May 6, 2015
Executives
Frank E. Hopkins - Senior Vice President of Investor Relations Timothy L.
Dove - President, Chief Operating Officer and Director Richard P. Dealy - Chief Financial Officer and Executive Vice President
Analysts
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Charles A.
Meade - Johnson Rice & Company, L.L.C., Research Division Pavan Hoskote - Goldman Sachs Group Inc., Research Division Arun Jayaram - Crédit Suisse AG, Research Division John Freeman - Raymond James & Associates, Inc., Research Division David William Kistler - Simmons & Company International, Research Division Robert L. Christensen - Imperial Capital, LLC, Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Irene O.
Haas - Wunderlich Securities Inc., Research Division Michael A. Hall - Heikkinen Energy Advisors, LLC Gordon Douthat - Wells Fargo Securities, LLC, Research Division
Operator
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.
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.
Frank E. Hopkins
Thanks, Alexie. Good day, everyone, and thank you for joining us.
As you probably realize 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'll 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'll update you on our latest plans for the remainder of the year. We'll then discuss the significant progress we are making to cut cost 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'll open up the call for your questions. So with that, I'll turn the call over to Tim.
Timothy L. Dove
Thanks, Frank, and thank 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 in 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 on our own internal pumping services for well completions.
And importantly, as Frank has alluded to many times in our prior meetings, we've 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 or 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 on 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 instance, it just doesn't make sense to extract ethane to $0.18 a gallon.
The winter weather, it wasn't as bad as what it was in 2013. But we did have 3,200 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'll 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 derivatives positions in the industry with about 90% of our oil volumes hedged for 2015, most of those are protected at a $71 per barrel swap value.
And as you look to the financials, you'll realize that resulted in about $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 a 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 a 21%. In terms of the Eagle Ford Midstream sale, the process is taking 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 around the idea of committing volumes and so on.
But we remain very optimistic that we will announce the 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 our way to have over 20% reduction by the time we get to the end of the year, and I'll talk more about that at 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 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'll also be rightsizing 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 work for us for many years in Colorado and this is a sort of 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 earlier 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 where spot prices are for Eagle Ford, condensate in the U.S., they may average, say, $12 to $13 of WTI. We're easily halfway inside of that with the international exports.
And so we anticipate increasing those volumes, and I'll 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 markets will be advantageous.
We currently have 15,000 barrels a day going down the Longhorn Pipeline. And the total volumes we'll 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 terms of education, in terms of the benefits of lifting the export ban. I'm not going to go into that too much today.
The current WTI and Brent differential is about $7. And 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 the PPS is competitive. We know that from 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.
But 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 is not impacted. We're going to still POP exactly the same number of wells.
It's simply the fact that more will be popped in the third and fourth quarter than we had originally planned and that will still yield a forecast of full year growth of about 10% plus compared to 2/3 -- 2014. And as I mentioned at the outset, we still expect and I feel confident now about adding 2 horizontal rigs per month in the northern area of the Spraberry/Wolfcamp beginning in the third quarter.
I think the oil prices have been positive and that's -- 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 2 rigs per month beginning July, of course, will have very little impact on 2015 production. We're generally going to be using 3-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 growth mode in 2016, where otherwise might not be able 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 is very strong.
We have a strong derivatives position, and what that gives us is the financial flexibility to ramp up drilling. And on this case, on what -- still it 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'll 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.
I'll 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 focused on the dashed boxes.
Those are the original plan forecast that we had in the prior quarter. You saw production and that's an area, of course, 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 extremely much more expensive than they are today.
But 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 2 rigs if, in fact, that's decided, which we're leaning towards that very, very heavily today.
Then going on to Slide 8. We want to give you a little granularity on this POP schedule because it's sort of changed the trajectory of production by quarter for the year.
But as you see the left-hand column, that's the first 4 months of the year. It shows an original plan of about 89 wells to POP with, in this case, the majority of being in the South, just based on timing.
And then the decision was made, as I said, mid-February. So to spread these completions more efficiently across the year to utilize Pioneer Pumping Services heavily.
And so we actually popped 66 wells only in the first -- or anticipate popping 66 wells in the first 4 months. We would've planned for much lower, 50 wells in the May to August time frame, now that's 65.
