先鋒自然資源 (PXD) 2015 Q1 法說會逐字稿

Good day and welcome to the Pioneer Natural Resources first-quarter conference call. Joining us today will be 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 Webcast.

This call is being recorded. A replay of the call will be archived on the internet site through May 31.

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 new 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 Lexi. Good day everyone and thank you for joining us. As you probably realized from the operator's introduction, Scott will not be on the call today. He's actually traveling internationally, and unfortunately the logistics of his travel precluded him from calling in.

With that, I will briefly review the agenda for today's call. Tim's going to be up first. He's going to provide the financial and operating highlights for the first quarter, and he will update you on our latest plans for the remainder of the year.

He will then discuss the significant progress we are making to cut costs and become more efficient in response to the recent oil market downturn. This will be followed by an update of our 2015 drilling programs in the Spraberry, Wolfcamp and Eagle Ford shale.

After Tim concludes his remarks, Rich will cover the first-quarter financials in more detail and provide earnings guidance for the second quarter. And after that, we will open up the call for your questions. With that, I will turn the call over to Tim.

Thanks Frank and thank all of you all for being on the call. Pioneer did have a solid first quarter despite the fact that we were dealt a few blows in terms of winter weather at the outset of the year and the commencement of ethane rejection that we also were dealing with at the beginning of the year. And what we hope was the bottoming of oil prices during the quarter. But production was near the midpoint of our range, despite the decision to spread our POPs or Put on Production wells more evenly throughout the year so that we were confident we were optimizing the use of Pioneer Pumping Services, our own internal pumping services, for well completions.

And importantly as Frank has eluded to many times in our prior meetings, we made a great deal of progress in terms of cost reductions and efficiency gains. And when you couple that with recent improvements in spot oil prices, now this morning I see near $62 on a spot basis. We're getting more confident in our ability to add rigs beginning in the third quarter.

So some details on these points are on slides 3 and 4 in the financial and operating highlights. We did announce an adjusted net loss of $5 million or $0.03 per diluted share for the quarter.

Production as I mentioned was near the midpoint, 194,000 BOE per day. Again, we did lose some production due to the weather, and ethane rejection, for us it doesn't make sense to extract ethane at $0.18 a gallon.

The winter weather wasn't as bad as what it was in 2013, but we did have 3200 wells down including 90 horizontal wells. We didn't get them all back on production until the end of January.

We did make a decision not long after the last earnings call to move further towards utilization of Pioneer Pumping Services as our primary mover when it comes to completing wells. And that had the effect and we will talk more about it as we get into these slides of spreading the horizontal completions more evenly throughout the year.

We do have one of the most extensive derivative positions in the industry with about 90% of our oil volumes hedged for 2015, most of those protected at a $71 per barrel swap value. And as you look through the financials, you realize that result was about a $20 per barrel uplift in receipts in the first quarter for oil.

We have been active recently in adding some new three-way collars, about 10,000 barrels a day, this for 2016. It gives us protection below [$60] with upside to [$70] and above. Three-way collars with the downside protection but upside as well.

We anticipate that with any kind of drilling scenario we could foresee whether we're adding rigs or not, we're covered to the extent of about 70% to 80% in terms of our oil hedges and derivatives for 2016.

Derivative coverage for gas is about 90% for this year, again with principally three-ways. And those have given us a great deal of protection in today's gas market. Balance sheet remains very strong with about $400 million of cash on hand at the end of the quarter and net to book about 21%.

In terms of the EFF, Eagle Ford midstream sale, the process has taken a lot longer than expected due to the complexities of the contractual arrangements that really what it amounts to is moving from us providing our own services with our partner to contracting the same from a third-party. And the complications surround the idea of committing volumes and so on. We remain very optimistic that we will announce a sale of this business during this month, and the proceeds from which will substantially improve the balance sheet even further.

Continuing on highlights, slide 4, we already can point to about a 15% decrease in our drilling and completion capital so far this year compared to last year. And I think we're well on the way to have an over 20% reduction by the time we get to the end of the year, and I will talk more about that in some slides that follow. We also are doing a good job I feel like in utilizing new technologies and also just supplying current technologies to improve our efficiency gains when it comes to drilling and completions, and I also have a slide on that that follows.

On Monday we did announce the closing of our Denver office that will occur by the middle part of this year, and we will also be right sizing our operations in the Raton Basin to deal with the realities of today's natural gas prices. We're not drilling wells in the Raton. We have a lot of great people who worked for us for many years in Colorado, and this is a sad day for us to have to close this office, but it's the right thing to do from a cost perspective.

We have implemented as we discussed in the last call a high-graded horizontal drilling program that has the effect of drilling locations that we are confident have very strong returns even in this environment. The rig count at least for today remains the same, and it's the same as we announced early on, which is a total of 16 horizontal rigs, 10 being in the Permian and 6 in the Eagle Ford.

We've been successful in exporting condensate out of the Eagle Ford, about 7,000 barrels a day net in the first quarter. Substantial improvements in pricing. I think if you look at the way spot prices are for Eagle Ford condensate in the US, they may average $12 to $13 of WTI. We're easily halfway inside of that with the international exports. And so we can anticipate increasing those volumes, and I will talk more to that in a few slides.

We are also actively involved with moving volumes to the Gulf Coast where we think pricing will be -- and end markets will be advantageous. We currently have 15,000 barrels a day going down the Longhorn Pipeline, and the total volumes we will have exposed to Gulf Coast pricing will be about 50,000 barrels a day by the time we get into the third quarter as we will participate in volumes on both Cactus and Permian Express as they get cranked up here in the next few months.

We are continuing, and Scott has made a great deal of effort in benefits of lifting the export ban. I'm not going to go into that too much today. The current WTI Brent differential is about $7. In any way to think about it, the benefits are obvious to the American consumer, and the country for that matter from a geopolitical framework.

Let me now turn to an update for 2015. I mentioned this in the earlier commentary that we have spread what would have been first-quarter and second-quarter completions in the Permian Basin more evenly over the rest of 2015 to effectively use PPS.

We know that PPS is competitive. We know that indices and from other third-party market data that we obviously have access to, but the result of this is shifting about 25 of the 90 wells that we had planned for to be completed in the first half of this year or actually first quarter into the early second quarter to later in the year.

This is the result of utilizing PPS essentially 100% and eliminating third parties. This is a huge benefit to us because we know we're competitive on the one hand. Our utilization becomes very near 100%. Our costs are optimized between logistics and our personnel requirements. So this is the right thing for us to do from an economic standpoint.

The full-year POP count's not impacted. We're going to still POP the exact same number of wells. It's simply the fact that more will be POPed in the third and fourth quarter than we had originally planned, and that will still yield a forecast of full-year growth about 10% plus compared to 2014.

And as I mentioned at the outset, we still expect and feel confident now about adding two horizontal rigs per month in the Northern area of the Spraberry and Wolfcamp beginning in the third quarter. I think the oil prices have been positive, and we're certainly happy to see that. At the same time, we're in the midst as I said and hope to complete the Eagle Ford shale midstream sale shortly.

The impact to add two rigs per month beginning July of course will have very little impact on 2015 production. We're generally going to be using three-well pads, so this production would come on near the end of the year.

