先鋒自然資源 (PXD) 2015 Q3 法說會逐字稿

Welcome to the 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; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations. Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com.

At the website, select investors, then select earnings and webcasts. This call is being recorded. A replay of the call will be archived on the Internet site through November 28.

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.

Thank you, Destiny. Good day, everyone, and thank you for joining us. I'm going to briefly at review the agenda for today's call. Scott is going to be up first; he will provide the financial and operating highlights for the third quarter of 2015, a great quarter for Pioneer, especially when you recognize the current low commodity price environment that we're operating under. He'll then discuss our latest outlook for the remainder of 2015 and provide some comments on the three years that follow.

After Scott concludes his remarks, Tim will review our third-quarter horizontal drilling results in the Spraberry/Wolfcamp and the Eagle Ford Shale. He'll also provide details regarding the latest plans for our Spraberry/Wolfcamp infrastructure projects.

Rich will then cover the third-quarter financials in more detail, and provide earnings guidance for the fourth quarter. After Rich concludes his remarks, we'll be glad to take your questions.

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

Thanks, Frank. Good morning. On slide number 3, we had an adjusted loss of $1 million or $0.01 per diluted share for the third quarter. What's more important, obviously, we had a tremendous quarter in regard to production growth. Third-quarter production, 211,000 barrels of oil equivalent per day, 52% oil. It was 7% above the second quarter, and above the top end of guidance of 205,000 to 210,000 for the quarter, obviously driven by the strong Spraberry/Wolfcamp horizontal drilling program. That production was up 15,000 barrels of oil equivalent per day or 13% versus the second quarter. The oil production actually increased 10,000 barrels of oil per day.

What's probably more important is the fact that this growth is coming from only six rigs in the north, and a net 2.4 rigs in the South, so really only 8.5 rigs coming out of the Permian Basin. You'll see later, as we've discussed, the additional eight rigs of that we've added, you'll see that growth coming on late first quarter, going into a tremendous strong second quarter of 2016.

Updating 2015 full-year production growth forecast to 11% from our 10%-plus. If you look at the Spraberry/Wolfcamp full-year growth rate, it was 22% to 24%. We're upping that to 25% to 26%. Continue realizing tremendous cost reductions and efficiency gains. Achieving already 25% decrease in drilling and completion costs compared to 2014. Expected to get greater than 30% going into 2016. 20% reduction in horizontal tank battery costs compared to 2014; expect that to be greater than 25% going into 2016. Continue to see reduction in LOE, 18% reduction already compared to the third quarter of 2015 compared to 2014.

Continuing to see that with efficiency gains -- continuing to see our horizontal pad spud-to-POP times reduced to 135 days. A lot of it is reflecting the reduced drilling time by seven days per well.

Going to slide number 4, we did place 33 horizontal wells on production in the third quarter in the north in the Spraberry/Wolfcamp. Continuing to see tremendous results from the Wolfcamp B and Wolfcamp A intervals. 30 wells; they're all, on average, tracking greater than 15% above a 1 million BOE type curve. We'll evaluate increasing that sometime next year. Average 24-hour peak rate for the 30 wells, 1,900 barrels of oil equivalent per day, with 78% oil content. 19 of the 30 wells benefited from completion optimization, which Tim will talk more about; 17 Wolfcamp B wells and two Wolfcamp A wells.

Again, the average production from all the Wolfcamp B and A wells drilled since 2013. In the north, continued to track EURs of 1 million barrel of oil equivalent. We did close the sale of our Eagle Ford midstream business in July for $2.15 billion gross or $1 billion net to Pioneer. Receipt and net sales proceeds of $530 million at closing. An additional $500 million will be received in July of 2016; resulted in a book gain of $778 million before tax, or a 7 time return on investment in five years. This is another great example of infrastructure spending that we do, unlike a lot of our peers, and turn it into a tremendous gain.

Strong balance sheet, with cash on hand at $600 million at the end of the third quarter of 2015.

Again, we probably have the strongest hedging position, when you look at the years 2015 and 2016, of anybody in the US. We were hedged 90% for 2015, 85% for 2016 on oil, and 20% for 2017. On Gas, 85% for 2015, 70% in 2016. When you look at what we've collected and what the current value of our entire hedge book is, it's about -- approximately $1.5 billion for the years 2015 and 2016.

Continue to forecast production growth of 15%-plus over the 2016 to 2018 time period. Oil growth of 20%-plus. Again, due to the efficiency gains and higher EURs in the Spraberry/Wolfcamp, we continue to expect to deliver forecasted growth using fewer rigs in the Spraberry/Wolfcamp than the 28 rigs we had previously anticipated and announced.

Eight rigs have been added in the north between July and late October. No further rig additions planned for 2015. Currently at 18 rigs, 14 in the north, and four rigs in the south. Obviously the timing of future additions over this next three-year time period dependent upon the incrementally efficiency gains, further productivity improvements, obviously commodity prices, while we're continuing to achieve strong well returns.

The current IRRs in the Spraberry/Wolfcamp range from 45% to 60% at current strip prices, as noted in footnote 1 at the bottom of your slide. Operating -- continue to operate six horizontal rigs in the Eagle Ford. With six horizontal rigs and our modeling over the next three-year time period, we expect to keep production essentially flat versus the third quarter of 2015.

On slide number 6, our capital program continues to stay at $2.2 billion. That includes the eight additional rigs we've added in the second half of 2015. Drilling capital, still the same, at $1.95 billion. And again, funding primarily through cash flow of $1.5 billion; cash on hand, $600 million at the end of September; and in addition with our great hedging program in 2015.

Going into slide number 7, forecasting targeting 15%-plus production growth over the next three-year time period, 2016 through 2018. Summarizing 2015, we'll end up averaging somewhere between 202,000, 203,000 barrels a day. A key footnote going into the fourth quarter, with our guidance at 206,000 to 211,000, we will have one-third fewer POPs in Spraberry/Wolfcamp and the Eagle Ford compared to the third quarter. That's why guidance is essentially flattish going into the fourth quarter.

I'll remind you, you'll see the major impact of the additional 8 rigs, late first quarter of next year, and going into the second quarter of 2016.