So it is -- in essence, there's 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 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 POP and now it's with 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 of the last 4 months of the year, Pioneer Pumping Services would have spare capacity to actually go compete the wells that would be drilled associated with additional rigs that we will 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 2 slides cover those topics and the first, of which, is on our drilling and completions, reductions. I already mentioned, we've 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 to drilling mud, chemicals and so on, some of these are down 18% to 20% already. Of course, fuel, diesel cost 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 and 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 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 of years, but we'll make strides, of course, in reductions of day rates 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 will be down in the neighborhood of 20% to 25% when you compare it with 2014 cost.
Facilities, of course, we continue to build tank batteries and saltwater disposal systems. Those costs were down about 10%, and we continue to pursue further cost reductions.
And we still have several RFQ's underway for various items. We are outbidding jobs out on a job-to-job basis, so we can get current cost even lower.
For example, if we're going to use third-party rental equipment, third-party labor or transportation, we're outbidding those out on a job-by-job basis. The objective on all this, of course, is the continuing initiative for cost reductions, 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 detail 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 per stage, the fluids pump, 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 shutdown in response to the commodity price environment we're in. We well publicize, 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, it has reduced drilling times down to the -- by neighborhood of 10 to 15 days per well.
So we've got the 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 these have been done in the Eagle Ford.
This allows us to pump plugs rather than having a tube that are dissolved versus having to come in with coil to drill out the plugs after the fracture done. And we're now moving those technologies into the Spraberry/Wolfcamp.
So a little early to say, but the early couple of wells that I've seen is 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 simulation 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 it'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 a work over where we use third parties.
So I guess, I'd summarize it by saying, we're well underway to achieving our year-end targets that's shown below, where we anticipate that we'll 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 on Slide 11.
And again, this is a just repeat of the slides that were done in the last quarter, but we now have included all the new wells where we drilled and completed in the first quarter. The red line, at the top, in the Wolfcamp A and the blue line in the Wolfcamp B, show all the 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 1 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.
Now we did successfully reduce our rig count down to 6 very quickly this year by the end of February and we are, again, focusing on areas that we feel like having the best economics in the phase of today's commodity prices. So those areas that we have offset wells that have high EURs or we may have net revenue interest 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 is 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 2 and 3 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 a 9,000-foot lateral length and only a 10% cost reduction. These costs, I think, should come down as we achieved the next 10% or more cost reductions as we go through the year.
And importantly, our returns still look very high, these 1 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 in the fourth quarter and caught up in the first quarter. You'll see that switch as we go into the second quarter and beyond.
We'll be completing more wells in the North. Obviously, we have more rigs running there and at the same time, you'll see more completions as well.
We did complete the drilling of all of our vertical program by the end of February. You'll see, if you look at the data, there's only 59 vertical rigs running in the Permian Basin where there had been 340.
So the days of vertical drilling are smoothing, 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 4 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're only be spudding 45 wells. There's large amount of carryovers, 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 cost 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 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've pushed that out in an essence, evenly spread those wells into the third and fourth quarters.
So you see, third quarter being peak production, with a decline into the fourth quarter assuming we did not add any more 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.
It had -- this is where most the effects we saw when weather and ethane rejection took hold. We do expect production to be up pretty substantially in 2015.
So what we're really saying is production in 2015 will have very small effect from any drilling, but much more significant effect from any additions to the drilling campaign starting in July next year results. Turning now to Permian infrastructure.
As I mentioned earlier, we have deferred capital in our 4 main areas where we spend money on 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 of 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'll 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 '18. It just depends on when we believe we're hoping to 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 order offtake for up to 2 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 have been trucking up into our southern operations.
So we do have still a capital budget here 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 2 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, it 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 2 wells beginning -- 2 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 6 rigs running. We're high grading and, in fact, we're only drilling in 2 counties.
Karnes and DeWitt. We'll put about 95 to 100 wells on production this year and that compares with the amount we'll 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 preforming very well and consistent with the lower targets. Our well cost are coming down here.