But it does have a big impact on 2016. It would allow us to get back into a growth mode in 2016 where we otherwise might not be if we did not add the rigs. The main message though is these wells are highly economic, and we believe the combination of our efficiency gains and cost savings put them where the margins are extremely strong.

So where we are today is that the balance sheet's very strong. We have a strong derivatives position, and what that gives us is the financial flexibility to ramp up drilling. And in this case on what still will be very high-return wells.

Turning to capital spending, this is slide 6. Our capital spending program remains essentially the same as it has been at a total program value of $1.85 billion. Of course, that does not include any potential rig adds that I just mentioned.

We will be dealing with that when we determine exactly how we proceed with those rig adds. But the numbers you see on the left-hand tables are precisely the same as they have been.

As you know, our other capital projects that are listed below, water and other projects such as processing facilities and so on, all of those projects have been substantially reduced, delayed or deferred in the current commodity price environment. Talk more about that in the slide that follows. The program will be funded of course by our operating cash flow and cash on hand going forward.

On slide 7, that level of spending will generate still a 10% plus production growth rate for this year. I'd call your attention to the right set of bars, which is a quarterly estimate of production, and particularly focus on the dashed boxes. Those are the original planned forecast that we had in the prior quarter, and you saw production, and that's an area peaking in the second quarter.

This had us more with a plan of accelerating the completions, using third parties. At that time third parties were much more expensive than they are today.

What you can then see as you look at the blue bars is that by spreading the completions more evenly, and in that case more efficiently utilizing Pioneer Pumping Services, we have a much stronger second half. In fact, the peak really occurs in the third quarter. We have a very strong fourth quarter as well. Of course, this does not include any volumes for the impact of adding two rigs if, in fact, that's decided, which we're leaning towards that very, very heavily today.

Then going on to slide 8, we wanted to give you a little granularity on this POP schedule because it's changed the trajectory of production by quarter for the year. As you see, the left-hand column, that's the first four months of the year. It shows an original plan of about 89 wells to POP with in this case the majority of them being in the South just based on timing.

And then the decision was made as I said mid-February or so to spread these completions more efficiently across the year to utilize Pioneer Pumping Services heavily. And so we actually POP 66 wells only in the first -- or anticipate POPing 66 wells in the first four months.

We would have planned for much lower, 50 wells in the May to August time frame. Now that's 65. So it in essence is level loading of Pioneer Pumping Services.

Of course when you get to the end of the year, you start to see the effect of the rig count. This of course does not include any additional rigs and the impact to production and POPs in the fourth quarter if we were to add rigs. But suffice it to say at today's rig count, we will have -- we would have expected 27 wells to be POPed, and now it's 35.

So what you see is a general shifting of the POP schedule out into the year, again, focused on efficiencies and cost savings and the efficient use of Pioneer Pumping Services. Of course by the time you get out to the last four months of the year, Pioneer Pumping Services would have spare capacity to actually go complete the wells that would be drilled associated with additional rigs that we would be adding in the second half of the year. So they will be ready to complete those wells once we get them done by the end of the year.

Turning to slide 9 now, and as I mentioned earlier, we made significant strides in terms of both cost reductions and efficiency gains. Of course the objective is to improve margins and optimize returns and in essence get back to an accelerated drilling program.

These next two slides cover those topics, the first of which is on our drilling and completions reductions. I already mentioned we achieved 15% we feel like so far, and the list is shown there as to what categories of savings we have been achieving in the materials area when it comes it drilling mud chemicals and so on. Some of these are down 18% to 20% already.

Of course fuel, diesel costs are down 36%, which is a huge benefit. Labor and transportation's a bit stickier but still down. Rental equipment down 17% to 20%, and well services down as well.

The thing about Pioneer is that we came into 2015 with a substantial amount of rigs on the one hand contracted, on the other hand tubulars having been acquired in late 2015 in anticipation of a more accelerated drilling campaign in 2016. So we've got to burn off an inventory of tubulars from last year's significantly larger drilling campaign before we will start seeing savings from tubulars.

And similarly we have stacked rigs today. And we are going to have to deal with those coming off contract over the next couple years, but we will make strides of course in reductions of day rate when that time comes.

We've estimated that if we were to essentially come out of the dirt with a new well without these continuing costs, here again I'm talking about tubulars and rig costs that are under contract, our D&C costs would today be down in the neighborhood of 20% to 25% when you compare it with 2014 costs.

Facilities, of course we continue to build tank batteries and salt water disposal systems. Those costs are down about 10%, and we continue to pursue further cost reductions.

We still have several RSQs underway for various items. We are outbidding jobs on a job to job basis so we can get current costs even lower. For example if we're going to use third-party rental equipment, third-party labor, transportation, we're outbidding those on a job by job basis. The objective on all this of course is the continuing initiative for cost reduction so we can hit our year-end targets.

Then turning to slide 10 in terms of the efficiency gains and optimization planning that we've been doing, I think we've also made significant progress here with the details shown on the slide. Some of this work is continuing in the sense that we have not stopped our R&D work when it comes to optimizing our completions or the testing of that optimization in terms of the stage lengths and clusters, the fluids pumped, the type of proppant and the concentration.

All that work continues. It's going to be a continuing process for quite a long time as we test new zones and new areas, and that's one of the R&D areas we have not shut down in response to the commodity price environment we're in.

As I think the fact that especially in the South we've been successful with a three-string casing design. This allows us to save quite a substantial sum per well, say $500,000 to $1 million per well, but importantly has reduced drilling times down by the neighborhood of 10 to 15 days per well. So we've gotten wells down 15, 16 days, and it wasn't unusual not long ago to have an average drilling time of 32 days, and so very substantial improvement out of this technology.

Most of the testing we've done has been in the South. We're now moving to the North. The feeling is that all the Southern acreage is applicable for this technology and about 60% of our Northern acreage.

We're also expanding our use of dissolvable plug technologies, most of this has been done in the Eagle Ford. This allows us to pump plugs rather than having to do -- dissolve versus having to come in with coil to drill out the plugs after the fracture, and we're now moving those technologies into the Spraberry Wolfcamp.

So a little early to say. The early couple of wells I've seen this done on, we've seen pretty substantial savings in the neighborhood of $300,000 per well and again saving time. And then finally, we are using fracture stimulation diversion technologies where we can actually go in on a cheaper basis and identify exact zones to stimulate, and by pumping diversion materials periodically, isolate those zones on a cost-effective basis.

In terms of LOE at the bottom of the page, of course LOE is more sticky due to its fixed cost nature. You have labor and electricity, which is generally pretty fixed.

We're currently so far this year down about 5% compared to our 2014 values. And that's because of reductions where we've been able to achieve at least where we have third-party labor out in the field and also pumping unit repair values coming down as well as work where we use third parties.

I'd summarize it by saying we're well on the way to achieving our year-end targets. They're shown below where we anticipate that we will be able to get above 20% on D&C cost reductions, facilities we feel like we can get to 15%, and LOE to 10%. All of those contribute heavily to our ability to get back to work in terms of accelerated drilling.

I'm now going to turn more to an operational focus at slide 11. And again, this is just a repeat of the slides that were done in the last quarter, but we now have included all the new wells that were drilled and completed in the first quarter. The red line or the top of the Wolfcamp A and the blue line in the Wolfcamp B show all wells drilled and their average laterals.

