Nov 5, 2014
Executives
Frank E. Hopkins - Senior Vice President of Investor Relations Scott Douglas Sheffield - Chairman and Chief Executive Officer 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 Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division David W.
Kistler - Simmons & Company International, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co.
Securities, Inc., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Evan Calio - Morgan Stanley, Research Division John Freeman - Raymond James & Associates, Inc., Research Division Eli J.
Kantor - Canaccord Genuity, Research Division Sven Del Pozzo - IHS Herold, Inc. Gilbert K.
Yang - DISCERN Investment Analytics, Inc
Operator
Welcome to Pioneer Natural Resources Third Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; 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 November 30.
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 business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Pioneer's news release, on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission. At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins.
Please go ahead, sir.
Frank E. Hopkins
Thank you, Shannon. Good day, everyone, and thank you for joining us.
As Shannon mentioned, you can find the slides for this call at www.pxd.com. I want you to note that the version of these slides that's on the website now has been updated from the version that we posted last night.
It now includes 2 slides related to our equity offering, which will be discussed during this call. This updated version is the one that will be used on today's call and the page numbers will be aligned to that version.
With that housekeeping matter out of the way, let me briefly go over the agenda for the call today. Scott's going to be up first.
He's going to discuss the rationale behind the transactions that were announced last evening to enhance Pioneer's balance sheet. He'll also provide operating highlights for the third quarter.
Again, another great quarter for Pioneer and one which highlights that we are successfully executing the growth program we committed to at the beginning of this year. After Scott concludes his remarks, Tim will review our continued strong horizontal drilling results in the Spraberry/Wolfcamp and the Eagle Ford Shale.
He will also provide color on some of the front-end loaded infrastructure projects that are being progressed to support Pioneer's long-term growth plan for the Spraberry/Wolfcamp. Rich will then cover the third quarter financials and provide earnings guidance for the fourth quarter.
With that -- or after that, we'll open the call up for your questions. And now I'll turn the call over to Scott.
Scott Douglas Sheffield
Thanks, Frank. Good morning.
On Slide #3, on our rationale, capital funding. The combination with selling $1 billion of equity combining with announcing the expected sale of our Eagle Ford Midstream business, it allows Pioneer to really prudently develop its assets in what I believe could easily be a $70 to $80 oil price environment over the next 2 years.
As you all know, the price of oil has dropped about $30 a barrel. It is $1 trillion stimulus per year to the world economy.
It's going to take a while to get the demand side up in the world today. At the same time, we're in a battle with Saudi Arabia in regard to market share versus U.S.
shale oil. This allows us, both transactions, to be able to have continued success, as Frank mentioned, of annual production growth of 16% to 21% through '16 at very attractive returns of 40% to 80% before tax.
As footnoted, those returns could significantly improve if you see a significant drop in the rig count, which I expect in first quarter among other industry participants and various plays throughout the U.S., in addition to other initiatives that we are initiating out in the field and optimization program. We won't decide on our final rig count until we announce it in early February on our schedule, whether it's 0 rigs, whether it's 5 rigs or whether it's 10 rigs add during the year.
We have tremendous flexibility with our rig contracts as most of them are on a 3-year contract, but we purposely had them expiring 1/3 in '15, 1/3 in '16 and 1/3 in '17. It all depends on what oil prices are over the next 3 months.
Again, the use of proceeds, in addition to the growth and continued success, is to fund front-end loaded infrastructure, which will provide significant cost savings in the future. Total of about $1.4 billion to $1.6 billion over the 2-year period.
The main cost will be $500 million to $700 million for our water distribution system and network coming out of the city of Odessa and the city of Midland, which Tim will give more detail on, which will save us about $0.5 million -- over $0.5 million per well. When you look at over 20,000 drilling locations, it's over $10 billion of savings over the next several years.
In addition, we're continuing to build out large horizontal tank batteries. And eventually, as we get into development drilling, we won't have to spend the money on those tank batteries and save over $0.5 million per well.
In addition, we'll be -- several new gas processing facilities will be coming on. We'll be expanding our sand mine to almost 3x for $125 million.
And we're doing all of this over the next 2 years to make sure we maintain a debt-to-book below 35% and debt-to-cash-flow below 1.5. So both of these allows us to prudently develop our industry-leading position in probably the largest oil field in the U.S., in the world-class Spraberry/Wolfcamp oil field.
Slide #4, a little background on the Eagle Ford midstream divestiture. Pioneer owns 50.1%, we're doing it jointly with Reliance, who owns 49.9%.
Pioneer's the operator. Data room will open in December.
Bids are expected shortly thereafter. We expect to announce a successful sale sometime between mid- and late-first quarter.
Sale proceeds back into the Spraberry/Wolfcamp assets. The rest of the detail, in regard to description, I won't go over that detail.
Probably the most important item is our forecasted cash flow to Pioneer is a little over $100 million for 2015. And obviously, with the MLP still trading at a very, very rich premium, we expect some significant offers for this asset.
Also, our ability to export processed condensate remains unaffected by this expected divestiture. In addition, we have no plans to divest our Eagle Ford Shale upstream assets.
Slide #5. Just to summarize what's happened in Pioneer over the last 3 years.
We've successfully transformed our Spraberry/Wolfcamp acreage from a vertical play into a world-class horizontal play on our 825,000 acres, appraising 6 of highly prospective stacked intervals with strong EURs, internal rate of returns with very high oil content. We've grown our resource potential from 3.1 billion barrels over 3x to 9.6 billion barrels of oil equivalent, adding significant net asset value.
Over 20,000 horizontal drilling locations, more than double production from 45,000 barrels a day equivalent to over 100,000 barrels a day. Entered in our joint venture Sinochem.
Developed a world-class premier pressure pumping company, in addition to acquiring the fourth-largest sand mine in the U.S., which is only about a 3-hour drive out to West Texas. Increased our gas processing capacity with our ownership being 27% to 30% from roughly 285 million a day to 1 billion a day.
Secured a long-term water supply to move away from freshwater over the next several years. And we negotiated third-party transactions to get premium pricing by moving away from the Mid-Cush differential and also getting -- over half of our production eventually will be priced off the Gulf Coast or LLS, minus transportation.
On Slide 6, just to show where we've gone from in '11 to '14, again, from 3 billion to 9.6 billion barrels of oil equivalent in the largest oil field in the U.S. today, so 3x.
Slide #7, as Frank said earlier, again, we're executing on our growth plan with great success. We are at the high end of production again, as we were second quarter.
Again, in third quarter at 186,000 barrels a day, up 10,000. The oil production is 90% of that, up 9,000, 6% compared to second quarter and 12% on oil production growth compared to second quarter.
Again, driven primarily by our success in the Spraberry/Wolfcamp play. We're narrowing guidance to the upper end of our range to 18% to 19%.
We've more than doubled the number of horizontal wells placed on production in second half compared to the first half. Already, production in mid-October is more than 195,000 barrels a day equivalent.
Our guidance for the quarter will be 200,000 to 205,000 barrels a day. A slight increase in our capital, roughly about $100 million drilling capital, primarily for optimization in regard to about 30 wells that we're optimizing with much bigger fracs, both sand and fluid.
And then also in addition, some early expenditures on our water distribution system. Again, forecasting production growth in this lower price environment is 16% to 21% over the next 2 years.
We have great hedges in place also, probably the best hedges in place among the industry in 2015 and '16 on oil. And again, we're 100% protected on a the Mid-Cush differential, as I mentioned earlier.