Looking long-term, 2016 to 2018 reflects increasing well productivity, capital efficiency improvements, strong rail returns, and increasing horizontal rig count. We'll be moving up to about 60% oil by 2018. Oil growth will be 20%-plus in that three-year time period.

I will now turn it over to Tim to get more specific on our horizontal results.

Thanks, Scott. I'll start with slide 8, and it shows that the third quarter continued our track record of excellent results in the drilling and completing of Spraberry/Wolfcamp wells. And toward that end, as Scott has already mentioned, we put 33 wells on production, horizontal wells. The predominant number, of course, is the Wolfcamp B, with 28 of those 33, with two Wolfcamp A wells.

It should be noted that according to our plan, these A wells were drilled after some delay from when the corresponding B wells were drilled; and this will be our plan, still, going forward. As you can see on the graphs, in both cases the production results are quite outstanding, and we're estimate that the early production is tracking over 15% above our 1 million barrel BOE type curve, which is simply outstanding.

We did put a couple other zone's wells on production, particularly two Wolfcamp D wells, which had excellent producing rates of about 1,600 barrels a day in the first 24 hours; and then a lower Spraberry Shale well that we still don't have any significant results for. The optimization program I think is contributing very mightily when it comes to the encouragement we see on production. 26 completion optimization wells were put on production over the last couple of quarters. And if you take a look at the 30 wells above, they clearly are being affected by that.

We've seen pretty significant increases across the board when it comes to completion optimization, when it comes to optimizing the stage lengths and reducing -- or increasing the number of clusters per stage, increasing fluid volumes and proppant.

And so, with the 26 wells among the total that had been put on production last two quarters have really seen significant increases. Actually, in one particular case, we have an offset well that is showing about a 34% increase in its EUR versus the offset well. So, it's clear that we need more work and more time for the optimization. And it's also clear that optimization won't be the same in every zone and every area of the field.

But it's very encouraging what we're seeing, to the point where we are actually expanding our optimization program. We'll be testing an additional 50 wells in the fourth quarter of this year, as well as into the first quarter of next year.

Turning to slide 9: as we've done for several quarters, the graphs on the left depict the actual production from all the wells that we've drilled in each of the Wolfcamp A and B intervals. And you can see on average -- in this case, we've got significant data sets for both -- these wells have averaged roughly about 1 million BOE in both the Wolfcamp A and the Wolfcamp B. If you take a look at the map on the right, we've got a substantial data set that is being developed with all these wells and across a large swath of the acreage.

As I mentioned, on slide 8, it's pretty clear that these drilling results on average are going to increase. Our averages will be pulled up by virtue of the increased EURs per well that we're seeing. And I think you'll see these curves move upward into the future.

On slide 10, the economics of drilling in this field still strongly support drilling longer laterals where we can do so. The table clearly shows that. It shows the cost incrementally of drilling longer laterals, and then the incremental amounts in terms of EURs. And the NPV per well dramatically increases from the case of a 5,000 foot lateral of about $2.3 million up to about $8 million for a 10,000 foot lateral. So, very significant improvement in the payout, and the NPV per well in doing so. As the graph at the bottom shows, it's pretty clear that the higher prices go, there's even a more significant NPV lift that we get from drilling longer laterals.

Our position in the basin is such that the vast majority of our acreage supports longer laterals, and that will allow us to drill, say, 7,500 to 10,000 foot laterals really for decades. As depicted in the cartoonish map here, you can see that if we only had one section by one section of 640 acres, that would limit us to only 5,000 foot laterals. But, in our case, we have contiguous acreage. In many cases, we have at least two sections stacked north and south, and we can drill up to 10,000 foot laterals.

And so we have a significant advantage, compared to peers, in that our substantial acreage position is contiguous, and allows for the drilling of long laterals.

On slide 11, even with the longer laterals, our drilling time per well has decreased substantially over the last several quarters, as seen in the graph. In fact, it was down seven days, from 32 to 25, in the third quarter compared to the second. This shows all wells drilled in the Wolfcamp B. You can see the dramatic benefits we get from focusing on one zone, and getting better and better at drilling that one zone to the point where our best wells to date in the north has been 17 days in terms of drilling, and in the south, 13 days. Given that that southern area well was much shorter lateral than in the north.

But the objective should be, as we move forward, to move the averages down even further to correspond to the best wells drilled to date. And I think you'll see that improvement continue as we go into the future. A lot of this has to do with utilizing a modified 3-string casing design, and, as I mentioned a minute ago, focusing on one particular zone, and this case being the Wolfcamp B predominantly.

And then turning to slide 12, this is an update on activity in the north. As Scott mentioned, we have 14 rigs running horizontally in the north, with no plans for additional new rigs in the north during this year. We will be actually POP'ing a number of wells that's actually larger than our original plan, even with adding only the eight rigs that we have since July 1. The average spud-to-POP times are coming down. This is in relation to the reduced drilling days I mentioned a moment ago. And I think that will continue as well. I think we're down to roughly 135 days in the north.

The cost per well has come down dramatically. This has already been mentioned, but about 25% is what we see as the cost reduction so far year-to-date in the north, bringing the well costs down to just over $8 million. And I think this can be reduced another 5% or so as we get into early next year, when we see the full effect of the reduction in tubulars as well as having some of our rigs that are under contract today be renegotiated at lower spot rates.

Our program still calls for us averaging 1 million BOE. It would generate IRRs at 50% to 60% in the north. That includes an allocation for tank batteries and saltwater disposal.

As I mentioned earlier, to the extent we are actually drilling EURs that are substantially above 1 million barrels it seems in the third quarter, then I think we can probably surpass these economics as we go forward, in large part due to the benefits from completion optimization.

If you look at the map at the right, we will be planning to POP about 110 wells this year; 76 have already been accomplished through the end of the third quarter. And most of these wells, as I mentioned earlier, will be focused on the Wolfcamp B, with decent number of Wolfcamp A and Lower Spraberry Shale wells in the mix.

On slide 13, this shows similar data for the Southern Wolfcamp area, where we have been drilling with four rigs, really which -- already this year. I'd say most of the statements I made for the north applied to the south as well, where the results look very, very good. We're seeing strong EURs and efficiency gains coming out of cost reductions. Costs down here are just over $7.5 million, owing to the fact that we're drilling in this area slightly shallower wells. And we'll see cost reductions, I think, further, just as we expect in the north, down to about 30% reduction compared to last year. [Think we can get them] down in the low 7s by the time the early part of 2016 comes around.