We're pleased to say that the new well performance in the Wolfcamp A and B continues to be repeatable and consistent. And as you see from the graphs, in general approaching or exceeding one million BOE in terms of their potential. You can see on the map where those wells are going to be drilled and the number of wells per area.

Slide 12 is focusing on the high grading of activity in the North that we did successfully reduce our rig count down to six very quickly this year, by the end of February. And we're, again, focusing on areas that we feel like have the best economics in the face of today's commodity prices.

So those areas that we have offset wells that have high EURs where we may have net revenue interests that are high due to low royalties and where we would have existing tank batteries nearby so that we can reduce ancillary capital costs. And all that's just based on improving the well economics for where we are going to be drilling.

We will put about 85 to 90 horizontal wells on production this year. That's a slight reduction from last year. Some of those wells of course are carried over from 2014.

If you look at the map, the actual number of wells we will spud this year in the North will be 60. Mostly using two- and three-well pads, but then 90% of which would be Wolfcamp B where we have the most confidence and the most data in terms of the number of wells that have been drilled and therefore the most confidence in the economics as well. But overall, our split of wells to be put on production will be about 70% Wolfcamp wells because of the carryover of other zones from prior completions at the end of last year.

The D&C costs are roughly about $9 million assuming at 9,000 foot lateral length and only a 10% cost reduction. These costs, I think, should come down as we achieve the next 10% or more cost reductions as we go through the year.

And importantly, our returns still look very high, at least one million barrel wells do produce very high rates of return, up to 55% using current strip prices. Of course we were using an average oil price of $55 and today it's exceeding that, so in actuality, the economics probably are stronger than what I just mentioned.

Now we only put 15 wells on production in the North. That's only because we put a large number of wells on production in the North in the fourth quarter and the inventory of available wells was significantly less in the first quarter. Just the timing of when the wells were completed dictated that.

At the same time, we didn't complete very many wells in the South during the fourth quarter and caught up in first quarter. You will see that switch as we go into the second quarter and beyond. We will be completing more wells in the North. Obviously we have more rigs running there, and at the same time you will see more completions as well.

We did complete the drilling of all of our vertical program by the end of February. You will see if you look at data, there's only 59 vertical rigs running in the Permian Basin where there had been 340. The days of vertical drilling are swooning, let me say.

13, slide 13, now we're turning to the South. Suffice it to say we're executing a similar program when it comes to high grading the activity. We have four rigs running down there, and essentially the same notion, drilling the best areas where we have the best economics closest to facilities.

We're going to put about 75 to 80 wells on production this year. That's a reduction from last year, mostly owing to the lower rig count, and as you can see in the map, we will only be spudding 45 wells.

There's a large amount of carryover as I mentioned earlier into the first quarter from last year's activity. Again, 90% Wolfcamp in terms of drilling, Wolfcamp B drilling, but about 75% of the wells put on production will be Wolfcamp B owing to the wells being carried over.

About $8 million D&C costs per well in the South. That's principally because it's shallower on the one hand, but the returns as a result end up being very similar to the North, still about 55% based on $55 oil. We did place as I mentioned 31 wells on production in the South owing to that timing of when wells were available to be completed.

Turning to slide 14 then, all of this yields a substantial amount of opportunity for growth. In fact, our growth trajectory here for this year is about 20% plus.

Of course similar to the first slide I showed on the Company's production, you can see in the graph here that the dotted lines would have had us completing many more wells in the second quarter. We pushed that out and in essence evenly spread those wells into the third and fourth quarters.

You see third quarter being peak production with a decline into the fourth quarter assuming we did not add anymore rigs. Of course as I mentioned, we're highly prepared to add more rigs starting in the third quarter, which would have some impact on fourth-quarter production. Again, we did put 46 wells on production in the first quarter and pushed some of those out into subsequent quarters.

Production about 112,000 BOE a day, 67% oil. This is where most of the effects we saw in the weather and ethane rejection to cold. Do expect production to be up substantially in 2015. So what we're really saying is production in 2015, we will have very small effect from any drilling but much more significant effect from any additions to the drilling campaign starting in July and next year's results.

Turning now to Permian infrastructure, as I mentioned earlier, we've deferred capital in our four main areas where we spend infrastructure in the face of the commodity prices compared to an earlier plan. That said, we're still spending about $410 million.

A lot of it is buried in drilling capital and tank batteries and so on, but also we still are proceeding with some expenditures when it comes to gas processing. A lot of that is related to compression and well tie-ins, but also even at the Buffalo plant where our partner Targa is contemplating a plant to be added in 2016, some foundation and compression work is ongoing. So we will spend a total of about $70 million there.

We have pushed out our Brady sand mine expansion still. It could be put on in 2017 or 2018. It just depends on when we believe we will have the sand demand that corresponds to the rig count.

And then finally, in the water infrastructure realm, we announced recently and it was in the press pretty significantly we've agreed with the city of Odessa to delay water offtake for up to two years. That will help us match our water needs more closely with the projects with Odessa to deal with our needs from the standpoint of the drilling campaigns.

We still are spending some money. In fact, we have a substantial project going on in the South. We are tying in some third-party water that we had been trucking up into our Southern operations. We do have still a capital budget here of about $100 million for this year, the majority of which is in the South to tie in some existing water.

I think if the numbers show that if we were to add two horizontal rigs per month starting in July in the North. We would need additional infrastructure, probably $35 million to $50 million for some of the same things but particularly tank batteries, salt water disposal well connections and so on.

If you look at the drilling capital add in 2016 that would come from those rigs, it probably is in the neighborhood of $225 million to $250 million. So overall to the extent we were to move ahead with the two wells beginning -- two rigs, sorry, beginning in July per month, we'd be adding probably $300 million plus or minus to the capital budget.

On slide 16, the same optimization story holds for our South Texas operations in the Eagle Ford. We have six rigs running. We're high grading. In fact, we're only drilling in two counties -- Karnes and DeWitt. We will put about 95 to 100 wells on production this year, and that compares with the amount we will spud of 85 -- again, a carryover somewhat.

Importantly, the upper and lower drilling campaigns have continued to be consistently similar. That is to say our upper wells are performing very well and consistent with the lower targets.

Our well costs are coming down here. I think eventually we can get our well costs down to about $6 million or $6 million plus in the Eagle Ford. And it's the reason we can really generate very high rates of return from Eagle Ford's very prolific wells, very low cost wells after we're now into this project some six years.

So this is an area we still see that Pioneer if you look on the bottom right is drilling some of the best wells in the industry as measured by cumulative production for five months. We did put 16 wells on production in the first quarter, up mostly basically split between upper and lower targets, and again, that's proven to be a positive.

Turning to slide 17 for 2015, six rigs this year can give us about a 9% production growth. So you see if you look at the bar, it's relatively flattish scenario based on the lower rig count.

We did put those 16 wells on production, production's 47,000 BOE a day, importantly 40% being condensate. So there's an opportunity for value accretion to the extent we can export more condensate.

We did find that we had about 2,000 barrels a day reductions due to the fact that offset completions were higher -- offset shut-ins basically from new completions were higher than expected. What we found is in drilling in only two counties, our operations are very centralized around each other.

And the result is we have many, many wells in proximity to new drills and new completions. And so I think we underestimated the number of wells that we needed to shut in for offset completions when we're working in such a tight arena of drilling which we had not been doing of course.