I think, eventually, we can get our well cost down to about $6 million or $6 million-plus in the Eagle Ford. And it's the reason that we can really generate a very high rates of return from the Eagle Ford's very prolific wells, very low-cost wells after we're now into this project some 6 years, and so this is an area we still see.
The Pioneer if you look on the bottom right, it's drilling some of the best wells in the industry as measured by cumulative production for 5 months. We did put 16 wells on production in the first quarter, mostly -- basically split between upper and lower targets and again, that's proven to be a positive.
Turning to Slide 17. For 2015, 6 rigs this year can give us about a 9% production growth.
So you see, if you look at the bars, relatively flattish scenario based on the lower rig count. If we did put those 16 wells on production, production is 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 of reductions due to the fact the offset completions were higher -- offset shut-ins basically were from new completions were higher than expected.
What we found is, in drilling only 2 counties, our operations are very centralized around each other and resulted as -- 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 were working in such a tight arena of drilling, which we had not been doing, of course. We've been drilling in many areas if you go back up to the 10 or 12 rig count in the past.
We do have the effects of ethane rejection also having been built in here as well, and I think that ethane rejection will continue through the year. So in summary, I would say, it's been a very good quarter.
And one more slide I do want to cover before I get there, and that is on the export business. I think, 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% or more of our condensate exported.
Most of this volume is going to export markets, such as in Asia and Europe and generally as a replacement for NAFTA. So I want to stop there and pass it over to Rich in a minute.
But on summary, I'd say, in the first quarter, we were very, 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 of those, based on how well we're were doing in those, bode well for return to accelerated drilling. And hopefully, in the very near future, you'll be hearing from us probably shortly in the next few weeks on that topic.
With that, I'll turn the call over to Rich to cover the first quarter financial and second quarter outlook.
Richard P. Dealy
Thanks, Tim, and good morning. I'm going to start on Slide 19, where 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 we did also have unusual items aggregating about $95 million of loss or $0.64.
The most significant of which is noncash impairment that we had on the West Panhandle field due -- all due to lower commodity prices we would -- oil, NGL and gas prices, all lower relative to where they were at the end of the year. So adjusting for those items, we're $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'll see that all those are very consistent with guidance. I'm not going to go through the detail, but they're there for your review.
Turning to Slide 20, price realizations. Something I know all of you are very well 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 revenues declined 36% during the quarter or about $287 million. Looking at the bottom of the slide, the derivative activity that we have, as Tim mentioned, did provide support.
Derivative activity added $206 million of cash for the quarter. You can see, we had a pickup of $20 on -- per barrel on the oil derivatives and $0.82 on the gas derivatives.
Turning to Slide 21, production costs. We're 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 are in production taxes in the yellow part of the bar there due to lower commodity prices. And then looking at LOE, it was down about $0.70 or so there due to our cost-reduction initiatives, as Tim talked about, as we -- he mentioned it's still 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 on 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 the slide, we've enumerated about $720 million of expenditures on drilling 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 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're 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 remainder of the year as 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.
So 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'll 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
[Operator Instructions] And we'll take our first question at this time from Doug Leggate with Bank of America.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Tim, I wonder if I could just go by to your commentary around spending on the incremental rigs. To add 2 rigs per month, I guess, that would be the run rate.
What is the incremental capital associated with those on an annualized basis? And then I've got a couple of follow-ups, if I may.
I just want to get a clarity on that first.
Timothy L. Dove
Yes. As I mentioned, Doug, we anticipate that if you add 2 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 sort of simplistic math, that's where we would be -- where it would come out, plus some ancillary activities surrounding infrastructure. But if you annualize that, that's about $1 billion, I would say, roughly.
That's a round number again.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Okay. And that assumes what well cost -- how are you thinking about allocating well cost?
Or is that including midstream capital as well, Tim? Or is that just the pure cost of adding the rig?
Timothy L. Dove
Well, 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 like this, the $80 million to $90 million per rig per year.
So it's incorporating essentially some of the cost savings we've already seen.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
That's pretty consistent, I guess. I've got 2 quick follow-ups, if I may.