And IRRs down here being about 45%, slightly less productivity in the south compared to the north, and that results in the lower IRRs. But we'll POP about 85 wells down in the south; again, the majority being Wolfcamp B.

Turning to slide 14, the results of this outstanding drilling campaign is a phenomenal quarter in terms of production growth. Production grew here 15,000 barrels a day from the second quarter into the third quarter. That was as a result of POP'ing 52 wells, with 33 in the north and 19 in the south. Production was up about 13%, and significant increases, of course, in our oil production as well.

For the first time, interestingly, we've ever seen in the history of the Company, the horizontal production in this field has now surpassed vertical, as we're drilling very few vertical wells, and the vertical wells decline, expect horizontal to take over in a significant way going forward.

Scott mentioned the fact we're going to see a slight production decrease in the fourth quarter, flat to down slightly. This is just simply a matter of POP timing and the number of POPs. So we had a significant number of wells from our July and August campaign that we're just going to be POP'ing at the very end of the year. And as a result, they don't have much impact on the quarter. And the actual number of POPs in the quarter will be dropping to the extent of about 30% -- 20% to 30%, just with the timing of those POPs. So I think what you'll simply see is the POPs will increase, beginning going into the first and second quarter, and this is where you'll see the production bump.

Interestingly, the fact is, we're getting to these wells faster. And so what's happened is we've moved to some wells that were otherwise planned to be POP'd in the fourth quarter, those got done in the third quarter. So that's why you see very substantial growth in the third quarter, and a flattening in the fourth.

But, overall, the results are simply outstanding. We're growing this field 25% to 26%, which is higher than we had anticipated going into the year. So really outstanding results in the third quarter, and I anticipate that will be the case for the year as well.

On slide 15: of course, our objective when it comes to infrastructure is to optimize the buildout so that we can prepare for the future, but also within the constraints of today's commodity price outlook. So you'll see us, in some cases, trying to limit what we need to spend on infrastructure but also moving ahead on these projects.

So for instance, when it comes to tank batteries and saltwater disposal facilities, we're spending about $175 million this year. Expect about $200 million next year for those same expenditures, but realizing we'll be POP'ing probably about 20% more wells next year. The cost per well is actually coming down by about $50,000 to $75,000 per well to hook up those wells.

In gas processing, one thing you've seen, I think, is the robust nature of the Permian Basin production is really probably the foremost system when it comes to new oil wells and production in the United States, in light of the low commodity prices. And toward that end, we need to put our new Buffalo plant in place in the second quarter next year. We spent about $70 million preparing for that this year, and will spend another $50 million putting in on production in the second quarter. Again, just because these systems are filling up faster than we would have otherwise anticipated, as production continues to be robust in the Permian.

Our water distribution system will still require capital. We spent about $130 million this year for a combination of engineering and putting in place right-of-way for the new pipeline systems, laying some of that pipe, and connecting the Odessa water system as well as other water sources.

I think we'll spend a similar amount next year. It will be more focused on subsystems for moving water within our field, as well as developing frac ponds to store water, so we're ready to go in the campaign for drilling in the next few years. We still are moving ahead with the notion of buying the effluent water also from the City of Midland, and those discussions are proceeding well.

On the sand mine front, of course we spent about $75 million this year to prep for an expansion. I think that expansion is not something we really need this year or next year. It's probably going to be the latter part of the decade, as we determine we need more sand in terms of the demand from the rigs. And when we do so, the expansion will cost about $75 million.

And then, finally, turning to Eagle Ford Shale at slide 16, we put about 36 wells on production in the third quarter, a mixture of upper and lower targets. We've POP'd about 85 well so far, with 100 targeted for the year. And of course, third quarter production was down slightly. We've seen some well performance issues that really result from changes we made earlier this year. In the face of the need to reduce costs, we changed the completion techniques to reduce fluid concentration, as we had some evidence from some earlier wells that could actually work and cut costs. It turns out, as we look back, that probably had a negative effect on production.

It's masked simply because these wells, generally speaking on day one, are choked back. And so, accordingly, you don't really see much of an impact in terms of the production curves until later in the life, as the pressure comes off the well. And accordingly, we really didn't see this until about six months after this change was made. So we're going to be remediating the situation, as you might expect.

So commencing immediately, what we're doing is using higher fluid concentrations. We're also going to be pumping more proppant, shortening the stage lengths, and tightening the cluster spacing; really putting the hammer to this field to get it back online in the type of trajectory we would expect.

The plan still is to continue with the six rigs that we have running today. That's down from nine that we had last year. Six rigs, in effect, is the number of rigs to keep production essentially flat, I think, going forward. We'll have only about 15 POPs in the fourth quarter compared to 36 in the third. And the timing of that, of course, is reflected in the overall Company production forecast for the fourth quarter being flat or slightly down from the third quarter.

So with that, I'm going to pass it to Rich for a review of the third-quarter financials, and his outlook for the fourth quarter and for the rest of the year.

Great. Thanks, Tim. I'm going to start on slide 17, where we reported net income attributable to common stockholders of $646 million or $4.27 per diluted share. That did include mark-to-market derivative gains of $214 million after tax, or $1.42. In addition, it had the gain on the sale of Eagle Ford that Scott mentioned, $499 million after tax, or $3.29. And then $66 million or $0.45 of other -- charges that hit during the quarter, primarily related to the impairment of our South Texas Edwards gas field during the quarter. So adjusting for those items, we were at a $1 million loss or $0.01 per share.

Looking at the bottom of the slide where we show results for the quarter versus guidance, you can see that production was above the top end of the guidance that we talked about. All the other items going down that list were either within guidance or on the positive side of guidance. So won't spend much time on those, other than just to point out in addition to the cost reduction issues we've talked about on capital and LOE, we're also seeing our G&A costs per BOE come down. We're down to about $0.50 per BOE this quarter compared to the third quarter of last year, and same on a year-to-date basis.