Slide #18 (sic) [ Slide #8 ] Again, I think the most important point for the quarter is that we have delineated the Wolfcamp A interval. If you remember previously, we had 1 -- well on the 1 good A Well, and we put another 11 wells in the A throughout the entire northern program.
All tremendous wells over 1,200 barrels of oil equivalent per day with an average lateral length of about 7,000 feet. Eagle Ford continued to shine with both downspacing and the upper targets.
Results continue to be very encouraging. Continued to export cargoes around the world, both to Europe and to Asia, our processed condensate with significant improved pricing.
We'll continue to increase that amount of barrels exported going into 2015. Also what's important, we've had multiple independent studies support lifting the oil export ban, in addition to the fact that gasoline prices would actually be lowered if we exported oil.
The EIA came out last week, the very positive report in regard to saying that U.S. gasoline prices is governed by Brent oil and by world gasoline prices.
Continued to maintain, obviously, a strong financial flexibility, in addition to the equity offering and also the expected sale of Eagle Ford midstream. Cash on hand of $550 million and we did close Hugoton and Barnett during the quarter for $328 million and $150 million, all to redeploy to the Spraberry/Wolfcamp area.
Now Slide #9, again, on production growth, we had a great quarter, 186,000, 69% liquids. Guidance, 200 to 205 MBOEPD the fourth quarter and already in mid-October, we are over 195,000 barrels equivalent per day.
As we see, we moved up to 75% liquids by 2016. I'll now turn it over to Tim to go over more details of our assets.
Timothy L. Dove
Thanks, Scott. And now that we've completed a pretty substantial drilling program all the way from 2013 into the 9 months of 2014, we have compiled a very substantial set of data on the various zones in the northern Spraberry/Wolfcamp area.
And in fact, we've put 56 wells on production in the Wolfcamp zone, as shown in the table, as well as several in the lower Spraberry Shale as well. You can see on the map, we've had a widespread area of drilling.
We have some areas we still have not yet done any drilling on but will be shortly as we needed to complete 3D seismic before beginning drilling in some of those areas. The main important message here is that we continue to see consistent results on these wells.
The production continues to support very strong EURs and returns. In fact, as Scott alluded to, even in the $70 to $80 oil environment, we're looking at returns in the neighborhood of 40% to 80%.
In terms of the Jo Mill and the Middle Spraberry Shale, you recall in the second quarter, we had some mixed completion issues. Glad to say, looking at the wells we've put on production in the third quarter, they're tracking very well and look a lot stronger reflecting the best wells we had reported on in the second quarter, with Jo Mill tracking about 800,000 BOE and the Middle Spraberry Shale about 700,000 BOE.
Data on our strongest individual wells can be actually seen in yesterday's press release. But as has been our practice in the last several quarters, you'll see on Slide 11, data on all the wells that have been drilled.
And in fact, on Slide 11, we start with a review of all of the Wolfcamp B wells, large data set now, 33 wells in 4 counties. And you can see very consistent results here showing that the Wolfcamp B, we believe, can support EURs from 800,000 to 1 million barrels.
And this data set continues to support the notion of very high returns in the Wolfcamp B. Similarly, as we turn to Slide 12, on Wolfcamp A, Scott mentioned the fact we only had limited amount of data on Wolfcamp A prior to the third quarter, but we have put 11 more wells on production.
And you can see the average of these wells, of all 11, in the red line, and I would consider this to be very strong results. It gives us a lot of confidence in the Wolfcamp A and leads us to the conclusion that the EURs are also in that 800,000 to perhaps, over 1 million BOE on average.
Turning now on Slide 13 to the Wolfcamp D. We've got a couple lines on this graph, and I need to explain what they mean.
If you take a look at the darkest of the purple lines, this is the case in which we're showing all the Tier 1 wells that were drilled, of which there are a total of 11. The lighter purple line has to do with a couple of Martin County wells that we drilled that we consider to be in Tier 2 acreage.
And as prognosed, they did underperform versus the Tier 1 wells. We needed to drill these in order to test our geologic model and to hold acreage.
Obviously, this leads us to the conclusion that certain areas where we have Tier 2 acreage in the D, we will not be drilling in those areas going further. But the main message is our Tier 1 drilling looks very good, and we would call the EUR, still in the range, but 650,000 to, in some cases, over 1 million BOE in different areas of those 4 counties.
Turning now to Slide 14. This is referencing the lower Spraberry Shale, 9 wells now in that data set.
Relatively shorter laterals as is the case in some situations where we have leasehold configuration issues. But you also see a continuation of what has been mentioned in prior calls, which is a different trajectory of production growth than you see in the Wolfcamp as water is drawn off the system.
But nonetheless, in the fullness of time, especially after about 90 days, once these wells have put on production, you show very strong results and consistent results, for that matter, again, with EURs ranging from 650,000 BOE to, again, over 1 million BOE. So very strong results in the Lower Spraberry Shale, as expected.
The next slide shows some of the new data regarding the recent Middle Spraberry Shale and Jo Mill wells that we drilled. Remember, I mentioned earlier, that in the second quarter, we had some completion issues, so we got some mixed drilling results, but much better results here.
If you take a look at, for example, in the blue lines, particularly the dark blue line, this is the Middle Spraberry Shale, drilled in Upton County, relatively short lateral. It's in early days of production but is, in general, looking pretty good.
Similarly, the lighter blue is the Middle Spraberry Shale drilled in Midland County, and it's exhibiting over 650,000-barrel type curve at this point. The Jo Mill tends to be a bit of a different trajectory, showing a little bit more like Lower Spraberry Shale.
And these wells are looking very good, both the red and the green lines over -- a little over 5,000-foot laterals and showing ranges that could be 650,000 up to 800,000 BOE. I'd consider this still to be a relatively small data set, and so we're going to continue to appraise these wells.
Of course, the amount of appraisal we do will be depending upon what our total rig count is. Pretty clearly, we're going to be focusing on the other zones that have been mentioned prior in terms of our focus for 2015.
Turning to Slide 16. Well, I guess, when you look at whether we've had success in execution or not, you should be looking at production.
And I'm very pleased to say we've shown very strong production growth in the quarter. Of course, that's a result of the fact that we expected that due to the back-end loaded nature of the completions with the rig count building only during middle part of the year and going to predominately pad drilling.
Though we did put on 73 wells in the combination of the northern and southern acreage during the quarter, production, 103,000 BOE a day, up substantially with the vast majority of that, as Scott mentioned earlier, being oil. And you can point then to a significant amount of growth in the fourth quarter for exactly the same reasons.
So to me, this graph depicts the fact that we are really hitting on all cylinders from an execution standpoint. Turning to Slide 17.
I'm going to now change to a discussion surrounding our development campaign in the future. It was such a large campaign of development that we have coming over the next several years.
We're taking a very holistic approach to the development, really, in the 10-year horizon. You could see on this particular slide, the various things we have to deal with when it comes to a 10-year program of drilling.
In particular, I'm going to talk about 3 of these that are the subject of the capital raisings that Scott had mentioned, that being gas processing, fuel infrastructure and water. And several of these resources will be dealt with when it comes to this capital being raised.
But the capital's needed upfront over the next several years to prepare to bring this PV, of this total project forward, as drilling accelerates into the future. So I'll touch on several of these in the next slide.
Turning to Slide 18. Obviously, water is a very significant need when you look at the resources required to develop this asset.