The first one is really on Midstream spending because obviously when we talk about D&C costs and a lot of managements have different ways of approaching this, but when you talk about the IRRs and the well, generally midstream is not included and we are seeing you, I guess, moving towards monetizing your Eagle Ford midstream. So when you think about the -- I guess, the short quickest [indiscernible] oil, the scale of midstream spending that you'd acquire going forward, has your thinking changed any in terms of how you managed that process whether it'd be monetizing the midstream, whether it'd be using a third party to build out for you?
I'm just kind of curious as to how you think about the overall kind of midstream MLP value as an option. And then I've got one quick follow-up, please.
Timothy L. Dove
Yes, of course. You can see from what we've just done.
We're in the process of doing. We're not opposed to monetizing midstream if we feel like it's the right 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 and acceleration in drilling campaign with additional space. In addition to which, as I mentioned, when we were talking about this during the call, the Buffalo plant today, they have planned sometime in 2016 will help as well.
But what's happened, of course, is with the downturn and the rig count reductions -- in Permian, you've seen a 49% reduction in horizontal rigs -- we just don't have any capacity constraints when it comes to this infrastructure build out today, but we have to 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 of this campaign, as well as initiatives that we have underway with the likes of Targa to improve the compression in the field. It's a lower field compression, 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.
So I think there's a very significant need for a 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.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
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, I guess, 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 have considered any kind of a response to that or what you would say to your investors who are obviously seeing that in headlines out there, and I'll leave it there.
Timothy L. Dove
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 2 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 would 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 that -- 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.
But price is only one component. A lot of that analysis is focused on price.
It's really the margin of the well, as you know, that matters. And I've already outlined a lot of initiatives we have underway to cut costs and improve efficiencies.
And I think all third parties would agree, the breakeven 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'll 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 we think we firmly believe that going forward.
Operator
We'll take our next question from Leo Mariani with RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
I was hoping you guys could address the kind of 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, I guess, 1 million BOE. Can you maybe just kind of talk about what's driving that, if it's better performance today, better fracs or whatever you're seeing?
Frank E. Hopkins
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 1 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.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. That's helpful.
And I guess with respect to well cost, I know you guys have laid out the $9 million well cost in 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?
Timothy L. Dove
Yes, Leo, the $8 million and $9 million as was mentioned or actually is included in the slide shows that we are incorporating about a 10% reduction in cost in those numbers. And so what -- it's sort of a difference of concept here because these wells that are currently getting drilled, we won't see the actual results regarding how they compared to their AFEs until a month or 2 from now.
But that said, we're just now reaching that sort of 13%, 15% number when it comes to cost reductions. So we're not going to really see those in AFEs probably for a couple more months.
There is definitely a lag built-in to what we say, we believe we can currently achieve and what actually hits the books from the standpoint of -- after the wells are drilled.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. That's helpful.
And I guess, yes, I'm sure you guys have done some scenario analysis. But I guess if you do follow through and add the 2 rigs per month starting in July here, just curious as to what type of level of production growth that gets you to for 2016?
Timothy L. Dove
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 2 rigs per month beginning July, the answer to some extent is dependent upon how many -- depends on how many rigs you're also going to add in 2016, if any. But I think if we add the rigs we were talking about this year and we add a few rigs in 2016, it's not out of the realm of possibility we would be double-digit growth rate again.
Operator
And we'll take our next question from Charles Meade with Johnson Rice.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
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 2 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 '15.
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?
Timothy L. Dove
Well, I think that's certainly the one that 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.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Okay, good. And then shifting gears over to the -- I think this touches maybe on Doug's question earlier is, first off, I want to thank your engineers for coming up with a $9 million well cost and 1 million barrel EUR because I can do the math on that.
That's a $9 F&D.
Timothy L. Dove
We try to keep all the numbers rounded for you, Charles.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
I appreciate that. So that's $9, but I recognize that doesn't incorporate a lot of the midstream, maybe some of 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?
Timothy L. Dove
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 cost and saltwater disposal wells on the first well, you'd get an astronomical number.
We do have to frontload a lot of this capital. But when we are 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 2 -- 2, 3-well pads, if they were to be labored with all that cost, it could be significant because of 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, when you amortize the cost of, let's say, a tank battery and related saltwater 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 1 million, it's $0.40 to $0.50 per BOE.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it. So just like a little $0.05 uplift?