Turning to slide 18, talked about price realizations; as obviously everybody knows, commodity prices were down for the quarter. Oil price realizations for Pioneer were down 18% in the third quarter compared to the second quarter; down 12% on NGLs between the quarters; and then offset slightly by a 7% increase in gas prices.

If you look at the bottom of the slide, the Company continues to benefit from our derivative portfolio, where we added about $20 per barrel to our oil prices because of our derivative position; about $1.28 on NGLs, and $0.87 per MCF on gas. When you aggregate those up, that's about $238 million of cash flow that we had during the quarter, or about $600 million for the year in total. And then our portfolio, as Scott mentioned, at the end of September, was worth $775 million at that point in time. So, continue to benefit strongly from our derivative position.

Turning to slide 19, looking at production costs. Production costs were up slightly for the quarter, about 4%. Most of that is what we talked about on our last earnings call, was coming from the third-party transportation costs going up about $0.75 to $1, as expected, due to the sale of our EFS midstream business. That was offset by taxes coming down with the lower commodity price environment. And then as you can see with the base LOE, you can see that we've continued to benefit from our cost reduction initiatives there, and we're down 18% relative to 2014 on base LOE. So, good progress on production costs in total for the quarter.

Turning to slide 20, looking at our liquidity position. The Company continues to maintain an excellent balance sheet, with $581 million of cash on hand, net debt of $2.1 billion at the end of the quarter. And our liquidity position still is excellent, with not only the cash on hand, but $1.5 billion unsecured credit facility that is completely undrawn. We did, during the quarter, extend its maturity out to August of 2020.

So overall, we continue to have a strong balance sheet. And as Scott mentioned, we have another $500 million coming in from the proceeds of our EFS midstream sale in July of 2016.

Switching gears, and talking on slide 21 about Q4 production guidance and other guidance items. Production, as Tim talked about, is flattish to slightly down, just given the decrease in POPs in the fourth quarter and just timing of POPs during the quarter. You'll see our production cost, we've adjusted that guidance down to $11 to $13, down from prior quarters, just reflecting the Company's cost saving initiatives that are ongoing.

Probably the couple of items worth noting is DD&A guidance is slightly higher, just reflecting that we'll have another quarter of lower commodity prices. And since we use the trailing 12-month average, we do expect to lose some end-of-life reserves on producing wells, causing our DD&A to slightly increase.

Other expense of $40 million to $50 million does include $18 million to $20 million of stacked rig charges, down as we put more rigs back to work from $22 million that we saw in Q3. And then current income taxes are $10 million to $20 million, really reflecting that we'll recognize in the fourth quarter the last portion of our AMT tax associated with our EFS midstream sale.

So with that, I'll probably stop there, turn it over to you, Destiny, for questions.

(Operator Instructions). John Freeman, Raymond James.

Great quarter. The first question, when I'm looking at the longer-term guidance where you're maintaining a prior growth rate, despite the less rigs -- is the way to think about it, or the way that you all are looking at it right now is -- you know you are going to need less rigs than the 28 you previously guided to. But the efficiency gains are happening so quickly. The type curve -- production relative into type curve keeps improving. It's just, you don't quite yet know what that rig count is. You just know it's less; and at some point early next year, we'll get some more color on that.

That's exactly -- John, you're reading it exactly right. It's taking a lot less rigs between July 1, 2015, and into March of 2016 then we thought. And we'll give out more details as we get into next year's budget. But really, I don't see current prices staying where they're at, but if current prices stay where they're at, even under that scenario, we would add only 2 to 3 rigs per year over the next three years. So, with increased efficiencies, getting much higher type curves, we're seeing tremendous -- it's going to be much easier to hit that 15% target.

Okay, great. And then just my one follow-up: when I think about through the mix of the wells next year, if we just look at the north, where you've got 80% Wolfcamp B, 10% A, 10% Lower Spraberry. Should I expect the mix in 2016 to be similar? I know you are encouraged by the Lower Spraberry, but also don't want to lose any of the progress on the efficiency front. So just maybe how to think about that.

Yes, John. I think the way to think about it is you'll see that we probably have a larger number, on a percentage basis, of As and Lower Spraberry Shales next year than we did this year. We haven't established the exact percentages yet, but you're not going to see a year where we drill 80% to 90% Bs next year, because we do need to make progress on As and Lower Spraberry Shales as well. We'll get back to you as soon as we pencil in the exact numbers. But I would say a substantially bigger percentage of As and Lower Spraberry Shales.

Great. Thanks, guys. Congrats again on a great quarter.

Charles Meade, Johnson Rice.

If I could just press a little bit further on how you are thinking about the rig adds in different scenarios. And I recognize that you guys have a lot of flexibility, in that you don't have to make that decision now. But you laid out a few scenarios or a few conditions on slide 5, saying that incremental efficiency gains, further productivity improvements, and well returns are really what you're looking for to add rigs.

But am I looking at it right, that you really want to see more productivity gains from here in order to add rigs? Or going back to your earlier comments, is it just with the current course and speed on both your operations side and on the commodity price side, that's sufficient to get 2 to 3 rigs a year? How should we think about the scenarios there?

First of all, we're being very conservative on these efficiency gains and well productivity. We're not modeling in the results we saw from this past quarter, where we're getting greater than 15% above 1 million barrel type curves. You've got to realize, the longer we see those wells continue to perform, the longer we see these efficiency gains stay and improve. We will eventually model that in. And over time, we continue to think we'll need less rigs than we're even saying now. So that's what we're saying, primarily.

And as long as we're getting -- the key driver to all this is getting strong returns, number one. And I think all prices have bottomed. They may stay in the $45, $46, $47 range for a while. But we're collecting, as you remember on our hedges, $20 plus the current price, so -- on all of our hedges next year. So we're just way above the peers in regard to our hedge position. But we think it's so important to continue to grow as long as the returns are great. So, as we see these gains occur, we'll model those in. And we think we could even need less rigs than we're even showing today.

Thank you, Scott. That's helpful. And perhaps picking up on one of your themes there, if I could ask about your most recent batch of these 30 wells that you brought on that are showing that 15% above the type curve. One of the things I noticed on that is the lateral lengths on these wells are more like -- they are averaging, call it, 8,500 feet.