One of the main objectives of course, in our case, is to make sure we can bring in relatively attractive water when it comes to cost in terms of its acquisition and transportation. And a large water system will be required to do that.
Obviously, we want to get to a point where we're reducing our reliance and in fact, eliminating our reliance on fresh water at some point in the future. And also, reduce the need for disposal of produced water through increasing our recycling programs.
We're very pleased to note that we have good supply sources in terms of effluent water from both the city of Odessa, and we're finalizing agreement with the city of Midland to deliver upwards 360,000 barrels per day of water -- effluent water, over the next 3 years or so. We've created an entity within Pioneer, with some great employees who are actively working this project.
And we're really making great strides towards making our water availability something that would not be a concern, including drilling our own brackish water wells to buying brackish water from third sources and running several pilots for recycling. So we're really -- I think have a step ahead here when it comes to water.
But one important part of this is shown on Slide 19. That is a very large project that we're beginning to spend money on for the transportation of water, storage, utilization and recycling.
As shown on the cartoon that's depicted on the right, we're going to be building about 100-mile mainline, principally north-south and then going to the southeast, of very large diameter pipe. We'll also be laying fiber optics, cable -- fiber optic cables in the same ditch to, in essence, create what will be a state-of-the-art system in terms of communications and in terms of control with very limited people in the field.
It'll be a world-class system, without a doubt. We'll also need to build feeder lines regarding the new water supply from Odessa and Midland.
And in addition to which, in the future, we'll be drilling -- be buildings subsystems that are out in the field areas to support drilling. And associated with that, frac ponds, some 120 to 150 frac ponds that are built strategically near where the drilling will be occurring.
Anticipate that the total project will be roughly $800 million to $1 billion spent over the next, say, 4 to 5 years. And it'll be built in phases, of course.
The first phase of which is the subject of spending in 2015 and '16. It's basically the mainline system and the feeder lines to the bring in the new water sources in, and it's really the backbone of the system.
We can control subsystems and frac ponds just based on where drilling occurs. And so it will depend upon where we land in terms of the capital budget.
But nonetheless, overall, we're going to be spending probably a minimum of $250 million each over the next 2 years, 2015 and 2016, in this initial phase of the project. Turning to Page 20.
And we really believe, ultimately, the benefits of this are significant. It's obviously critical from the standpoint of the success of the executing on our plans.
But it also will provide us relatively low-cost competitive water to develop the system. In addition to which, we believe the economics of this project are going to be very strong, probably in the neighborhood of 35% IRRs.
One important thing it does is get water out of trucks. It gets trucks off the roads, and you've been in Midland, you know what I'm talking about, it's a dangerous place.
And we need to do everything we can to get trucks off roads out there. And we'll be heading more towards a recycling world that will allow us to utilize our produced water.
Ultimately, again, leading to a conclusion where we're not using any freshwater of any significance. Scott mentioned this, but this is significant.
It's going to save us $500,000 per well. In a 20,000-well campaign that's very impressive.
Turning to Page 21. Two other critical front-loaded capital requirements are in the form of tank batteries and saltwater disposal, on the one hand, and gas processing on the other.
We do have to build very large scale batteries and disposal wells and facilities in order to deal with the very high-volume wells in the Spraberry/Wolfcamp that require that kind of volume. In 2014, for example, we spent about $250 million for these kind of facilities.
We will have built over 30 tank batteries and over 25 saltwater disposal facilities this year. And expect that or more over the next couple of years, probably we'll be spending $300 million each in 2015 and '16 in similar expenditures.
This will be going on for a few more years until we have all of this built out, ready for the significant acceleration of drilling wells and we'll have the tank batteries ready for all this volume. It's easy to calculate, in gas processing, our need for perhaps up to a 200 million cubic feet a day new gas processing facility every 12 to 18 months.
And you can see that occurring already this year. We have 2 new plants coming on, one is already on production, the Edward plant with Atlas.
Another WTG plant coming on in about a month or so. And we have plans, in fact, have already made the orders to build another plant.
In this case, Martin County with Atlas, that will come on December of 2015. Probably we'll need additional plans in 2016, the way it currently looks.
So we're earmarking about $175 million of capital for the next 2 years in total to fund our share of these facilities. And then finally -- turning to Slide 22, sand is just another critical component in the long-term plan.
And we're really, really fortunate to have our Brady sand mine located very close to our field activities. It has about 750,000 tons a year current capacity, very significant reserves behind that of 68 million tons on a proved and probable basis.
So we get multi-decade inventory of sand. And most of that, of course, is used on our own wells, and in fact, in the future, the vast majority will be used only by Pioneer wells.
With our growing needs though, it's very clear we need to go ahead and complete the expansion of this facility. We have a plan in 2015 to spend $125 million to expand capacity to 2.1 million tons.
And that includes storage facilities and some preinvestment to the extent we want to add another expansion in 2 or 3 years. We calculate this to have a very fast payout, because when you consider this mine with sand, the only alternative we would have would be to bring it in from the Midwest.
That is to say, white sand, and the transportation costs and the issues pertaining to logistics of getting the sand down there are very significant. So we think this is a very fast payout project.
Turning to Slide 23, and now really turning away from Permian into Eagle Ford. Here, we continue to see the benefits in the Eagle Ford Shale of our downspacing and staggering program.
In fact, we expect to put about 50 wells on production in the upper targets, as a part of that downspacing and staggering and adding upper Eagle Ford targets. About 35 wells of which have been placed on production so far this year and 18 in the third quarter.
I think we're pleased to say that the upper wells are showing very similar results at least when it comes to early production as compared to their offset lower wells. In fact, you can see in the graph to the right, there are cases, one shown here in Karnes County, a situation where the upper well actually exceeds the volume in the lower well and that of the parent well next door.
So we're very pleased how this program is going. It'll be a large part of our program going forward in 2015 and beyond.
Turning now to Slide 24. Results were very good in the Eagle Ford, in fact, record production of about 47,000 BOE per day.
You'll notice that was not up very substantially from the second quarter. However, it was an expected number, simply because we knew we'd have quite a large line of wells off production due to offset fracs that were being performed.
We probably lost 1,000 barrels a day due to that. And also, we had anticipated a back-weighted POP schedule in the quarter, and that's exactly what happened.
And you can see in our expectations for the fourth quarter that production continues a substantial ramp up to 50,000 to 52,000 BOE per day. So we did put 35 wells on production.
We're doing a great job of utilizing 2-string casing designs and that's saving us somewhere in the neighborhood of $750,000 to $1 million per well. Our optimization program, we've talked about through time, is really working well.
We still see a 20% to 30% increase when it comes to pumping more sand, pumping higher volumes and fluids and changing the spacing in terms of the fracs. The exportation of the Eagle Ford continues.
We're exporting currently about 25% of our volume. Our process condensate, we're actually targeting that to be almost half of our production next year.
We've participated in 6 cargoes during the July and November time frame. And we are seeing pretty substantial increases in pricing related to the export of the condensate, as compared to leaving it in what's a swamped U.S.
market. And incidentally, we will continue to be able to export condensate in the event of a positive sale of our EFS midstream assets.
Turning to Slide 25, this is my final slide. It refers to the fact that we still need a lot of work to be done here to make sure that if we really are in a low-price environment, we are optimizing our returns.
We are actively working with our service providers to seek cost reductions for 2015. All of those contracts are not let yet, so we have a lot of discussion going on to reduce costs as best we can for 2015 and after that.