We'd been drilling many areas if you back up to the 10 or 12 rig count past. We do have the effects of ethane rejection also having been built in here as well. I think that ethane rejection will continue through the year.

So in summary I would say there's been a very good quarter. One more slide I would like to cover before I get there, and that is on the export business.

If you look at the economics of this, they're simply outstanding. We export about 7,000 barrels a day and additional 6,000 barrels a day exporting in June. We really want to get to 75% of more of our condensate exported. Most of this volume is going to export markets such as in Asia and Europe and generally is a replacement for naphtha.

So I want to stop there and pass it over to Rich in a minute, but in summary I would say in the first quarter we were very busy, and I think that's important. And that is continuing into the second quarter because what we're focused on is improvement in several key areas including cost reductions, efficiency gains and productivity enhancement. And all those based on how well we're doing in those bode well for a return to accelerated drilling.

And hopefully in the very near future, you will be hearing from us shortly in the next few weeks on that topic. With that I will turn the call over to Rich to cover the first-quarter financial and second-quarter outlook.

Good morning, I'm going to start on slide 19. We reported a net loss attributable to common stockholders of $78 million or $0.52 per diluted share. That did include noncash mark to market derivative gains of $22 million after tax or $0.15.

And then on the slide, you can see it did also have unusual items aggregating about $95 million of loss or $0.64, the most significant of which is a noncash impairment we had on the west Panhandle field due -- all due to lower commodity prices with oil, NGL and gas price all lower relative to where they were at the end of the year. Adjusting for those items, we're at a $5 million loss or $0.03 per diluted share.

Looking at the bottom of slide 19 where we show our results relative to the guidance we provided, you will see that all those are very consistent with guidance. I'm not going to go through those in detail, but they're there for your review.

Turning to slide 20, price realizations, something I know all of you are very aware of what's happened to commodity prices during the first quarter. You can see here that our oil price realizations were down 35% to $43.02 relative to the fourth quarter.

Also NGL prices were down 19% to $15, and gas prices were down 25% to $2.70 for the quarter. So when you look at this, this is the primary reason why our oil and gas revenue declined 36% during the quarter or about $287 million.

Looking at the bottom of the slide, the derivative activity that we have that Tim mentioned did provide support. Derivative activity added $206 million of cash for the quarter. You can see we had a pickup of $20 per barrel on the oil derivatives and $0.82 on the gas derivative.

Turning to slide 21, production costs were down for the quarter 8% to $12.56 per BOE from $13.61 in the fourth quarter. Just going down the bar chart, the biggest declines were in production taxes in the yellow part of the bar due to lower commodity prices.

And then looking at LOE was down about $0.70 or so there due to our cost reduction initiatives that Tim talked about. As he mentioned, it's still a work in progress. We still would like to see 10% by the end of the year so something that we're still working on today.

Moving to slide 22 on our liquidity position, net debt at the end of the quarter was $2.3 billion with $400 million-ish cash on the balance sheet. As you can see here, very strong balance sheet still.

We did see a reduction in our cash of about $642 million, which is principally due to paying invoices that were associated with our higher activity levels that we had in the fourth quarter of 2014. You can see here on this slide we've enumerated about $720 million of expenditures on drilling and infrastructure that was a lot of Q4 costs that weren't invoiced until Q1.

We also had a $250 million reduction in accounts payable due to the reduced drilling activity. This was partially offset by operating cash flow of about $330 million for the quarter excluding working capital changes. So all in all, still a very strong balance sheet, and as we talked about earlier, we further strengthened when we're able to complete the EFS Midstream divestiture.

Turning to slide 23, second-quarter guidance. Production for the second quarter is estimated to be 198,000 to 203,000 BOEs per day. It does reflect the spreading of our completions over the remainders of years we more efficiently utilize our Pioneer Pumping Services.

Production cost of $13 to $15. This is higher than the first-quarter actual results, mainly reflecting the higher commodity prices we're seeing in the second quarter. And we do expect production taxes to be up some. And also the increase in LOE if and when the midstream deal closes, that will be about $0.75 per BOE add to our operating cost mainly as we no longer will have our share of profits that reduce it today.

The only other item here of significance to talk about is other expense of $50 million to $60 million of guidance out there. That does include about $30 million to $35 million of stacked rig fees that we will have in the second quarter, and so that's up from where we've been in the past. So with that I will open up the call for questions.

(Operator Instructions)

And we will take our first question at this time from Doug Leggate with Bank of America.

Thank you, good morning, everybody. Tim, I wonder if I could just go back to your commentary around spending on the incremental rigs. There are two rigs per month, that would be the run rate.

What is the incremental capital associated with those on an annualized basis? And I've got a couple of follow-ups if I may. Just want today get clarity on that first.

As I mentioned, Doug -- good morning to you as well. We anticipate that if you add two rigs a month starting July for 2015, it's going to be roughly $250 million.

It depends on the exact timing of the rigs and when they all get started and so on, but if you just do the simplistic math, that's where you'd come out. Plus some ancillary activities surrounding infrastructure, but if you annualize that, it's about $1 billion I would say roughly. That's a round number again.

Okay. That assumes what well costs -- how are you thinking about allocating well costs, or is that including midstream capital as well, Tim? Or is that just the pure cost of adding the rig?

Last year of course we were dealing with $100 million per rig per year as basically the run rate. I think today's world we're utilizing numbers when we start giving numbers out like this of $80 million to $90 million per rig per year. So it's incorporating essentially some of the cost savings we've already seen.

That's pretty consistent I guess. I've got two quick follow ups if I may. The first one is really on midstream spending.

Obviously when we talk about D&C costs and what are management's different ways of approaching this, you talk about the IRRs in the well, generally midstream is not included. And we are seeing you moving towards monetizing your Eagle Ford midstream.

When you think about the shock we just had in oil, the scale of midstream spending that you'd acquire going forward, has your thinking changed any in terms of how you manage that process, whether it be monetizing the midstream, whether it be using a third party to build it out for you? I'm just curious as to how you think about the overall midstream NLP value as an option, and then I've got one quick follow up please.

Of course you can see from what we've just done or we're in the process of doing, we're not opposed to monetizing midstream. We feel like it's the right thing to do.

But in Permian, we have a little bit of a different situation. Actually, we're very, very happy regarding our partner there Targa for the principal amount of our assets. And the nice thing they bring to the table there is excess capacity, and what that allows us to do is manage around an upturn in acceleration and drilling campaign with additional space, in addition to which as I mentioned when we were talking about this during the call, the Buffalo plants they have planned sometimes in 2016 will help as well.

What's happened of course is with the downturn and the rig count reductions in Permian, you see a 49% reduction in horizontal rigs, we just don't have any capacity constraints when it comes to this infrastructure buildout today. But we actually prepare for the future and for the success that would come from accelerated drilling.

And toward that end, the one thing that this position gives us, that is a 27% interest in this big complex, is the fact that we have a seat at the table to make sure our wells get connected on time. And that's a huge positive when you're in the mode we are, which is trying to execute properly on all this campaign, as well as issues that we have underway with the likes of Targa to improve the compression in the field. It's a lower field compression and lower basically pressure such that we can get incremental volumes out of both high-volume and low-volume wells when it comes to natural gas.