So I suppose the question is, number one, is that what we should look for in your 2016 program, is lateral lengths of 8,500 feet? Or perhaps is it even going higher?

And the other question -- and this may be torturing the data a little bit too much -- but Tim, in your prepared comments, you talked about how you put those two A wells -- I recognize there are just two of them, but you mentioned about how you let some time elapse after drilling the Bs on the same pad. And so I was wondering if you could maybe -- if you have the data, compare how those A wells are doing with this completion [opposition] to the B wells on the same pad.

First of all, on your first question, Charles, I think as we move forward -- of course our land team has done a phenomenal job working to put even further adjacent acreage next to our existing acreage, to the point where I think our current planning would suggest 9,500 foot laterals in general, on average, in both the north and the south next year. And I made the case, as you remember, that that's a substantial value-adder, even compared to the 8,500 or 8,600 that we're dealing with this year so far -- or in the quarter. So it's going to be a dramatic increase.

What I would say about the As is, we have systematically decided to wait on As after the B campaign. And now you're seeing us coming back to As -- is what I mentioned to John's question -- that the A campaign will increase simply because we're ready for it, having drilled the Bs that correspond. And so, what we'll say is that we have limited sample size of optimized As. That's the two wells that we already mentioned. But they look great, of course, but we're going to need a bigger sample size. But so far, if that's what we're looking at, we're looking at wells in the sense of the As that correspond well to the Bs, and produce similarly.

Thank you, Tim.

David Kistler, Simmons and Company.

Real quickly, with respect to these longer laterals, I know you outlined decades of inventory? But what percent of your portfolio would you say is applicable to longer laterals, based on the Block E acreage?

Well, if you take a look at the statistics, it's pretty mind-boggling. I think about 75% of our acreage would be 7,500 feet or more. And there's quite a substantial -- I think over 50% would be 10,000 foot laterals, so it's -- I don't have the exact number, but those are round numbers for you that are pretty close.

Okay, I appreciate that. And then when you think about the infrastructure that you've currently designed, do you have to add some increased infrastructure to handle these longer laterals, given the productivity increase? Just any kind of color around that, or is that plan already factored in, at this juncture?

I think it's essentially factored in. You're talking about incremental volumes in terms of produced water, in terms of oil. We're already planning for incremental volumes. And as you know, as you've worked with us on our tank barrier designs, they're typically set up for 60 wells. So we have got plenty of capacity. I think the fact is, these are already built for much higher volumes than we ever dealt with, when it came to vertical wells.

Okay. And then just last one, when you think about that 15% guidance through 2018 and capital outlines, do you think about the D&C cost -- is that capturing these longer laterals? And is in capturing the uplift in production in the current guidance? Or could we see what you're targeting for the start of 2016, those well costs being a little bit more, but obviously productivity being more?

I think you hit the nail on the head there. We're in a situation where we will have incremental costs that come from lengthening laterals on a percentage basis, and, as I mentioned, probably going to 9,500 compared to 8,700 or 8,600. But that's far more than offset by the fact that the incremental production from that will yield a result we think which significantly enhances the returns. That said, everything we have built in today is using, still, the 1 million barrel type curve results. So we haven't built in anything over that, so that's a significant adder.

We're just now getting our arms around, as you can tell, the impact of reducing days on wells, and the optimization effect of that in terms of needing less rigs to drill the same number of wells. That's what is leading us to the conclusion that we don't need to add any more rigs here during the latter part of this year to achieve the similar results that we thought we were going to need more rigs earlier on.

So, I think as you look forward, we'll be beginning, through time, to add into our modeling -- as Scott has already referred to -- some of these benefits we're seeing. But we're not adding all of those benefits in yet.

Okay. Appreciate that color, guys. Great work.

Doug Leggate, Bank of America.

Tim and Scott, I wonder if I could just pick up on a couple of the questions that have been asked so far. On the 15% growth target, just to be clear, what are you assuming is your standard well design to get to that number? I'm just trying to figure out, is that an outcome, or is that the target? Because there's obviously a lot of flexibility as to how you get there. But in terms of type curve and lateral lengths, what are you assuming in that 15% target?

So far, what we're assuming is type curves that are roughly the 1 million barrel type curves, Doug. And when you take a look at the lateral lengths, it's going to correspond -- that will correspond to typical 8,500 foot laterals. To the extent we're at 9,500 it would be type curve slightly higher than that, so it might be 1.1 million BOE or something like that for a 10,000 footer or a 9,000 footer. I think you have to look at this and say, that will be built in, but all of the efficiency gains would not be.

Tim, in the event, then, that -- let's assume that the type curve, as you pointed out, you might revisit that next year. Let's assume it comes in better and the laterals end up in longer. Do you adjust your activity level down to cap your growth at 15%? Or how do you respond if that turns out to be the case?

Well, the first thing we're focused on, as Scott has already mentioned, is the returns. Let's go on the basis of that returns are strong. We would take a look at the combination of levers we have, and make a decision about that going forward. As you can tell, we are focused on trying to maintain a CAGR growth rate that makes sense in the face of those returns. But we can land our growth rate essentially on any number we want to, depending on how much money we spend. We can spend less money if we have these efficiencies and achieve the same results.

So, this is going to be, I would say, kind of a moving target. We have a goal set at the 15% plus CAGR rate. We could exceed that if we choose. If we were in a lousy commodity price environment, we could come in under that if we wanted to. It's more or less a general target. And it will be adjusted to the extent the number of dollars needed to be spent would be substantially lower, to the extent these efficiencies and productivity numbers continue.

I know it's an unfair question, Tim, but I guess you've drawn that out by your comment there. Why is 15% the right number, when oil is $45?

Well, I don't know that 15% is the right number or the wrong number. It's just a target we have internally for the type of growth rate we think we can achieve when the economics are as strong as they are.

Okay. My last one is picking up on your comment about the Wolfcamp As. So I just want to try and understand, is this going back to existing pads? Or when you think about going back to -- if you skew it towards the As next year? And if so, what are the implications for infrastructure spending? And I'll leave it there, thanks.

In principle, a lot of these As are following localized Bs, as I mentioned. Because we believe the right thing to do is come back to the As from the standpoint of our modeling. You still have some areas where will be obviously building new pads. On a per-well connection basis, I mentioned it will be less next year. We still have other areas, I said, that we're drilling B wells that are going to need new infrastructure as well.