We will, as you might expect, focus in 2015, in the event we are in a lower cost environment, on only the very best intervals. And as I've mentioned earlier, that's probably seen to be focused on the Wolfcamp B, A, and Lower Spraberry Shale.
And probably deferred drilling in some of the other zones that are quite excellent in terms of how well they're performing, but we have less data and we might as well focus on the highest return wells first in this environment. We're also -- we'll be continuing our optimization testing.
You recall that we, similar to what we did in South Texas, in the Eagle Ford, we've moved that team into the Spraberry/Wolfcamp area to begin the process of optimization early in the campaign of drilling and that's being implemented. We'll continue doing that.
Of course, some science cost we'd probably will try to limit if we're in a lower price environment in 2015. I think it goes without saying that continuous improvement in shale plays is just part of the program.
And as we continue to be working on that, it really amounts to, in our case, identifying and implementing D&C cost reductions. And it comes in a lot of different forms.
I'm not going to go through everything we're doing, but the example would be the same 2-string design concept that were used in Eagle Ford, we're now looking at using and have successfully used in the Southern Wolfcamp area where we've drilled a well as fast as 12 days, which is unheard of in the past. Of course, we're continuing our SIMOPS, simultaneous operations, when it comes to the completions of wells where we're actually putting wells on production at the same time we're drilling out other plugs and so on.
And that's cutting several days, in some cases, about 8 days out of time to get the wells completed. We also have done a lot of work to increase our subsurface understanding and that's helping us to optimize landing zones.
It doesn't just don't stop in terms of cost reduction on capital though. We're doing a lot of work on initiatives when it comes to reducing LOE.
You can see our LOE costs have done phenomenally well. It has to do, first of all, with high volume wells.
But we're also attentive to these costs and, for example, using plunger lifts as opposed to gas lift or ESPs or rod pumps, which are more expensive, where we can do so. So you'll see us continue to pursue these initiatives.
I mean, we would pursue them in a high-price environment and a low-price environment, so it's just something that we do as a part of the shale gain. So I'm going to turn it over now, the call -- turn the call over to Rich for a discussion of our third quarter financials and fourth quarter guidance.
Richard P. Dealy
Thanks, Tim. I'm going start on Slide 26, where we report net income attributable to common stockholders of $374 million or $2.58 per diluted share for the quarter.
It did include noncash mark-to-market derivative gains of $216 million or $1.49. That was primarily a result of our derivative -- value of our derivative portfolio going up, as the oil prices primarily declined and softened during the quarter.
It also included a loss associated with discontinued operations of $37 million or $0.26 per diluted share. This is primarily related to the sale of our Barnett and Hugoton assets as Scott referenced.
So adjusting for those 2 items, we are at $195 million of earnings or $1.35 per share. Looking at the bottom of this slide, where we look at results relative to guidance.
You can see, as Frank mentioned, we had another great quarter being at the top end of production guidance. I won't go through all the line items here, but as Tim mentioned, production costs were at the -- below the guidance really is, and I'll mention it later, but as we bring on horizontal wells and our cost initiatives.
Turning to Slide 27, looking at price realizations. As you guys are aware, we did see softening of prices during the quarter.
So you saw our oil prices were down about 5%, NGLs about 6% and gas prices down about 12%. That was offset some by our derivative position, which you see at the bottom of the slide, where we did have positive results from derivatives during the quarter.
Turning to Slide 28. As Tim mentioned, the production costs are down about 5% to $13.17 for the quarter per BOE, mainly as lower-cost horizontal wells are being placed on production, that is bringing it down.
In addition, we did see with the softening of commodity prices that our production taxes were down for the quarter in addition to base LOE. Turning to Slide 29, liquidity position.
Net debt at the end of the third quarter was $2.1 billion, that did include $550 million of cash on the balance sheet. So we're in excellent financial position at the end of the quarter, that will be further strengthened by the equity offering that we just completed.
And once the Eagle Ford Midstream transaction is completed, that'll strengthen it as well. So excellent financial position for the next couple of years of infrastructure build up and capital plans that we have.
Turning to Slide 30, looking at fourth quarter guidance. We've talked about the production being up significantly in the fourth quarter, again, with our incremental addition of wells in the second half of the year, so 200,000 to 205,000 BOEs per day.
The rest of the items here are generally consistent with what we've shown for past quarters, so I'm not go through each of those, but they're there for your review. So with that, Shannon, I think we'll go ahead and open up the call for questions.
Operator
[Operator Instructions] And we'll take our first question from Doug Leggate with Bank of America Merrill Lynch.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
I have 2 questions, if I may. The first one on the Midstream.
Clearly, the decision to sell the Eagle Ford Midstream, it kind of begs the question with a such a large spend in the Permian, what are your longer-term plans for your midstream assets? Because clearly the MLP value is something to be considered I guess, and I'm just thinking about the scale of investment that you're going to have make.
What is the prognosis for how you think about Midstream going forward? And I have a follow-up, please.
Scott Douglas Sheffield
Yes, Doug. I think, we have seen the benefit of owning -- we've owned this 27% to 30% for over 20 years.
We've seen tremendously the benefit by owning a piece of -- all the processing plants in the Spraberry/Wolfcamp field. Allows us to execute, get tied-in quicker.
And so it's a very, very important integrated piece of our integrated assets out in the Spraberry/Wolfcamp. It's always a possibility way down the road but right now, it's been a tremendous benefit for us to own a piece of every plan and to educate all the various parties just like we do with Atlas.
It took us a couple of years to educate them to get them to start building. We are excited about the target transaction.
It leaves a much stronger, financially stronger MLP owning the assets, which should be able to build quicker and larger plants as we need them.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Okay. Fine.
My follow-up is really about the high grading of the Pioneer capital. So per your prepared remarks, if Pioneer is going to start putting Pioneer dollars, if you like, into the better parts of the play, I mean, we saw what looks like a big step-up in oil mix this quarter for what you did deliver by way of production.
So I'm just kind of trying to figure out, one, what does it mean for the ratable growth targets you've given us, given that you would be targeting higher EURs? And if I may, kind of double barrel the question, what does it mean for your thoughts on using third-party capital to maintain the potential value of the noncore assets that are, obviously, company makers for someone else if you chose to go that route?
Scott Douglas Sheffield
Yes, Doug. Obviously, we're going to wait and come out in early February with our capital budget.
So we have lots of flexibility. It depends on what happens with the Iranian negotiations coming on that would carry November 24, the OPEC meeting on the 27th, what's going to be the price of crude going into our final decisions in late January, early February.
We have extreme flexibility. It's still going to be within that 16% to 21% range, whether we keep rigs flat or whether we add 5 or add 10 rigs, so we have lots of flexibility.
In regard to your second part of your question, referring to...
Timothy L. Dove
Bringing third-party capital in.
Scott Douglas Sheffield
Oh, bringing third-party capital. At this point in time, in the sweet spot in the North, we just don't think, at this point in time, it's worth doing a third joint venture.
It's always an option way down the road. It makes it -- we have found out, through time, it makes it tougher to divest of assets to get people attracted when you do have a joint venture partner.
And so we do not see any -- that as an availability over the next couple of years in our northern acreage because it's great returns. As you can see, we've appraised.
We have sold part of the acreage to the north. There are small pieces that we may look at over time on the fringes to divest.
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
If I could pick up that point on the big infrastructure spend. Can you point us to anything, either in your history of development across different plays or maybe in other places in the industry where a company has led the infrastructure development of a play of this size, including not just the typical midstream things but really the guys -- things that you're focusing on like water and sand?