I think there's a very significant need for symbiotic relationship in the Permian Basin when it comes to gas processing. You never say never on these things, but that's where we're currently leaning.

Thanks Tim, I don't know if you would be prepared to answer my final question, but I'm going to have a go anyway. There's been a fairly high-profile investor criticizing not only Pioneer but the industry as a whole in terms of shale economics and mechanics and so on. I'm just wondering if you've considered any response to that or what you would say to your investors who are obviously seeing those headlines out there, and I will leave it there, thanks.

Yes, Doug as you might expect, we've been working pretty hard right now to finalize this earnings release and preparing for the conference call over the last two days, so I can't say we've had a huge opportunity to fully analyze the presentation in question from Mr. Einhorn. But what I would say is, that all said, when we look at the analysis from a cursory standpoint and we have done some cursory review of the material, it has identified several areas where our view and Mr. Einhorn's view regarding the assumptions and analysis and conclusions regarding our business differ materially.

And I'm not going to really get into those details of where those differences are. I think some of them are rather obvious if you take a look at the material.

But what we can say is -- and we can affirmatively assert that our assets are among the very best in the domestic oil and gas arena. Our D&C and development economics of these wells we're drilling are very strong as I mentioned during the call. And that's true even in light of current commodity prices which we hope of course are improving.

Price is only one component. A lot of that analysis is focused on prices. It's really the margin of the well that matters, and I've already outlined a lot of issues we have underway to cut costs and improve efficiencies. And I think all third parties would agree the break even on our wells in the Permian are among the best in the industry, and we can weather the current price storm.

So I think we will continually get better at what we do best, which is as you know a common trait in shale development as we learn more and more from the wells. So when we look at the 20,000 plus inventory of horizontal wells in our inventory and then we look at that representing 11 billion BOE of resources, I think those are all going to be economically drilled in the fullness of time. Now it's going to take a few decades, and that said, our company and others who are doing in the similar business are going to further contribute to the country's energy revolution, and I think we firmly believe that going forward.

Appreciate the answer, I think we're on the same page then. Thanks very much.

We will take our next question from Leo Mariani with RBC.

Hey, guys. Was hoping you guys could address the EUR increase in the 2015 program.

I think last quarter you guys were saying 900,000 BOE EURs in the Northern Midland. This quarter you bumped it up to 1 million BOE. Can you maybe just talk about what's driving that, if it's better performance to date, or better fracks, whatever you're seeing.

Hey, Leo, it's Frank. I think it's fair to say if you look at the ongoing results, and we have a slide in the presentation which shows the history of all of our Wolfcamp A and Wolfcamp B wells, you can see they're tracking that million barrel type curve. So you're right, it's about performance, and moving forward we expect to continue to drill wells that look like that.

Okay. That's helpful. And with respect to well costs, I know you guys have laid out the $9 million well costs in the Northern Midland, $8 million in the South. Just curious at this point are you guys ahead of that a little bit today? Some of the cost savings you quoted maybe implies that maybe you are.

Yes, Leo, the $8 million and $9 million as was mentioned and is actually included in the slide shows that we are already incorporated about a 10% reduction in costs in those numbers. And so what -- there's a difference of concept here because these wells are currently getting drilled. We won't see the actual results regarding how they compare their AFEs until a few -- a month or two from now.

But that said, we're just now reaching that 13%, 15% number when it comes to cost reduction. We're not going to really see those in AFEs for a couple more months. There's definitely a lag built in to what we say, what we believe we can currently achieve and what actually hits the books from the standpoint after the wells are drilled.

Okay. That's helpful. I'm sure you guys have done some scenario analysis, but if you do follow through and add the two rigs per month starting in July here, just curious as to what type of level of production growth that gets you to for 2016.

Yes, I think if you take a look at the modeling we've done and you assume as you mentioned and what we've been talking about, two rigs per month beginning July, the answer to some extent depends on how many rigs you're also going to add in 2016 if any. I think if we add the rigs we're talking about this year, we add a few rigs in 2016, it's not out of the realm of possibility we will be a double-digit growth rate again.

Okay. Thanks guys.

And we will take our next question from Charles Meade with Johnson Rice.

Yes, good morning everyone. Tim, I'm wondering if I could try to peel back a bit on the shift in completions later in the year and what that may mean about what the underlying well production is, because I look at two things.

One, you guys started deferring those completions in mid-February. And so you've shifted them, the same number of wells are going to come on, but those wells are going to contribute for fewer days in 2015.

And so it seems to me that for your Q1 volumes to come in frankly above expectations on oil even with those deferred completions and for you to keep 2015 guidance intact, that something has to be outperforming your plan underneath there. Is that the right conclusion to draw?

I think that's certainly the one I would focus on simply because we are focused on as I mentioned here pretty heavily where we're going to be drilling excellent wells. And it's hard to account for a situation where we basically produce near our midpoint but we didn't POP as many wells as we planned unless you refer to the fact that we're drilling very good wells.

And I think that would be the same answer I would give pertaining to a shift out in the year or a level loading of POPs. Shifting them out of the year, you lose days of production, but it's offset by strong well performance. And I think that's really the only conclusion you can come up to.

Okay. Good. Thank you. And then shifting gears over to the -- I think this touches maybe on Doug's question earlier is first of, I wanted to thank your engineers for coming up with a $9 million well costs and a million barrel EUR because I can do the math on that. That's a $9 F&D.

We try to keep all the numbers rounded for you, Charles.

(Laughter) I appreciate that. So that's $9, but I recognize that doesn't incorporate a lot of the midstream, maybe some -- the surface infrastructure, things like that. Tim, if you were -- could you give us some guidance, what percentage on top of that $9 should we think about for a really fully loaded F&D?

Okay. So this is going to take a minute to explain just because it's semi complicated because if you were to load up all the tank battery costs and salt water disposal wells on the first well, you'd get an astronomical number. We do have to front load a lot of this capital.

When we were building tank batteries out, Charles, we're generally doing it for 60 wells, okay? And so the wells when they come on, let's say the first two-, three-well pads, if they were to be labored with all that cost, it could be significant because the initial spending that's going to be $6 million to $8 million to begin with.

When you look at the fullness of time, though, and you amortize the cost of let's say a tank battery and related salt water disposal over the whole 60-well program, it's going to average $40,000 per well. Sorry, $400,000 per well, slipped a digit. About $400,000 per well. So again if you're using the million, it's $0.40 to $0.50 per BOE.

Got it. So like a 5% uplift.

That's what you have to think about because we're spending the money up front. So when people comment -- gosh, all this capital's going out the door, sure it is. But you're not going to have to spend it again on the last 59 wells.

Got it. That's a great explanation, Tim, thank you for that.

We will take our next question from Brian Singer with Goldman Sachs.

Good morning, this is [Pavenham Soria]. I'm on for Brian Singer. You've highlighted significant cost savings from efficiencies and cost inflation, but your capital budget is unchanged. Can you talk about what flexibility or buffer this cost savings has created for you to then increase activity levels without a fully proportionate increase in your capital budget?

I think that's a great question. I think of course we are focusing in on from a budgetary standpoint a 10% cost reduction on average for the year already. So that was in the $9 million number that Charles referred to and then $8 million in the South and so on.