Timothy L. Dove
The concept you have to think about because we're spending the money upfront. So when people comment, "Gosh, all this capital is going out the door."
Sure it is, but you're not going to have to spend it again on the last 59 wells.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it. That's a great explanation, Tim.
Operator
And we'll take our next question from Brian Singer with Goldman Sachs.
Pavan Hoskote - Goldman Sachs Group Inc., Research Division
This is Pavan Hoskote. I'm on for Brian Singer.
You've highlighted significant cost savings from efficiencies and cost deflation, 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?
Timothy L. Dove
Yes, I think that's a great question. I think, of course, we are focusing in on when we -- 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 we're spending are going further in terms of the wells. And 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 2 rigs per month beginning July.
It may not be the whole, let's just say, $250 million because we'll get some benefit from the original campaign of 10 rigs on reduced cost. So I think you're on to something there.
Pavan Hoskote - Goldman Sachs Group Inc., Research Division
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 may need to maintain in the Eagle Ford to support your midstream contracts?
Timothy L. Dove
Well, I think if 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 going today. So as I've mentioned, we have 6 rigs running.
I think that 6 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.
Operator
We'll take our next question from Arun Jayaram with Crédit Suisse.
Arun Jayaram - Crédit Suisse AG, Research Division
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 question whether this could potentially lead to suboptimal recoveries because if you come back later and, for example, did the Wolfcamp A, that the frac energy could propagate toward some of the depleted zones. I was wondering if you could maybe address your development scheme compared to others out there.
Timothy L. Dove
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. But I will say, I agree with what you said here and basically where you were leading to which is, we do believe that there is a 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 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. But realizing there's all kinds of zones we're dealing with here.
We've got the Lower Spraberry Shale. We've got the Middle Spraberry Shale.
You've got the Wolfcamp D. Each of these zones are on the one hand going to have -- we'll have learnings regarding how to properly and efficiently develop them in terms of the scheme of development that 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, even as well 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 6 years into it now and where there's one zone or 2 zones that we can pretty much understand. Even in the Eagle Ford, we have 6 or 7 areas where we complete the wells differently.
So this is going to be a science project, Arun, I guess, through quite a long time.
Arun Jayaram - Crédit Suisse AG, Research Division
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?
Timothy L. Dove
I think the optimal way, you learn in about 15 years, okay? I mean, if we just take -- we're taking stabs at it as we go forward.
And our laboratory is slow, okay? I was accused of that in one of the conference really, "You guys are slow."
And I said, "Well, yes, it takes 150 days to get the wells on production, and then you got to watch them for a while before you can decide whether they're better than the other ones you just drilled next door." So 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.
Arun Jayaram - Crédit Suisse AG, Research Division
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.
Timothy L. Dove
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've worked out a lot of deals with landowners to that extent. We're focused more on the Wolfcamp B simply because we have more data.
And so data gives us confidence in terms of the situation. We want to make sure these wells are highly economic.
In other words, we can predict their productivity. But that said, as we move forward, and let's just say we were to add the 2 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.
Arun Jayaram - Crédit Suisse AG, Research Division
Okay. If I could squeeze one more in.
Tim, in the middle of Martin County, the Sale Ranch, you guys have drilled, based on completion reports, some really eye-popping kind of IPs. Could you comment on that acreage position in Martin County?
And perhaps would that be an area that you'd put more activity at, throw some more activity at?
Timothy L. Dove
Well, we have a limited sample size would be the first thing I'd say, but we have 2 sort of 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 were at 2,800 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 Hutt 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.
Operator
And we'll take our next question from John Freeman with Raymond James.
John Freeman - Raymond James & Associates, Inc., Research Division
Just looking at -- as we think about the rig adds and you're talking about some of these completion efficiency change you've made on -- like the 3-string casing design in the Wolfcamp, where you're shaving 10, 15 days, the Eagle Ford with the dissolvable plug, maybe 3 days off there. The last update, I think you have given on spud-to-POP, like Northern Wolfcamp, you're around 145 days for like a 3-well pad.
Eagle Ford was around 100 days. Could you may be update that or even say kind of what you would think those would be maybe more toward the end of the year?