So yes, I think the areas where you come back to existing pads, you're obviously not going to need as much capital, but we're still building new pads as we speak.

And a lot of that population next year, then, is it fair to assume that [time] batteries and so on are already in place?

Yes, for some of the campaign, they certainly are. For others, they are not.

All right. I'll leave it there. Thanks, guys.

And Doug, one last item, on the $45, you got to realize we do not believe that we're going to have $45 flat for the next three years. So, we're targeting 15% growth over the next three years on the strip price case. And I don't think anybody here thinks we're going to be $45 for the next three years. If we did, we would not be targeting a 15% growth rate, let me say that.

I would embellish that by saying, we're looking at margins, Doug, not the commodity price, per se. We're looking at what our economics are, pursuant to the margins.

Brian Singer, Goldman Sachs.

Wanted to focus first on production mix. Can you talk to how we should look at the path to moving to your 60% oil objective? And specifically within the Permian, we haven't really seen that much movement here in the last few quarters -- increases, that is -- despite now multi-quarter focus on horizontal drilling. What is the right percent oil in the Permian, and the timing and catalysts to get there?

Yes Brian, as you saw, the well mix was 78% oil. As we add more Lower Spraberry Shales, they are up in the 80s. You look at our peers, they are up in the 80%, 85% range. So it's a combination of the -- what we're seeing the mix of Wolfcamp B, Wolfcamp As in the lower Spraberry shales. So it's a slow movement from 52% to 60%, but it's what we're seeing in the model.

As we add the results from the eight additional rigs that you're starting to see in the late first quarter and second quarter next year, you'll see that mix even increase even more so, going into second half of next year.

Brian, the other thing you're seeing, too, is you're seeing improved gas recoveries and NGL recoveries. Now that Targa has taken over and optimized the systems out there, they've made a lot of improvements. So we're getting better gas recoveries than we were getting before, which affects this year.

Yes, affects this year in particular.

And that would also possibly impact, then, reserves' EURs recovery rate? Or is that not the case?

Yes, it does, in a sense. Because you're holding -- the lines that we're putting in place are increasing the size of the lines, so it allows you to get more recoveries over time.

Okay, great. And then a bit of the follow-up to some of Doug's questions earlier. On your capital budget and growth plans, how does the oil price environment play into the equation when you talked about 2016? You're very well hedged, strong balance sheet. You talked about having flexibility to change that growth rate around, and the rig count around, depending on whether you have bad oil prices versus good oil prices.

What is it that governs your decision on whether to increase the drilling and completion cadence in 2016, versus stay flat at your year-end 2015 levels?

We haven't really changed our plans in 2015. Just to remind you, we've seen $38 once; we saw $42; we saw two lows. But as long as Goldman keeps putting -- if you all stop putting out $20 stuff, it would help. (laughter) But hopefully that we do not see $20, but I think we're at a bottom. And if oil prices are going to move up, second half of 2016, and we'll be $60 in 2017 or higher, you'll see us add more rigs if we see that event happen.

But remember, if for some reason we do go to $20, in that scenario we get $20 plus, so we're only collecting $40. And if it stays at $20, we're obviously going to cut back rigs. But if it stays like it has in 2015, I do not see making any changes in 2016.

Just to follow up, then, is it a balance sheet constraint, where you are trying to get to a net debt to EBITDA type number? Is it a CapEx/cash flow balance? What is it that you look at to say, we should increase the rig count versus not?

We have a tremendous inventory. Our number-one driver is returns; second driver is bringing NAV forward. So, those are the two drivers. It's important for us. We have so many locations. Some people ask, are you depleting your inventory in this price environment? The answer is no. It's miniscule. And when you have a 100-year inventory, it's important to bring your NAV forward. The best way to do it is put rigs to work. The economics are good. That's the key driver. I don't think you're going to see us change in regard to what we've laid out for 2016, at this point in time.

Great. Thank you very much.

Stephen Richardson, Evercore.

I was wondering if you could talk a little bit about acknowledging that you're just getting a lot of these efficiency gains -- longer laterals, lower costs -- and the implications of fewer rigs and fewer wells, and the 15% uplift on the EURs.

But how is this implicating your view on cash neutrality and the timing at which you think the program can reach CapEx cash flow, acknowledging a balance, acknowledging a normalized oil price at some reasonable level? Is that part of this calculus, and is that point coming forward in time as you look at your corporate modeling?

Well, I think with us, or with the industry in general, we have all -- when you look at -- we have all overspent cash flow. But it's been done -- a lot of us have done it with asset divestitures in the past. We've done it with joint ventures. We've done it with equity. We've done it with higher debt levels. Certain companies have done it too high a debt levels, obviously, in this environment. And so, in a reasonable price environment, I think most people predict that we'll be back in a $60 to $80 price environment. Under that price environment, we will get to neutrality. Whether it's $60 or $70 depends on what happens to the service costs and efficiency gains.

We see actually getting to a point to where we'll be expanding cash flow and growing substantially. I can't tell you what that is without several other factors and making assumptions.

But Scott, fair to assume that better wells, fewer wells to get to the 15% CAGR, and efficiencies you are seeing across the program, that every one of those contributes to bringing forward that point in time, acknowledging that commodity price is important.

Exactly.

Okay. And I guess that segues well into the second question, which is clearly the equity window has been open for you and some of the peer companies, particularly in the basin. How do you think about -- acknowledging you've got the other $500 million from the Eagle Ford sale coming next year -- but how do you think about equity and your prioritization of funding the next couple of years, as you look out?

Yes, if you look at our growth rate and look at our balance sheet and our $500 million of capital -- I mean, of cash flow coming in from Enterprise -- and look at our hedge book, at this point in time we see no need -- like some of the other companies have gone out to the marketplace; those other companies that have done it recently, their balance sheets were more stretched. They did not want to take any risk at this current time. We see no reason to do anything at this point in time.

Great. Thank you very much.

Evan Calio, Morgan Stanley.

Very good operational results today. My first question is really a follow-up on some of these prior questions on the lower rig count. And hopefully not beating a dead horse here, but are efficiency gains in well performance since just June when you raised that guidance, the primary change to drive a different rig count outlook to deliver your growth profile? Or is it more moderating your activity through the trough due to commodity considerations?