Timothy L. Dove
Charles, I think, first of all, I don't think there has ever been a shale development of the magnitude we're talking about, considering the shale plays are relatively new in the industry. I mean, you'd have to look at the kind of infrastructure build out and the requirements here as something akin to the North Slope development in the fullness of time.
Now they have different -- we have different needs in shale plays than the North Slope development needed, but that's the scope we're talking about, and so it's something of very -- of significance.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Got it, Tim. That's the way it seemed to me, but I didn't want to presume that you guys were looking at it that way, but it looks like a up.
Timothy L. Dove
It's a lot warmer in West Texas.
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
No polar bears. On a little smaller scale.
The Wolfcamp A, if I go back to think about the way you guys were talking about that, maybe 1 year or 2 years ago, I think there was a concern there that -- I think, you were confident about the oil in place and that sort of thing, but there was a concern about being able to get effective frac containment there. Can you talk about how that's -- with these 11 wells that you've put online, how do you think you've done on that front?
And are you doing anything different in the Wolfcamp A with your frac designs and what you're doing in the Wolfcamp B? And I guess, the natural follow-on to that is given that Wolfcamp A is still in their early innings and is looking so good, is there -- do you think there's more upside there?
Scott Douglas Sheffield
Yes, Charles, you have a good memory. From what we said over about 18 months, 2 years ago.
We were concerned at the time about frac-ing up into the Dean formation. And I think, this -- by bringing on 11 new wells, all great success, microseismic has showed all the fracs were contained within the A.
So very, very positive results. The A does have almost as much oil as the B.
So it allows us really to develop the A throughout the North, just as much as the B. So very, very positive results and still getting great results in the Lower Spraberry Shale.
Operator
And we'll move next to Dave Kistler with Simmons & Company.
David W. Kistler - Simmons & Company International, Research Division
Real quickly, you outlined for us what you expect kind of the rate of return to be from the water investment in your release. Can you give us color on kind of maybe what you expect other investments to generate?
Or maybe refresh our memory in terms of how quickly the payback was on the original sand mine investments or the rate of return on that?
Timothy L. Dove
Yes Dave, I think, when we calculated the original sand mine acquisition, we were looking at a 4- to 5-year payout on that project. We acquired that in 2012.
And I think it's on schedule. Probably 2 or 3 more years to payout.
With the alternative, of course, being, as I mentioned earlier, even regard -- even in regard to our expansion, to have to bring in a large quantity of white sand from the Midwest, which has a lot of complication. Actually, white sand costs at the mine are similar to Brady Brown, but the problem is the costs at least double to bring it in, notwithstanding all the infrastructure issues and logistics that you've heard about with regard to the rail system.
So I think, when you calculate the incremental values associated with the expansion, the expansion is relatively cheaper than the original sand mine. It just has to do with we're not acquiring reserve, we're just building a facility.
So if we spend $125 million or so on that, I calculate the payout to be probably in the neighborhood of 1.5 years. And so, to me, this is a really outstanding investment when you consider we have decades worth of sand.
David W. Kistler - Simmons & Company International, Research Division
Okay. And then, just one, thinking about budgeting for next year.
When you make that budget or as you're going through that process right now, how are you thinking about what kind of improvement you anticipate in well cost and EURs? Or are you going to be using current well cost, current EURs?
And can you refresh us on what you think those are for the budgeting purposes?
Timothy L. Dove
Yes, I think, Dave, right now, I think the plan is, is we're giving instructions to our teams is to use the current well cost, use current EURs, and basically, in that sense, be conservative. I think, if you look at the current well cost, to the extent we're out to 9,000, to 10,000 foot laterals, those wells are costing $9 million to $10 million.
So I think we have some ability to cut that back as we continue our optimization. We're cutting days off wells as we speak.
If you look at this quarter versus last quarter, we didn't give you a lot of color on that. But you'll see incremental improvements.
I think, the question is, as we go further towards new casing designs and other things I mentioned with regard to how to complete the wells more efficiently, you'll see the cost come down. So I think, we've got upside when it comes to the cost.
On EURs, we have not yet set exactly what will be the zones to be drilled, so we don't even have the rig count set, well count set yet because it's something we're in the process of doing and won't discuss even until February. But that said, if we're in the situation we're in today, we're going to be limiting everything other than let's just say Wolfcamp A, B and Lower Spraberry Shale, you would think that our returns and our EURs and our production rates will be better as we high-grade.
We just simply haven't gotten any numbers surrounding that. But as for right now, we're having the teams evaluate that and evaluate what are the best areas, what are the best wells to drill when it comes to economics.
Operator
And we'll move next to Brian Singer with Goldman Sachs.
Brian Singer - Goldman Sachs Group Inc., Research Division
You've talked about a $1.4 billion to $1.6 billion here of new infrastructure CapEx over the next couple of years. And in the context of 16% to 21% growth forecast, should we think about this as a truly one-off or is this a good rate of infrastructure spending, or should it be greater, over a longer-term period for these types of projects or others that may come up?
Arguably, you'll need more water, you'll need more sand, you'll need additional infrastructure over time.
Scott Douglas Sheffield
Yes, Brian, I think, the major expenditure of the water system will be in the next 2 years. The rest of it will be spread out over the 3- or 4-year timeframe.
So that's mostly the main trunk line. And so that's going to occur in '15 and '16.
The sand mine, we could expand it, but it's going to be way down the road, again, several years down the road, so the major expenditure of that. On the processing plants, I think, if we stay in this $70 to $80 world, that you're going to see significant cut back by third-parties.
And that the 12- to 18-month cycle could be pushed back. And so, I think, the processing plants will probably get delayed, not the ones that are coming on in '15 and '16, but that scenario could easily play out that way.
And so we're front-end loading with -- what's going to happen is that if rigs are cut back in the first half of the year, you're not going to see any decline in U.S. production until toward the very, very end of '15.
So I think the U.S. is going to continue to put 1 million barrels a day into the market over 2015.
Permian Basin is a big chunk of it. So I would say, overall, that most of it is going to be '15 to '16.
When you get into '17, '18, like on tank batteries, we'll have built out a lot of our tank batteries, and so you should -- we should be getting into development drilling, then going into existing tank batteries, cutting cost there, too. So I'd say more of it is front-end loaded in '15, '16.
Brian Singer - Goldman Sachs Group Inc., Research Division
Got it. And then, you mentioned in your prepared remarks that you found some limits of the Wolfcamp D zone in Martin County, maybe you could provide more clarity, but it looked like that was probably near the Andrews County border.
And I wanted to see if you regard that acreage as being Tier 2 and a limit solely on the Wolfcamp D or whether you regard that as a limit to the horizontal opportunity across multiple zones?
Timothy L. Dove
Yes, Brian, I'll take it. If you look at the Wolfcamp B mapping that we've done, and we've shown you guys from time to time, it's been about 400,000 acres net that are prospective for the Wolfcamp D on our acreage and only about 10% of that is Tier 2.
That is to say 90% of that is Tier 1. So I think, what we're really saying is we've now well-defined the limits.
We felt like, from our geologic mapping, that we had a pretty good handle on that but that's why you drill the wells, to make sure you can tie to your geologic mapping. And what I said in the prepared remarks is that, naturally, we're going to be focusing on Tier 1 drilling, but we needed to know that, in fact, our modeling was correct and that we could also evaluate where the edges were of, let's say, Tier 1 versus Tier 2, realizing the Wolfcamp D is deeper, so it has more challenges due to costs because it's deeper as well.