Timothy L. Dove
Yes, I think -- thanks for the question, John. I think the answer to that has somewhat though to do with this level loading or spreading on completions.
The effect of that is to, by choice, increase spud-to-POPs in certain areas, right? So actually, I had the math done on this.
And our average spud-to-POP in the north -- this is Permian North today is about 160. I think we were like 150 last year is 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 bit lower anyway because of the 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 done 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.
John Freeman - Raymond James & Associates, Inc., Research Division
So Tim, just one follow-up, when you mentioned -- kind of threw out kind of a double-digit growth number next year assuming you do go ahead with the rig ramp, like what would you kind of assume you were kind of baking in on kind of the spud-to-POP?
Timothy L. Dove
Well, I think we'll 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'll 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's somewhat dependent 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 here, we're choosing to push it to 160.
Operator
And we'll take our next question from Dave Kistler with Simmons & Company.
David William Kistler - Simmons & Company International, Research Division
Real quickly kind of trying to triangulate a little bit more towards '16 guidance. Can you guys articulate what you think production adds per an individual rig are on an annual basis?
Obviously, we 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?
Timothy L. Dove
Frank, I defer to you.
Frank E. Hopkins
David, let me get back to you on that.
Timothy L. Dove
We have to do a little math on that question.
Frank E. Hopkins
I have not looked at it that way, but we can do it for you, I guess, looking forward on an annualized basis.
Timothy L. Dove
And I think you have to assume...
Frank E. Hopkins
The calendar year.
Timothy L. Dove
Yes, you got to assume -- I guess he's saying, you put the rig out there 1/1/16, what's it do for you?
David William Kistler - Simmons & Company International, Research Division
Yes, exactly.
Frank E. Hopkins
We have those recoveries.
Timothy L. Dove
Yes, we'd have to get back at you, David.
David William Kistler - Simmons & Company International, Research Division
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 the 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 kind of shifting POPs and stacking rigs versus fully utilizing the Pioneer Pumping Services.
I'm just to get to -- I don't know -- backing into that decision on a standalone basis in the event that this transaction doesn't come through, which seems highly likely at this point that it comes through.
Timothy L. Dove
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 think twice about heavily ramping up. I think the probability of the transaction is still very high.
It's really not that big of an issue. But if that were to be the case, then 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 those -- 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 '16?
What does that do to '16 planning for additional rigs? And so right now, I think we're hoping for scenario one, I guess, is the way I'd put it.
David William Kistler - Simmons & Company International, Research Division
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 flows slip out.
Am I way off base on my math?
Timothy L. Dove
Is your $200 million an annualized number?
David William Kistler - Simmons & Company International, Research Division
Yes.
Timothy L. Dove
Yes, some of the cost savings we're talking about aren't kicking in as I mentioned due to this sort of the lag effect until probably July 1 in some cases, and so I would half that number just to be safe.
David William Kistler - Simmons & Company International, Research Division
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 kind of a fair way to think about it?
Timothy L. Dove
That's reasonable, yes.
Operator
We'll take our next question from Bob Christensen with Imperial Capital.
Robert L. Christensen - Imperial Capital, LLC, Research Division
I'm lost a little bit on those 2 rigs a month starting in July. You made it contingent on 20% cost reductions.
You achieved that. You made it contingent on better oil prices.
That appears to have come through. You've then added it's contingent on the midstream, I mean, but you say, the midstream is still likely in May, I just -- I don't know what it takes to have an announcement on adding 2 rigs.
I'm...
Timothy L. Dove
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 a subject for the board to consider as well, and I would expect we'll have something to say about it subsequent to those meetings.
Operator
We'll take our next question from Neal Dingmann with SunTrust.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Say, Tim, just a quick one, one quick question on the ramp -- the rig ramp that you mentioned. Are most of those are -- 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 kind of spread out?
Timothy L. Dove
Yes, well, first of all, Neal, the concept of drilling this year, of course, as I mentioned, is mostly Wolfcamp B in certain locations. We'll spread out -- in that scenario, we start adding rigs and start targeting some of our better Wolfcamp A and Lower Spraberry Shale zones.
So you'll see us basically expand the footprint and the zones.
Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division
Makes sense. And then just lastly on M&A.
Obviously, you guys have a ton of acreage, not necessary for you all. Just your thoughts -- for you or Frank -- what you're seeing in the play right now as far as sort of bid?
I know for a while it seemed like the bid-ask spread was pretty wide. What are you seeing out there on acreage prices, anything going on?
Timothy L. Dove
I haven't really seen very many acreage deals. I think it's precisely for the reason you said that the bid-ask spread is really unclear.
Having come off $42 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 is grappling with, where does this thing go?
Are we really done with the bottom at $42? We tend to think so.
And so we think the signs point to positive. But as you know, in those kind of markets, it takes a buyer and a seller that are coming together.
I think that's the big issue.
Operator
We'll take our next question from Irene Haas with Wunderlich Securities.
Irene O. Haas - Wunderlich Securities Inc., Research Division
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. So my question for you is, using the 3-string casing design, what's keeping you from actually applying that to the entire basin?
And sort of related to that, right now, we're seeing a lot of cost savings and how much roughly percentage-wise would we -- would those be sort of lasting savings that we could see sustaining after the downturn is over? That's all.
Timothy L. Dove
Yes, thanks, Irene. I think on the 3-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 Andres in the shallower part of the well, say, it was at 5,000 feet something like that.
And what this casing design allows us to do is to drill and in essence cement the zone in and then drill the remaining part of the well in one basically...
Frank E. Hopkins
One string.
Timothy L. Dove
That's right, sorry guys. And therefore, save a lot of money related to days having to trip out and add another string.
And 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 lost circulation zones in the Spraberry, which would give you pause and perhaps may give you the decision to go to a 4-string design just to prevent that because you're really dealing with a potential for stuck pipe. You're dealing with basically a potential for train wreck in terms of well cost, and that's the last thing we want to do.
So we might in those areas, the other 40% of the north, defer and just kind of say, let's just go with the 4-string casing design to prevent train wrecks. But we'll be pushing the envelope on that.
I think it's -- we'll have an incentive more and more to utilize that in the entire basin.
Irene O. Haas - Wunderlich Securities Inc., Research Division
And then the question, the second part is, how much of your current savings would be sustainable?
Timothy L. Dove
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, but what is sticky is always efficiency gains.
So when it comes to the application of new technologies, this 3-string design and the dissolvable ball technologies to the other techniques I mentioned to try to improve efficiencies and cut cost, those are all sticky. And so 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 cost, and we emerge better in terms of our cost structure as a result of it. And that's what we're going to be.
We're going to be better because of the downturn.
Operator
We'll take our next question from Michael Hall with Heikkinen Energy Advisors.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Just wanted to come back a little bit on CapEx in part as we think about this rig ramp program kind of outline the annualized D&C would be, call it, $1 billion for '16, $50 million of incremental infrastructure that you highlighted, and we can annualize that for '16 as well. Is there anything else, I guess, that we ought to think about in the 2015 budget that would get scaled up with that ramp, any of the other kind of infrastructure or other CapEx that [indiscernible].
Timothy L. Dove
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. Of course, and just about this time, 1 year ago, we had 16 rigs running in the north and say, 12 or so running in the south over most days.
So let's just say 28 rigs. So to the extent we add 2 per month this year, that gets us to, starting July, that gets us to 22 rigs.
And 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 takeaway.
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 -- there's a couple more years pushed out into the future just as a result of the rig count reduction and all 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 a Targa, pursue the implementation of the Buffalo plant in Martin County next year as well.
So 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.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Okay. And so like if this year's current base for the other CapEx line was $250 million and if we kind of just add another $200 million or so to that for the ramp program, is that a reasonable assumption then for '16?
Frank E. Hopkins
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 that you'll see...
Timothy L. Dove
Explained by the $35 million to $50 million we're adding this year...
Frank E. Hopkins
Well, that's going to be -- that's where I'm going. That will be in drilling and completions and 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.
Timothy L. Dove
We have not done any preplanning for saltwater disposal systems and the tank batteries for '16 yet, obviously. So I don't really have a number that I can share with you to be very accurate.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Okay, that's fair. It's a bit early.