I think if you look at the data that we've provided -- Evan, this is Tim -- you can see that we've been staring at these efficiency gains for some time, and particularly if you look at slide 11, where we show the number of days on wells coming down. But the dramatic reductions we've seen really have been in the last two quarters. We've moved, if you look back at the slide, from 37 days to 25 days. That's pretty dramatic improvement right there. And so we start seeing that and we realize, wow, we really don't need as many rigs to be operating to achieve the same sort of results. And that's a linchpin, I think, on the one hand.

On the other hand, we're seeing these dramatic improvements in productivity gains per well, and cost savings as well. So, we basically can spend less dollars, have less activity, and get you the same answer. I think it's really dawned on us really over the last couple of quarters, as we've seen the confluence of all those factors. And that's led us to where we are landing the rig count today.

Great. That's very clear. My second question is somewhat related, but a question on the completion designs in the quarter. Almost 60% of the Permian completions were optimized with very strong results.

Can you discuss maybe the primary variable that's changing, such as stage spacing or stage size? And any indications that you've reached limits of optimal, or could we see this go for a continued rate of change into 2016? That's not just from more wells being optimized, as per your guidance, yet from a continued improvement of what optimized means.

Yes. I think, first of all, when we're talking about optimization, optimization is going to be a long-term project around here. Because not every optimization concept will apply to each zone; and nor will it over long areas, wide areas, aerial extent of the field. But you're right; the concepts come in the form of several. One is just pump more volumes in terms of proppant, and the same would be true of fluid volumes.

And, importantly, I think changing the stage lengths, reducing the stage lengths, and increasing the clusters per stage, we think is important as well.

What I can tell you is we're testing all these different parameters in different wells. So we're a long ways from being able to say, man, here's the concoction that makes the most sense across the old field -- let's say, for example, the Wolfcamp B -- because we're just in the early stages of testing, one-off, all these different concepts.

You have to use a scientific method here, where you statistically look at offset wells that were not completed with the new style, versus the results from those that are completed with new techniques, and then coming to a conclusion about what sort of net improvement you're looking at.

I would say we're early days. I think we'll be continually improving. We'll be continually optimizing, and it's going to take a long time before we can say that this is definitive in certain areas that this is the way to do it. I think if you look at -- the perfect example is we haven't done any optimizations on Lower Spraberry Shale wells, zero. So we're not even started there yet, and we've done it on two Wolfcamp A wells out of the whole mix. So we just have a lot more work to be done. But that's our job, is to basically continually to improve and to optimize.

And that process is incremental, going incrementally tighter in different wells? For instance, on stage spacing, versus actually stepping to test a real theoretical limit. Is that accurate?

Well, I think if you -- there's only a certain distance you can shrink down to in terms of the distances between clusters. We're testing a pretty tight cluster space right now, which is I think about 60 feet between the clusters.

You also realize the more stages, the more clusters you have, the more you are actually having to increase your cost of completions. Because you're in there, if we're using a plug-and-perf method, we're drilling out more plugs, we're on the well a little bit longer from a completion standpoint. And with that comes some risks also. So it's not just a situation where you can just drill an unlimited number and get down to essentially where the whole zone is fracked with clusters.

But I can see us moving down in some of our testing, even to 30 feet cluster spacing. So we're doing that as well. It's really a combination of all those things, to try to basically improve.

Very helpful, guys. Thank you.

Michael Hall, Heikkinen Energy.

Congrats again on a good update. I just wanted to dive in a little bit more on the efficiencies and the commentary around spud to POP, and how that relates to the pace of completions we've seen here in the second half of 2015.

If I'm doing the math right, 135 days spud-to-POP implies maybe 115 POPs on a 14-rig program for 2016 in the north. But you're completing, call it, 33, 34 POPs per quarter here in the third and fourth quarter in the north. So if I run that out through 2016, I have over 130 completions. Just trying to understand how to think about completions pace per quarter, and what sort of additional efficiencies might be potentially expected, relative to the 135 spud-to-POP.

Well, I think the way to think about this -- and here, I think of it in the totality of the Permian Basin. This year, we're going to POP about 195 wells. I think, along the lines of your math, I think our estimates would say us getting to 240 wells next year. So your pace goes up roughly to the tune of 20%. If we were out there POP'ing, let's just say on average, 40, 50 wells per quarter, that goes out to maybe 60 or something like that. I think that's what you're going to see.

But realizing -- first of all, we just to reduced the amount of time when it comes to spud-to-POP by about 30 days. But even at 135 days, those wells that we began drilling in July and August are just now, at the end of the year, going to be POP'd in the sense of a three-well pad. So you still have 4 1/2, 5 months between when you start up and when you're done.

Okay. So, that's helpful. 240 wells, give or take.

North and south.

Okay.

I think our math would say 175 in the north, roughly. The balance in the south.

And that's on a flat 18-rig program?

Yes, that's the current campaign.

Pretty much, yes.

Okay. Good, helpful. And then I was just trying to think about also then the organizational readiness for that continued ramp-up. You're getting to pretty high quarterly POP rates. How are you all staffed on that front? Are you fully built out on -- you feel comfortable with that? Or is there any additional adds that are needed in that context?

Well, you may remember, in the mid-part of 2014, we were running 26, I believe it was, horizontal rigs in the Company.

Yes.

Today we're not even to that number, even with the additions we've made this summer.

Still plenty of room?

Yes, so we're not even back to our -- where we were, what's now a year and a half ago, in terms of total rig count, and therefore POPs. So, we have an organization that's ready to perform at a high level at this rate.

Great. And then just shift over to the Eagle Ford a little bit. I appreciate there's quite a bit of uncertainty around that program following the light quarter. But running a six rig program, kind of old type curves, seems like it's reasonably conservative to suggest it would stay flat at 43 Mboe a day. I'm just trying to understand what you have baked in on that sort of commentary around go forward type curves, relative to recent experience.

If you look at the type curves we utilize out there, they generally range, let's say, from 1.1 million to 1.3 million BOE. And that's -- we would say maybe 1.3 million historically. If we shave that down just based on recent results, you might use 1.1 million in the range. But maybe down 10%, 15%. If you look at the math on that and look at the returns, first of all, are quite good, even at that kind of EUR.