Brian Singer - Goldman Sachs Group Inc., Research Division
And so I guess, is that just the edge of the Wolfcamp D or is that the edge of some of the shallower zones as well?
Timothy L. Dove
No, no ,no. Those different zones are in different areas.
I mean, Wolfcamp A and B are basically ubiquitous across the acreage. D is not as ubiquitous across the acreage.
Because we calculate Wolfcamp A and B as having 650,000 acres, and I mentioned just a moment ago, the, say, 90% of 400,000 acres would be Tier 1 in the D.
Operator
And we'll move next to Joseph Allman with JPMorgan.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
So just to clarify on your high-grading, so are you in the process of high-grading your drilling activity now in the better formations or are you just waiting to judge how long this lower price oil market is going to last? And kind of follow-up to that is, are you in the process right now of actually increasing activity, adding rigs, and again, you're just going to wait and see how the oil market plays out to decide if you're going drop some of those?
Timothy L. Dove
The answer Joe on your first question, we are not doing what I would high-grading per se along the lines of what you would do in a low price environment for 2014. I mean, our 2014 deal is baked.
I mean, our plan is baked. All those rigs are currently running and they're running on the wells that we had scheduled from the standpoint of several months ago.
So really, when we talk about high-grading, it's something that's a 2015 event as we crank out a forecast for rig utilization and then what wells are actually going to be drilled. In terms of the rig situation, of course, Scott mentioned, we have sort of a cascading or waterfall approach on rigs.
We do have several new rigs coming in, in 2015, that are contracted, some 10 new rigs. Our evaluation will be whether to have those simply replace existing rigs or -- and let existing rigs go or keep existing rigs and build the rig count.
So that's the optionality surrounding where we see prices when we have to eventually pull the trigger on that decision, realizing it's not a onetime decision. We don't have to decide on January 1 regarding what our rig count is for the year.
We have rigs coming on and off throughout the year, and therefore, we could adjust our rig count on the fly. Obviously, we'd rather have as much of a steady state rig count as we can just to avoid inefficiencies.
But we've got a lot of bites at the apple with what exact number of rigs and wells we're going to drill really throughout next year.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
That's very helpful, Tim. And then, the second question is on just completion designs.
I know that you are seeing improvement by changing the completion designs. Could you describe what you're doing versus what you were doing before?
And where are you seeing the biggest impact? And where are you most optimistic about seeing improvement in productivity with changing the completion designs?
Timothy L. Dove
Well, first of all, as I mentioned during the prepared remarks, our completion designs are really the subject of study right now. We've got quite a few optimization studies going and quite a large number of wells that are involved with that right now.
And we don't have -- we won't have any answers on that basically until probably well into next year as all that's done. But for example, in Martin and Midland County, we are using similar concepts that we use in the Eagle Ford.
So for example, increasing the number of clusters per stage from 4 to 5, and this is actually just reduces the number of stages we're pumping, which is a very big economic effect. We are substantially testing the use of more proppant.
Generally, we were at 1,100 pounds per foot, now we're running it up to 1,700 a test. We actually, in the case of Permian, are reducing fluid volumes to try to save money where actually when you do that, pump the same amount of proppant, you're increasing your proppant concentration, which we think could potentially lead to substantial improvements in EURs and production rates.
And I think we'll know the results of this only, in the fullness of time, into 2015. But what I expect is I don't any reason we wouldn't see similar results as we have seen in the Eagle Ford where we saw 15%, 20%, 30% improvements in EURs by various combinations of these tests, realizing not every zone will be identical in terms of what we believe is optimal for that particular zone.
That's why it's going to take quite a long time before we get to where we really feel like we've got it figured out in every zone.
Joseph D. Allman - JP Morgan Chase & Co, Research Division
And just to follow up your comment on the Eagle Ford. I know you said 20% to 30% increase, but is that a 20% to 30% increase over what already had been an increase because of new completion designs?
And I know it's kind of an ongoing process, there's no clear beginning, no clear baseline, but you've actually been kind of tweaking things and using some of these techniques for a few years, if I understand correctly.
Timothy L. Dove
That's right. I think, if you look at it though, what we have to do is, in the case of this kind of testing to establish a baseline set of wells that then we compare with.
So all we're saying is if you look at the baseline wells that were, in most cases, drilled and completed in the way we were first doing it with the proppant concentrations and with the volumes pumped and with the stage configurations, we now offset that with new wells utilizing these new tests and then can calibrate and calculate how much they've improved. Actually, it's the subject of a recent SPE paper that just went out, I think, last week in October, you may want to search out.
It tells you exactly how this testing is done and it's the precise -- it's precisely the same kind of testing we're using in the Permian.
Operator
And we'll move to our next question from Matt Portillo with TPH.
Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
Just one quick follow-up from your prepared remarks. You mentioned service cost and I was curious how you guys are seeing current trends and potentially any initiatives that you have in place to lower your overall cost structure or service cost specifically heading into 2015?
Timothy L. Dove
Well, I mentioned, we're in the initial stages of that. We let out a substantial number of contracts for all of our services, both capital and operating costs services, in -- for the upcoming year.
Those are the contracts that have been led out, we're evaluating them. I think, essentially, what we're doing is we're going out for a round 2 set of bids to incorporate the fact that commodities appear to have fallen pretty considerably compared to what people were first envisioning.
And take another crack at cost reductions with our major service providers across the board. So I'd say, we're kind of in the initial stages of that.
That won't finalized until we get a little bit further into the year. But nonetheless, we do expect some significant improvements in cost.
Operator
And we'll take our next question from Leo Mariani with RBC.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
I know you haven't set the budget yet, but you clearly indicated you still think we can get to the 16% to 21% growth here over the next couple of years, I guess, corporate-wide. Could you help to maybe put a few parameters on sort of the lower end versus the top end?
Is the lower end kind of the 0 incremental northern Midland rigs and the top end closer to 10%? Can you maybe just kind of help us with some of the thinking around that?
Scott Douglas Sheffield
Yes. I mean, that's the range, Leo.
I'm sorry. I mean, as Tim says, on well cost, we don't know what -- we're going to know in a couple of months what our cost savings are going to be, which is going to have -- it's really that, coupled with what rig count to start the year with.
And so those are the big 2 unknown items, and we've got to wait and see what happens with these 2 events end of November, with the Iran negotiations on nuclear sanctions and, secondly, followed by the OPEC meeting. So those are all big events, we just don't have the data points yet.
So that's why we -- you can take our infrastructure and sort of spread it out over 2 years. You know what the current capital is for 2014 and the current rig count and so you could probably back in if you can.
Timothy L. Dove
That would not incorporate any accelerated drilling, if we would choose to do that.
Scott Douglas Sheffield
Or cost savings.
Timothy L. Dove
Or cost savings.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Right. Okay.
No, that's helpful, for sure. And I guess, you guys talked about high-grading kind of within the northern Midland Basin as a potential outcome at lower oil prices for next year.
Should we also assume that you guys may also try to put a higher percentage of activity in, say, northern Midland versus Eagle Ford or southern Midland, can you maybe talk to that dynamic?
Timothy L. Dove
I think, Leo, everything we're doing is based on what the rates of return are per well. And so I think we'll try to high-grade also essentially along the lines of returns.
It's one thing to say wells where we have the best EURs. What we're really saying to you, we're going to drill the best economic wells that we have.