And I guess on that ramp program, roughly, do you know how many wells do you think you could put to sales in '15 with that program?
Timothy L. Dove
Well, let's see. Let's do some math on it.
Maybe I can help a little bit here. We're drilling 3-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 5 months. We don't see any production from the first rigs activity until basically it's November, December.
Let's say Thanksgiving or something. So you're going to have 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 in -- between Thanksgiving and Christmas, but that's it for this year.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Okay. Makes sense.
And then last one on the Permian. I guess just Wolfcamp D, what sort of price environment do you think brings that back into the program?
Timothy L. Dove
The Wolfcamp D, was that the question?
Michael A. Hall - Heikkinen Energy Advisors, LLC
Yes.
Timothy L. Dove
Well, I think, certainly, Wolfcamp D numbers would show its productivity slightly less than the Wolfcamp A and B and Lower Spraberry Shale. And so I think, if you were to say, if we're in a $50 environment, what do you want to drill?
It certainly would 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.
Those -- you also have Jo Mill. You got Middle Spraberry.
They probably start getting interesting $70 to $80. So what you have is, as always, a sort of stratification of opportunity in terms of returns and we're starting at the top.
Michael A. Hall - Heikkinen Energy Advisors, LLC
Great. That's helpful.
And then I guess the last on my end is, on the Eagle Ford midstream asset, is there excess capacity on that? Just trying to think about what might be interesting to potential buyers.
Richard P. Dealy
The answer is there is.
Michael A. Hall - Heikkinen Energy Advisors, LLC
There is?
Frank E. Hopkins
But there's a significant extra capacity.
Timothy L. Dove
Yes, we have. Let me give you an example.
You could take a look at this versus our production, we have 780 million cubic feet a day of gas treating capacity. So that's -- and stabilization capacity, if you're talking about condensate, of 119,000 barrels a day, so that -- you can go in there in our materials and look at how much gas and condensate we are producing, of course, our net interest is about 33%.
So you have to uptick that and also add on the royalties, but we have substantial capacity in those areas.
Operator
And we'll take our next question from Gordon Douthat with Wells Fargo.
Gordon Douthat - Wells Fargo Securities, LLC, Research Division
Just a couple of 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 -- fully utilizing PPS versus third parties?
Timothy L. Dove
Yes, I think, 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 if we don't use the equipment, we'll have to idle it.
So just as an example, if we sit the fleet in the yard, it's very expensive, just like stacking a rig. Probably is $50,000 a day because of the fixed cost associated with the equipment.
So there is a need, I think, to make sure we use this, 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 or 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, where 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 with demurrage while waiting for sand -- or while the sand -- while we're waiting to take the sand is the way to put this off the trucks. And so there's several million dollars there.
The other thing is we -- we are going to benefit here because we can manage the water transfer cost into the locations we're going to be drilling when we know -- with Pioneer Pumping Services, we were very much more efficient on scheduling. So 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 over time and also reduce what I'd kind of 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 put a bow on the total amount for you, but it's substantial.
And another thing that's substantial is -- have 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 better generally than third parties.
And so you can save a lot -- if you pump one more stage a day, it can save you $150,000 per well. So there's all these things add up.
Gordon Douthat - Wells Fargo Securities, LLC, Research Division
Okay. Makes sense.
And then, over in the Eagle Ford, just wondering on your thoughts on refrac potential and how that might benefit upper and lower development and then potential for down spacing in areas where you might not have previously down spaced?
Timothy L. Dove
Yes, we have done really what I would refer to as a limited amount of refracking really across our acreage. Of course, some people will ask 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 the 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 frac job, we're looking at the economics of refracking, a lot of cases with diversion materials to reduce the cost. And so we're looking at it, but I think it's only in a handful of wells.
I think there's a total of 4 wells in the Eagle Ford we're going to refrac this year. So just not a lot of opportunity that we see that come to mind where this is a no-brainer.
Operator
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.
Timothy L. Dove
I want to thank all of you for being on the call. Hope the rest of the spring goes well.
We will see you during the summer in our August call. It'll be a lot more hot then, I think, than it is now with most of these places.
So we'll see you then. Thanks a lot.
Operator
This concludes today's conference. We thank you for your participation.