But the second thing is, if you take a look at how that -- if we're using six rigs, and play it out from the standpoint of three-well pads, you can see easily we can keep production basically flat. By flat, I mean it could be 1% up, 1% down, or a couple percent up or down; essentially flat, if you do the math on that.

Okay, fair enough. And actually if I might jump back to the middle of [midstream] real quick, what do you have the northern program horizontal wells? What were they booked at, at year-end 2014 on proved reserves?

Are you talking about new well bookings from a proved reserves standpoint?

Yes.

First of all, there would be an averaging concept associated with that. But the way to think about it is we're conservative about our bookings, especially in the first year. And so it's not unusual for us to be booking what we think is 50% or 60% of the EURs of the wells in year one. Just because the objective is to be moving, in terms of revisions, upward versus downward. And so you'll see potentially positive technical revisions moving forward in that field, if that's our philosophy.

Okay. That's helpful. And then last, on my end, is just on the infrastructure spend. You guys -- I think this year, you've got in the northern program $275 million for infrastructure and land; talked about a $25 million incremental spend on some component of the infrastructure. Any other incremental increases on that line item that we ought to bear in mind as we think about building out 2016?

I think there's always moving parts. But I think we've covered most of those on the slide number 15. Like, for example, this year and last year, we did a lot more in terms of buildings, which essentially we're done with our buildings. This is mostly field buildings, of course. So that's a number coming down. Of course, we're spending a similar amount when it comes to our water systems and gas processing. But when you tally everything up, most of the numbers are there, included on slide 15.

Great. That's helpful. Appreciate it.

Leo Mariani, RBC Capital.

Wanted to focus a little bit on the Eagle Ford here. It sounds like you guys have got six rigs out there, and you're indicating production can stay flat over the next handful of years at that same level. Just trying to get a sense if that's more of a theoretical statement. Or if we do see oil prices recover, whether or not you guys would go and add rigs there. And obviously I recognize competing for capital against the Permian.

The returns have always been good. We had nine rigs running out there last year. So yes, in a higher commodity price environment, Eagle Ford would definitely be a place we'd look to add capital. Because it does compete very favorably with the Permian, from the standpoint of very prolific wells and very high rates of production in the early stages of the wells.

That said, what's hurting the Eagle Ford today is the fact that we still produce a decent amount of gas with these wells, and a decent amount of NGLs, particularly ethane. And so, with ethane economics and natural gas prices having been where they've been, you can see that it's taking a little bit on the chin. So at the margin it's still very positive, but it has a running room to the extent we get higher commodity prices.

That's helpful. And obviously good performance update in terms of the well results in the Wolfcamp here, and the northern Midland Basin. Just wanted to get you all's thoughts on what you're seeing in terms of some longer-term production performance from the Lower Spraberry. You obviously mentioned you want to increase percentage exposure there next year.

Yes, Lower Spraberry Shale still is really one of our most prolific zones. As you can see, we're not drilling very many wells in the Lower Spraberry Shale as we speak, or POP'ing them. You'll see a higher percentage next year. But Lower Spraberry Shale calculates to have the most oil in place of any of the shales. It's also shallower. It will take a bigger place in the campaign.

Of course, this year, we've been focused on efficiencies and cost reductions. And so we're focused on the zone that we've drilled the most wells in; so, by definition, that's the Wolfcamp B. Next year, we'll be drilling some more Lower Spraberry Shales in significantly higher numbers.

Okay. And the last question on the rig charges here, obviously that's been happening for the last couple quarters. You are forecasting some more stacked rig charges in the fourth quarter. Just trying to get a sense of when those start to go away, if that's in the first half of 2016. Or what can you tell us about that?

That's generally in the first half of 2016, you're correct.

All right. Thanks, guys.

Neal Dingmann, SunTrust.

Just two things. Scott, I know you've hit a lot of things today. I really wanted to just get more on your comment about bringing the NAV forward. In this environment today, versus if we were -- I agree with you; if we do hit that $65, $70 type environment -- how do you think about bringing that forward? To me, it seems like you're maybe not getting credit for all the different benches anyway, so I like what you're doing with the Bs.

So I'd just like to hear your comment about what you guys think, either you or Tim, best way to bring the NAV forward, either in today's environment or if we have -- where we go to maybe a $65, $70 environment.

Yes, Neil. Obviously in a higher price environment, the first thing we'll do is add more rigs. That's the best way to bring it forward. And also, as we've been out there talking with shareholders and potential shareholders, Tim and I and Frank have been very open that we'll always look at evaluating acreage opportunities. We've done that before already in the Permian Basin, whether it's joint ventures or whether it's them selling acreage, as we did up in the far north of the Midland Basin. We will continue to evaluate opportunities like that, too, as a funding mechanism, by bringing NAV forward also.

Yes, that makes sense. And just lastly on that point, I know you guys are not actively looking to sell anything today, nor obviously with inventory position you have, certainly don't need to buy anything. But just have you seen anything with the M&A environment? It seems like prices really never did dip much, and we've seen a lot of excellent prices, I guess nothing too recent. Just anything you could comment about M&A activity around either your north or south there.

Yes, I think most of it's been in the north. There's been probably about 4 to 5 deals in the $30,000 to $40,000 per acre range. I think the recent two deals, everybody saw in the Wall Street Journal, a Chinese company came in and spent $1.3 billion. It was not state-owned. So private company, Chinese company, came in and paid a high price, in the $30,000 to $40,000 per acre. The rest of it has been by companies, smaller companies that are trading at high multiple. They can go to the equity markets and deleverage.

There's been about five deals, I think, so far this year in that $30,000 to $40,000 per acre, which shows it's still the most favored basin in the US, the Midland Basin.

I agree with you. And again, guys, thanks for all the color today.

And now I'd like to turn the call back over to Scott Sheffield for closing remarks.

Again, I thank everybody for participating. Great questions. Looking forward to another great quarter when we come out in February. Everybody have a great holiday and Happy New Year, if we don't see you on the road. Thanks.

This does conclude your teleconference for today. Thank you for your participation. You may disconnect at any time.