And we haven't really landed on how many wells that is in which area. We have quite a large number of economic wells in today's environment in the Eagle Ford Shale, needless to say.
Same as true in the southern Wolfcamp area, especially in the northern part of the southern Wolfcamp and certainly in the northern Wolfcamp. So I think, that's really the whole product of what we're talking about here, which is basically a capital allocation exercise towards the best returns.
Richard P. Dealy
And Leo, just another factor on that is, and you know this, we've got a joint venture partner in the southern Wolfcamp, we've got a joint venture partner in the Eagle Ford and those discussions are just going on right now.
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Okay. That's helpful.
And I guess, just to kind of hone in one of the prepared remarks that you all had made here, I know you talked about saving $500,000 a well or maybe a little bit more than that, based on your water system. But I also hear you guys say that you potentially could save another $500,000 from the installation of your saltwater disposal and tank batteries, I just wanted to clarify that?
Scott Douglas Sheffield
Yes, as you know, we are installing larger tank batteries to handle the first group of wells over the next 2 years. As you get into '17, '18 drilling, Leo, you can basically go back in and tie those directly into the existing batteries.
That's what's happening right now in the Eagle Ford. Eagle Ford costs are down because we're going into existing CGPs.
We pretty much have built out all the CGPs in Eagle Ford. So it's the same example, so costs come down.
Operator
And we'll move to our next question from Evan Calio with Morgan Stanley.
Evan Calio - Morgan Stanley, Research Division
Congratulations for really leading the way in condensate exports, and we're seeing our first self-classified condensate exports announced today. I mean, but while it's early, do you see a faster pace to crude exports given the preliminary election outcome last night and kind of any roadmap there with kind of next key catalyst?
And I have a second question.
Scott Douglas Sheffield
Yes, I'm personally getting more optimistic spending a lot of time in D.C., and we'll spend a lot of time over the next few weeks in D.C. It's our #1 priority to get the export ban lifted next year in 2015.
And so with what happened last night, and Senator Murkowski is going to run the Senate Energy Committee. I'm probably much more optimistic that something may happen in '15.
We are making headways on both the Democrat and the Republicans, educating them. So right now, Brent goes to $90, $91 in the out years, WTI stays at $80, $81, flat.
And so if exports are lifted, I would hope that those 2 trends narrow instead of spread out like they are over the next several years, and so U.S. producers can compete with the rest of the world.
And so, I think you'd see a lot of hedging today if WTI had the same strip as Brent going up to $90 a barrel or $91 a barrel over the next several years. So that's the name of the game.
We hope to accomplish it in 2015.
Evan Calio - Morgan Stanley, Research Division
That's great. And my second question, on the longer-term infrastructure spend, maybe just to follow up with Singer's question.
I mean, you clearly map out a moderation of the $700 million to $800 million per annum spend over the next 2 years, yet, any long longer-term guidance as you think about that 10-year plan on an annual spend? And related, with midstream valuations, I mean, why wouldn't you monetize those investments and make infrastructure self-funding on an asset sale basis a couple of years out?
Timothy L. Dove
First of all, if you look at this year, and you can use tank batteries as an example, we spent about $250 million on tank batteries and saltwater disposal. That's a pretty heavy load, going to about $300 million for the next couple of years.
I think, you can see that level go for another couple of years after that and start to come down. And overall, realizing what Scott already alluded to, we don't have another sand mine expansion on the docket probably for a few more years.
We could accelerate it if we needed to. Gas plants will probably decelerate a little bit.
So you're probably getting down, instead of this $700 million to $800 million zone, probably more $300 million or so as you get out in -- or $300 million to $400 million, I'd probably say, counting water in the years 2017, '18. So you'd probably have $300 million to $400 million reduction just because you'll have a lot of the stuff behind you.
Evan Calio - Morgan Stanley, Research Division
Great. And the midstream piece?
Timothy L. Dove
I think, what I would say about that, Scott alluded to this in his commentary a minute ago, and that is, I think, we have to take a look at that. We need to make sure we get all this stuff built in order to be able to execute on our plan.
But several of the assets we're talking about building, this would include water and sand and infrastructure and certain gas processing are MLP-able in the fullness of time. So we'll have to just take a look at that when the time comes.
It certainly may provide an option for us from a capital markets perspective on these assets.
Operator
And we'll move to our next question from John Freeman with Raymond James.
John Freeman - Raymond James & Associates, Inc., Research Division
First thing I wanted to look at, you placed a significantly higher number of wells on production in that Spraberry/Wolfcamp during the quarter than you all had originally expected. You mentioned it was a big acceleration in the southern Wolfcamp.
And then, based on the guidance you all got for POPs in the fourth quarter, it's going to be the first time we've had sort of a sequential decline in POPs in the Spraberry/Wolfcamp. So just assuming kind of base level same level of activity, wouldn't that indicate we'd have a pretty dramatic increase in POPs in Q1?
Timothy L. Dove
Yes, John, I think, first of all, you are right. We did accelerate some costs, mostly because of efficiencies in the southern Wolfcamp area where we're drilling wells faster.
I alluded to that in my earlier commentary. We've actually reduced the number of days on wells and that just accelerates your POP schedule.
And so what you've seen is wells that were otherwise scheduled in the fourth quarter getting done in the last, say, couple weeks of September. So it's one of the reasons why you look at the fourth quarter production in the Spraberry/Wolfcamp and see even further accelerations, because you're going to get the full benefit of that production for the whole quarter in the fourth quarter.
But because of that, the fourth quarter POPs look lower as a result, almost by definition of them being moved from the fourth to the third. And I think the real question for the first quarter is, where -- it's the same question, do we get more of these done in the fourth quarter or do they slip into the first quarter.
So I don't think that we have a lot of color on the first quarter POPs being any significantly different related in the third or fourth quarter.
John Freeman - Raymond James & Associates, Inc., Research Division
Okay. And then, looking at the exporting going from 25% of your Eagle Ford condensate volumes to 50% next year.
You had mentioned, Tim, just it's a pretty substantial difference you're seeing here on the pricing. Can you just sort of quantify that?
Timothy L. Dove
Well, we're really not prepared because there's some confidential issues pertaining to pricing, needless to say. But if we were to sell this stuff in the U.S.
market today only, we would be probably achieving $10.50, $11 off WTI. I can tell you, we're well into the single digits in terms of the discount of WTI compared to that.
So it's been a substantial improvement.
Operator
And we'll take our next question from Eli Kantor with Canaccord Genuity.
Eli J. Kantor - Canaccord Genuity, Research Division
It's been a few quarters since we've seen your gun barrel slide in the Permian Basin. Given the exciting nature of the stack pay potential in the Permian, can you just give us an update on those downspacing and staggered lateral pilots and then getting sealed?
And as a follow-up, how much of your upcoming Permian activity will test the staggered or stacked lateral format? And do you see any variance in communication or interference between wells in the A, B zone versus wells in lower Spraberry, Jo Mill, and middle Spraberry?
Timothy L. Dove
Yes, Eli, we certainly are continuing our testing of various spacing regimes. I think, if you take a look at it when we started with this whole project, we were -- everything was predicated at 140-acre spacing.
It's pretty clear that the results we've shown so far in our own internal testing would say that we can get down to, easily, 100-acre spacing, maybe in some cases a little less than that. So that's going well.
In some of these areas, we're just now beginning to get those results because those are pads that we began drilling the middle part of last year -- of this year, I should say. So it'll be the end of this year before we started seeing a lot more results.