That said, to the extent we can achieve the 20% plus, then in the second half of the year, we should see reduced cost, and as a result the dollars and spending going further in terms of the wells. What that will give us is some flexibility in terms of how much actual net capital adds we have to add in order to add the two rigs per month beginning July. It may not be the whole let's just say 250 because we will get some benefit from the original campaign of 10 rigs on reduced costs, so I think you're on to something there.

Great. And then my follow up is on the Eagle Ford. You've talked about divesting your Eagle Ford midstream assets. Can you talk about what type of minimum activity you need to maintain in Eagle Ford to support your midstream contracts?

Well, if I think you take a look at it and just do the math from the standpoint we're looking at, it's not a dissimilar amount of drilling that we're doing today. As I've mentioned, we have six rigs running. I think that six rigs in general would be such that it would meet the requirements of throughput that are being contemplated in the negotiations, and I really can't go much more further than that in terms of detail.

Great, thanks a lot.

We will take our next question from Arun Jayaram with Credit Suisse.

Good morning, gentlemen. Tim, I wanted to first ask about your development scheme in the Midland basin. Last quarter you guys talked about focusing in on the Wolfcamp B interval.

Some in industry, Tim, have questioned where this could potentially lead to call it suboptimal recoveries, because if you come back later and -- for example, did the Wolfcamp A, that the frack energy could propagate toward some of the depleted zones. I was wondering if you could maybe address your development scheme and compare it to others out there.

Yes, well, first of all, I think the answer is there's no cookie cutter answer to that question because every area has its own unique attributes when it comes to how it would be optimally completed. I will say I agree with what you said here or basically what you were leading to, which is we do believe there is potential that you could have energy moving into the A from B completions.

And so one of the things we have been doing from the standpoint of a schematically planning development in certain areas of the basin is to drill and complete the Wolfcamp Bs and come back and do the As. We think there's nothing destructive about that at all. In fact that's probably optimal.

Realizing there's all kinds of zones we're dealing with. We've got the Lower Spraberry shale, we've got the Middle Spraberry shale, you've got the Wolfcamp D. Each of these zones one the one hand will have learnings regarding how to properly and efficiently develop them in terms of the scheme of development you mentioned, but it's also the separation between the wells, the spacing, the staggering of the wells.

This is very much a science project today, so I think if you look at some of the areas, some people would say, gosh, as you go west, the Lower Spraberry shale is better than the Wolfcamp B. We look at that and simply say -- we think the Lower Spraberry shale is excellent, across our acreage with some 600,000 acres.

The Wolfcamp B we've proven is excellent, so I think the answer is all of these areas will take a lot of science and it's going to take some time. It's not like Eagle Ford where we have six years into it now and where there's one zone or two zones that we can pretty much understand. Even in the Eagle Ford we have six or seven areas where we complete the wells differently, so this is going to be a science project through quite a long time.

Okay. It just sounds like, Tim, you're still testing a lot of development ideas and haven't yet come to the conclusion in terms of the optimal way quite yet. Is that fair?

I think the optimal way you learn in about 15 years, okay?

Okay.

I mean we just take -- we're taking stabs at it as we go forward. And our laboratory is slow. I was accused of that in one of the conferences earlier.

You guys are slow. I said -- well yes, it takes 150 days to get the wells on production, and then you've got to watch them for a while before you can decide if they're better than the other ones you just drilled next door.

It's going to take time. It's going to take a lot of effort. I feel very confident in our scientists here and our engineers that they will get to the bottom of all this in the fullness of time.

Okay. My follow up just really is regarding A, the Spraberry potential. What are you doing on the Spraberry?

And yes, we've seen some pretty eye-popping industry results on the western side of the Midland basin. I was just wondering what you're doing there and perhaps the potential that you see on your acreage position.

Well, we love the Lower Spraberry shale. It calculates as having the most oil in place of any of the zones. Accordingly, we think it has tremendous potential.

We have shown some quite excellent results from Lower Spraberry drilling ourselves. It's just in this year we're not doing a lot of Lower Spraberry drilling just because most of that Spraberry acreage we don't have to get to for the time being to hold acreage. And we worked out a lot of deals with land owners to that extent.

We're focused more on the Wolfcamp B simply because we have more data, so data gives us confidence in terms of a situation. We want to make sure these wells are highly economic -- in other words, we can predict their productivity.

With that said as we move forward, and let's just say we were to add the two rigs per month starting July, it's not inconceivable at all that that would incorporate more Wolfcamp A drilling, more Lower Spraberry shale drilling and in some other areas than we currently are focused. So stay tuned. I think the Lower Spraberry shale is a phenomenal asset.

Okay. If I could squeeze one more in, Tim, in the middle of the Martin County, at the Sale Ranch, you guys have drilled based on completion reports some really eye-popping IPs. Can you comment on that acreage position in Martin County and perhaps would that be an area where you'd put some more activity at, throw some activity at?

We have a limited sample size would be the first thing I'd say, but we have two phenomenal wells here in the Wolfcamp B that have been drilled up in the Sale Ranch area. And eye-popping results is maybe diminishing it to some extent.

A couple of these wells, if you look at the average 24-hour rates in terms of IP or 2800 barrels a day on average,. And then if you look at the cume on the wells, each of these wells has made 130,000 barrels in 150 days, so they are monster wells.

They're twice as productive so far at least as the HUD wells when you measure it on the same exact basis. So these are eye-popping. They need to be watched, and I can promise you they have our attention.

Okay. Thanks a lot.

And we will take our next question from John Freeman from Raymond James.

Hi guys.

Hi John.

Just looking at as we think about the rig adds and you're talking about some of these completion efficiency gains you've made on like the three-string casing design in the Wolfcamp where you're shaving 10 to 15 days, the Eagle Ford with the dissolvable plug, maybe 3 days off there. The last update I think you all have given on spud to POP, like Northern Wolfcamp you're around 145 days for a three-well pad, Eagle Ford was around 100 days. Could you maybe update that or even say what you would think those would be maybe more towards the end of the year?

Yes, thanks for the question, John. I think the answer to that has somewhat, though, to do with this level loading or spreading of completions.

The effect of that is to by choice increase spud to POPs in certain areas, right? So actually I had -- our average spud to POP in the North, this is Permian North today, is about [160]. I think we were like [150] last year, and it's because we've chosen to push out the completion timing.

If you look at the Swat area, the South, it's about [140] today. It's always been a little bit lower anyway because of its shallower well drilling. And so we have chosen to kick these out.

I think if we get more into more of a level-loaded mode of completing these wells than we're anticipating this year, it's not unusual as you mentioned to get these wells down instead of 150 days on average last year to [130] for instance, by a combination of the different technologies you mentioned. So I promise you we've got pretty aggressive targets. But this is a year where we're actually choosing to push it out slightly.

So Tim, just one follow-up point. When you mentioned throughout a double-digit growth number next year assuming you do go ahead with the rig ramp, what would you assume you were baking in on the spud to POP?

I think we will be much more level-loaded at that point. Realizing our Pioneer Pumping Services fleet is going to be looking for business in the fourth quarter if we were not to add those rigs. I think we will be in good shape with the fleet if we do add the rigs starting in July for the completions that are needed in the fourth quarter.

It is somewhat depends upon how many rigs we want to add in 2016, but I think we would want to have -- to go into 2016 with a pretty flat schedule of POPs, and if you do that, I think we can then start to chip away at those efficiencies. In other words, you can get in that scenario hopefully down to [130] in the North as opposed to this situation where we're choosing to push it to [160].

Great. Thanks, Tim, that's all I had.

And we will take our next question from Dave Kistler with Simmons and Company.

Good morning, guys.

Hi Dave.

Real quickly trying to triangulate a little bit more towards 2016 guidance, can you guys articulate what you think production adds per an individual rig are on an annual basis? Obviously we've got to worry about declines and all that, but just what an individual rig would produce in a year once it's up and running.

Frank, I defer to you.

(Laughter) David, let me get back to you on that.

We have to do a little math on that question.

I have not looked at it that way, but we can do it for you. Looking for it on an annualized basin for a calendar year.

You've got to assume -- he's saying, put the rig out there 1/1/16, what's it do for you.

Yes, we have those recoveries.

We will have to get back to you Dave.

Okay. I appreciate that. And then just looking at the cash flow estimates that you outlined now, $1.6 billion which is down from $1.7 billion. Obviously that's related to the POPs or the production cadence.

Completely understand, no change to CapEx with the pending Eagle Ford divestiture, pipeline divestiture and rig ramp. But if that doesn't happen, can you articulate the CapEx savings shifting POPs and stacking rigs versus fully utilizing the Pioneer Pumping Services. I'm just trying to get to, I don't know, backing into that decision on a stand alone basis in the event that this transaction doesn't come through which seems highly likely at this point that it comes through.

Yes, well, first of all, likelihood of the EFS Midstream notwithstanding, if it were not to occur, then we'd be in a situation in which we probably would have -- we'd think twice about heavily ramping up. I think the probability of the transaction is still very high, so it's really not that big of an issue.

If that were to be the case, I think what we would be doing is still pushing out the POPs simply because we think that's a cost saver and an efficiency adder, and would really have nothing to do with whether that was -- that sale was achieved or not. The question is going to be at that point how much do we want to ramp. What does that do to 2016? What does it do to 2016 planning for additional rigs. And so right now I think we're hoping for scenario 1 is the way I'd put it.

Yes, just thinking about scenario 2, though, if I back into it and I think about what you articulated for facility cost savings, well cost savings, whatnot, it looks like that would back into north of $200 million versus having call it $100 million of cash flow left out. Am I way off base on my math?

Is your $200 million an annualized number?

Yes.

Yes, so some of the cost savings we're talking about aren't kicking in as I mentioned due to the lag effects until probably July 1 in some cases. And so I would half that number just to be safe.

Okay. So if nothing else, it's a net neutral transaction at this juncture and then benefits by the Contango in the oil curve. Is that a fair way to think about it?

That's reasonable, yes.

Great, well, I appreciate the added color, thanks so much.

Okay.

We will take our next question from Bob Christensen with Imperial Capital.

Yes, I'm lost a little bit on this two rig a month starting in July. You made it contingent on 20% cost reduction, you achieved that, you made it contingent on better oil prices. That appears to have come true.

You've then added it's contingent on the Midstream. I mean, but you say the Midstream is still likely in May. I don't know what it takes to have an announcement on adding two rigs.

Well, let me just tell you first of all, I'd say read between the lines in that sense, but then secondly, our board meeting of course surrounds our annual meeting which is on May 20. That will be something for the board to consider as well, and I would expect we will have something to say about it subsequent to those meetings.

Very good, thank you.

We will take our next question from Neal Dingmann with SunTrust.

Good morning guys. Tim, just one quick question on the rig ramp you mentioned. Are most of those -- for you or Frank I guess -- where you're going to target will be mostly Lower Spraberry wells on those additional rigs, or is that just going to be spread out?

Yes, well, us first of all, Neal, the concept of drilling this year of course as I mentioned is mostly Wolfcamp B in certain locations. We will spread out in the scenario we started adding rigs and start targeting some our better Wolfcamp A and Lower Spraberry shale zone, so you will see us basically expand the footprint and the zones.

Makes sense, and then just lastly, on M&A obviously you guys have a ton of acreage. Just your thoughts for you or Frank what you're seeing in the play right now as far as [bit].

I know for a while it seemed like the bit spread was pretty wide or what are you seeing out there on acreage prices? Anything going on?

I haven't really seen very many acreage deals. I think it's precisely for the reasons you said, the bit spread is really unclear. Having come off $42 an oil and now at $62, what's the right number for a parcel out there?

I don't -- I haven't seen much deal data to speak of whatsoever, and so I think that could be the case for a while. I think everybody's grappling with where does this thing go. Are we really done with the bottom at $42? We tend to think so.

We think signs point to positive. As you know in those markets, it takes a buyer and a seller coming together. I think that's the big issue.

Thanks guys. That's all for me.

We will take our next question from Irene Haas with Wunderlich Securities.

Yes, so the question I have is that truly to get drilling days of 15 to 16 in the Southern part of the basin is remarkable. My question for you is using the three-string casing design, what's keeping you from actually applying that to the entire basin?

And related to that is right now we're seeing a lot of cost savings. And how much roughly percentage wise would those be lasting savings that we could see sustaining after the downturn's over?

On the three-string casing design, of course, one of the things that benefits us there is we have a pretty caustic and difficult zone that we're dealing with called the [San Andrea] in the shallower part of the well, 5,000 feet, something like that. And what this casing design allows us to do is to drill in essence cement the zone in and then drill the remaining part of the well in one string and therefore save a lot of money related to days having to add a trip out and add another string.

So I think if you take a look at -- I even mentioned this during the call if you remember, that in the South, we believe it is almost 100% applicable even though we're just starting it up. If you look at the North, what you have is a very substantial amount of vertical Spraberry wells having been drilled. And so the issue in certain areas is the potential for some significant loss circulation zones in the Spraberry, which would give you pause and perhaps make -- give you a decision to go to a four-string design just to prevent that.

You're really dealing with a potential for stuck pipe. You're dealing with basically a potential for train wrecks in terms of well costs, and that's the last thing we want to do.

We might in those areas, the other 40% of the North, defer and just say let's just go with the four-string casing design to prevent train wrecks. We will be pushing the envelope on that. I think it's -- we will have an incentive more and more to utilize that in the entire basin.

And then the question, the second part is how much of your current savings would be sustainable.

Well, yes, I think if you take a look at cost savings in general, and here I'm talking about already the 15% we've achieved and up to 20%. A lot of that is coming from services provided to us by third-parties, needless to say, and you'd have to say a lot of that might not be sticky. What is sticky is all these efficiency gains.

When it comes to the application of new technologies, these three-string design of the dissolvable ball technologies to the other techniques I mentioned to try improve efficiencies and cut cost, those are all sticky. I think what happens as a result of this downturn and this is probably true for the entire industry -- we get better at what we do.

We basically reduce our breakeven costs and we emerge better in terms of our cost structure as a result of it. That's where we're going to be. We're going to be better because of the downturn.

Thank you.

We will take our next question from Michael Hall with Heikkinen Energy Advisors.