We'll be talking more about that in the fullness of time when we have more data. And when it comes to stacking, the one thing we want to make sure of is that we sort of optimize the production from these pads, and so that means we want to make sure that we have wells off production only a limited amount of time while we frac offset wells.
And so that may lead us to, in certain configurations, for example, drilling a set of B wells before we drill A wells and so on. So I think we're still really learning about that today.
We're learning about what's optimal and the most significant optionality is surrounding making sure that we limit the amount of offset wells that are off production at any given time, as well as make sure that we understand the interference between the wells. Right now, we think, we can easily frac and complete A and B wells, though, in a staggered sense.
Eli J. Kantor - Canaccord Genuity, Research Division
And just as a follow-up, Permian Basin has been one of the most active areas for onshore U.S. E&P acquisition activity.
Given all the liquidity coming into your balance sheet, would you guys look at using the dry powder to potentially take advantage of the recent decline in asset values?
Scott Douglas Sheffield
No. We have -- the acreage values are still high.
We have over 20,000 locations. We've only -- we've purchased very little in 2014, only places where we can buy acreage in the 2,000 to 3,000, 4,000 per acre range to allow us to drill 10,000-foot laterals.
So that's the only area that we may see it. So very little capital doing that, all going into primarily infrastructure and drilling on the return side.
Timothy L. Dove
The only thing I'd add to that, Eli, is we are very active in acreage swaps. So situations where we can make sure that by virtue of swapping acreage with other industry participants to be able to increase our lateral lengths out to, say, 10,000 feet versus 5,000 feet, we're swapping acreage in a lot of scenarios.
Operator
We'll move to our next question from Sven Del Pozzo with IHS.
Sven Del Pozzo - IHS Herold, Inc.
I'd like to know about Brady Brown crush strength versus white sand and if there's any misconception out there about how resistant it is to crushing?
Timothy L. Dove
Yes, Sven, if you look at all the different aspects of sand in terms of what makes it API gravity -- API quality sand, it's things like crush factor and sphericity and roundness and so on. If you take a look at Brady Brown and the crush factor as compared to white sand, it's just slightly less when it comes to the crush factor, but nonetheless, API standard.
That said, we've been using Brady Brown sand in these deeper zones in the Wolfcamp for years and have never had any issue pertaining to any crush factors. And usually, the data would say it's good up to and probably slightly exceeding 11,000 feet TBD.
Sven Del Pozzo - IHS Herold, Inc.
Do you resin coat any of that Brady Brown sand that you've got and how much might that cost?
Timothy L. Dove
We're not resin coating it. Others are.
You have to get with them as what the cost of it is.
Sven Del Pozzo - IHS Herold, Inc.
Okay. And then, just as to the water that's being sourced, the effluent water that's being sourced, what would they have done with that water?
Had they not sold it to you and, I guess, how clean is it when you guys get or what -- do you have to process it further in order to utilize it?
Timothy L. Dove
My understanding is a lot this water is just -- effluent water today is just put on the ground by the municipalities, so it's otherwise being wasted. We will be working with the municipalities to do some water cleanup, so it's ready for our use.
But in principle, that's already built into the economics of the projects.
Sven Del Pozzo - IHS Herold, Inc.
Okay. And is there a way to have a general idea how much it's costing you?
I mean, since they were just going to dispose of it anyway, it would have represented a cost to them. So I mean, this just seems like a win for the municipality as well as for you guys.
Is there any cost you can help us to understand how much it's costing you to buy that water?
Timothy L. Dove
Well, the pricing terms of our contracts are confidential, as you might guess. But suffice it to say, I think it is a great win-win for the municipalities and for us and for the industry that we can otherwise take water that is unusable and converting it to use that makes sense for the entire industry.
And so -- and the municipalities are the beneficiary from a revenue standpoint. So I think it's a long-term win-win.
I can't give you the details, of course.
Operator
And we will take a question from Gil Yang with DISCERN.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
I was wondering if you're going to increase the effort to renegotiate leases so you can drill more horizontal wells and reduce the vertical wells drilling obligation and whether or not the lower price environment are going to help those conversations?
Timothy L. Dove
Yes, Gil, actually, that was the subject in one of the slides that I had in my slide packet, I didn't really mention it. But we are now moving down from we were about 11 rigs vertically down to about 6 here.
Very shortly, we will be at 6 rigs running vertically, of which, 1 of them is drilling water wells for us. I mentioned we're drilling Santa Rosa nonpotable water wells for part of our water supply.
So I think the answer is what we're using is we're using cash basically and relatively limited amount of cash to work with the landowners, the lease -- actually, they're the mineral owners in this case to negotiate ways to avoid this continuous drilling obligation situation as opposed to having to drill vertical wells to do it. And we've been very successful in that regard.
I think, so successful, we're probably be reducing that vertical rig count further as we get into next year. Probably, we'll have essentially 0 vertical rigs running in a couple of years.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Can you give some idea about how that will change your capital efficiency in terms of production per dollar spend? Will that be a noticeable improvement or is that more in the noise?
Timothy L. Dove
Well, I mean, we're just going to be avoiding drilling vertical wells, if that's what you're going with that. And that means we're going to drill that many more horizontal wells, which we think are more efficient from a capital standpoint and from an economic standpoint.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Right. I was just getting an idea of that sufficiency [ph] is a noticeable change to growth or is it more a minor blip?
Timothy L. Dove
Well, I think, it's significant in the sense that the horizontal wells make such larger volumes. The issue is going to be we can drill and produce vertical wells a lot faster and so -- because you get the pad drilling effect on the horizontal campaign.
So it is a tradeoff here. In the long-term, you'd much rather be drilling horizontal wells.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Right. Okay.
And second question for Scott is, in terms of the market share battle with Saudi Arabia, is this just a street fight or just an outright market share issue? Or are there other things going on?
Are there hidden agendas that you can maybe speak to in terms of maybe driving down price in the U.S. so that they can purchase U.S.
assets or just getting the other OPEC guys in line to -- so they all cooperate in terms of controlling the market better? What's the real agenda here?
Scott Douglas Sheffield
No. I think, that's the real agenda.
There's been articles written about whether or not they're trying to hurt the Russians or the Iranians, but you have to realize, OPEC is down to just Saudi Arabia, maybe Kuwait and maybe UAE. But when you're trying to negotiate with the bankrupt Venezuelans or trying to negotiate with the Shia in Iraq and Iran, that's going to be -- it's going to be a lot tougher for OPEC to come to an agreement to cut production.
So the U.S. is still growing over 1 million barrels a day.
Most people has the world growing only 600,000 barrels a day this year because of Europe economy, what China is doing. And so the stimulus, I think, will help long-term, $1 trillion stimulus.
And so prices should recover within the next 2 years. But it's going to be really hard for OPEC, I think, to come some type of agreement just because of the status of these various OPEC countries.
I didn't add Libya. Who do you negotiate with in Libya to cut production?
You got 3 factions, one of them is Al Qaeda-related. So who do you negotiate there to cut production?
So it's a lot tougher than it has been in the past. So it's down to Saudi to cut production, they just don't want to do it.
So it's putting pressure on the U.S. shale oil revolution.
Operator
And there are no further questions in the queue. At this time, I'll turn the call back to the speakers for any additional or closing remarks.
Scott Douglas Sheffield
Again, thank you for listening to our great quarter. We got a great story, a great asset over the next 2 years, so look forward to seeing everybody out on the road.
Thank you.
Operator
That does conclude today's conference. Thank you for your participation.