Hey, good morning. Just wanted to come back a little bit on CapEx in part. As we think about this rig ramp program and outline the annualized D&C would be call it $1 billion for 2016, $50 million of incremental infrastructure that you highlighted, and we can annualize that for 2016 as well. Is there anything else that we ought to think about in the 2015 budget that would get scaled up with that ramp, any of the other infrastructure or other CapEx that's --

Yes, I think that's a pretty simple question because if you take a look at where we are in the Permian today, we are at 10 rigs. Just about this time one year ago, we had 16 rigs running in the North and say 12 or so running in the South most days. Let's just say 28 rigs.

So to the extent we add two per month this year, that gets us to --starting July, that gets us to 22 rigs. If we add a few more in 2016, it might get us essentially back to exactly where we were last year at this time.

And at this time last year, we had no bottlenecks when it came to water or sand or gas processing facilities or pipeline take away. And so we would find ourselves exactly in that same situation if it were to be that we were to raise the rig count this high.

And that's just us, that's not even related to the rest of the industry getting back to where we were, which was what, 550 rigs. And so I think the days of having significant infrastructure constraints are many -- at least a couple more years pushed out into the future just as a result of the rig count reduction and all of the new pipelines, for instance, that are just coming in this summer for oil offtake. That's a good example.

And we probably will, as I mentioned with Targa, pursue the implementation of the Buffalo plant in Martin County next year as well. I feel like we have staved off as an industry and certainly as a company any and all bottleneck issues for some time, another product of the downturn.

Okay. And so like if this year's current base for the other CapEx line is $250 million and if we add another $200 million or so to that for the grant program, is that a reasonable assumption then for 2016?

Well, wait, just for clarification, that other is basically property, plant, and equipment, and that's where the sand mine is. That's where the water project is, so I think where you will see --

The $35 million to $50 million we're adding this year.

That's where I'm going. That will be in drilling and completions, and there will probably be incremental on top of what we have this year that Tim showed you on slide 6 on our budget. So that's really the increase next year.

We have not done any preplanning for salt water disposal systems and tank batteries for 2016 yet obviously. So we -- I don't really have a number that I can share with you that will be very accurate.

Okay. That's fair. It's a bit early. And on that ramp program, roughly do you know how many wells you think you could put to sales in 2015 with that program?

Let's see. Let's do some math on it. I can maybe help a little bit here.

We're drilling three well pads commencing let's just say July 1, and those take -- let's just use the same number we were using, [160]. So that's roughly five months.

We don't see any production from the first rig's activity until basically November or December, let's just say Thanksgiving or something. So very minimal impact on this year's production, but I think it will only be that first pad or the second pad as well that are producing. And so you may see a few extra thousand barrels a day produced between Thanksgiving and Christmas, but that's it for this year.

Okay. That makes sense. And then last one in the Permian, just Wolfcamp B, what price environment do you think brings that back into the program?

Wolfcamp D? Was that the question?

Yes.

Yes, certainly Wolfcamp D numbers would show its productivity slightly less than the Wolfcamp A and B, and the Lower Spraberry shale wells. I think if you were to say -- if we're in a $50 environment, what do you want to drill, it would certainly be the Wolfcamp B Lower Spraberry shale wells. I think when you're at $70 plus, you start thinking about D wells and so on.

You also have Jo Mill. You've got Middle Spraberry. They probably start getting interesting $70 to $80. What you have is as always a stratification of opportunity in terms of returns, and we're starting at the top.

Yes. Great. That's helpful. And then the last one on my end is on the Eagle Ford midstream asset, is there excess capacity on that? Just trying to think on about what might be interesting to potential buyers.

The answer is there is.

There is? Okay.

But there's significant extra capacity.

Because we have -- let me give you an example, you can take a look at this versus production. We have 780 million cubic feet a day of gas treating capacity, and stabilization capacity if you're talking about condensate of 119,000 barrels a day.

You can go in our materials and look at how much gas and condensate we are producing. Of course our net interest is about [3.3]%, so you have to uptick that and also add on the royalties, but we have substantial capacity in those areas.

Perfect. Thanks so much for the color. Thanks guys.

And we will take our next question from Gordon Douthat with Wells Fargo.

Thanks good morning, just a couple questions for me. On the shift to the Pioneer pressure pumping services, is there any way to quantify the savings or efficiency gains that you receive by using -- totally utilizing PPS versus third parties?

Yes, first of all, you have to list what the savings are, and I would summarize it like this. We -- and some of this is esoteric because we're in a situation where if we don't use the equipment we have to idle it. For an example, if we sit a fleet in the yard, it's very expensive just like stacking a rig, probably is $50,000 a day because of the fixed costs associated with the equipment.

So there is a need, I think to make sure we use it assuming it's competitive on the one hand. But the other aspects of it are sand requirements.

We do have a lot of our sand provided by our own sand mine, the Brady sand mine, our premier silica. One of the costs of not doing this would be to get that plant out of balance and would cost substantial amounts of money in terms of storage needs for sand that's otherwise produced but for which there's no market. So we're trying to balance that as well.

The other thing we get hit on, and this is several million dollars a year for sand shipments whether they're being provided by truck by third parties, to the extent we're not ready to take sand or not taking on a ratable basis, we're charged a demurrage while waiting for sand, or while we're waiting to take the sand, as a way to put this, off the trucks. So there's several million dollars there. The other thing is we are going to benefit here because we can manage the water transfer costs into the locations we're going to be drilling when we know Pioneer Pumping Services we're very much more efficient on scheduling.

The other thing that's important is personnel. You can imagine a situation in which we're just putting fleets out there when and if needed versus a level-loaded program where we can reduce overtime and also reduce what I would refer to as overstaffing.

And the calculations show we could probably save $100,000 per completion just for the supervision staff by level loading and not being out there in the sense of only providing a fleet when and if needed. So there is substantial savings.

I don't -- I can't put a bow on the total amount for you, but it's substantial. And the other thing that's substantial that has a difficulty of putting monetary value on it is our own people being on time, pumping our wells on schedule and Pioneer Green pumping Pioneer Green wells.

And so I know there's a benefit of that because we look at the stages per day efficiencies of our fleet, and they're generally better than third-parties, and so they can save a lot. If you pump one more stage a day, it can save you $150,000 per well. So all these things add up.

Okay. Makes sense, and then over in the Eagle Ford, just wondering on your thoughts on refrack potential and how that might benefit upper and lower development, and then potential for down spacing in areas where you might not have previously been.

Yes, we have done really what I would refer to as a limited amount of refracking really across our acreage. Of course some people asked us about that in the Permian, and these are all new wells in the Permian, so refracking doesn't make a lot of sense.

But Eagle Ford we've got wells that have been on for some time, and in some cases we believe that -- where we believe we did not get a sufficient frack job, we're looking at the economics of refracking in a lot of cases with diversion materials to reduce the costs. And so we're looking at it, but I think it's only a handful of wells. I think there's a total of four wells in the Eagle Ford we're going to refrack this year. So not a lot of opportunity where we see that come to mind where this is a no-brainer.

Okay. Thank you.

This concludes our time for the question and answer session. I'd like to turn the conference back over to Tim Dove for additional or closing remarks.

I want to that think all you all for being on the call. Hope the rest of the spring goes well.

We will see you during the summer in our August call, and it will be a lot more hot than it is now I think in most of these places. We will see you then. Thanks a lot.

This concludes today's conference. We thank you for your participation.