先鋒自然資源 (PXD) 2014 Q3 法說會逐字稿

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

Pioneer has prepared Power Point 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 and 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.

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 two 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 will 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 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 will open up the call up for your questions. Now I will turn the call over to Scott.

Thanks, Frank. Good morning. On Slide number 3, on our rationale, capital funding, the combination was 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 two years.

As you all know, the price of oil has dropped about $30 a barrel. It is a trillion dollar stimulus per year to the world's 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 US 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 2016 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 US 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 zero rigs, whether it's 5 rigs or whether it's 10 rigs add during the year.

We have tremendous flexibility with our rig contracts, because most of them are on a three-year contract, but we purposely had them expiring a third in 2015, a third in 2016, a third in 2017. It all depends on what oil prices are over the next three 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 two-year period.

The main cost will be $500 million to $700 million for 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 over $500,000 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 the development drilling, we won't have to spend the money on those tank batteries, and save over $500,000 per well.

In addition, we will be several new gas processing facilities will be coming on, we will be expanding our sand mine to almost 3 times for $125 million, and we're doing all this over the next two 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 and probably the largest oilfield in the US and the world class Spraberry/Wolfcamp oilfield.

Slide number 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 is 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 the description, I won't go over that detail. Probably the most important item is our forecasted cash flow to Pioneer is a little bit 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 building to export process condensate remains unaffected by this expected divestiture. In addition, we have no plans to divest our Eagle Ford Shale upstream assets.

Slide number 5, just to summarize what's happened in Pioneer over the last three years, we have successfully transformed our Spraberry/Wolfcamp acreage from a vertical play into a world class horizontal play on our 825,000 acres, appraising six highly respective stacked intervals, with strong EURs and internal rate of returns with very high oil content. We've grown our resource potential from 3.1 billion barrels over 3 times 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 with Sinochem, developed a world class premier pressure pumping company, in addition to acquiring the fourth largest sand mine in the US, which is only about a three-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 B 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 midCush 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 2011 to 2014, from 3 billion to 9.6 billion barrels of oil equivalent. And the largest oilfield in the US today, 3 times.

Slide number 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 in second quarter, again in third quarter at 186,000 barrels a day, up 10,000. The oil production is 90% of that, up 9000. 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're more than double 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 of 16 to 21 over the next two years.

We have great hedges in place also, probably the best hedges in place among the industry in 2015 and 2016 on oil. And again, we're 100% protected on the midCush differential, as I mentioned earlier.

Slide number 18, 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 one well on the one good A well, and we put another 11 wells in the A throughout the entire Northern program, all tremendous wells, over 1200 barrels of oil equivalent per day, average lateral length of about 7000 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 process condensate with significant improved pricing. We will 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 EI came out last week. The very positive report in regard to saying that US gasoline prices is governed by Brent oil and by world gasoline prices.

Continue to maintain, obviously, 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 redeployed through the Spraberry/Wolfcamp area.

Slide number 9, again, on production growth, we had a great quarter, 186,000, 69% liquids. Guidance, 200,000 to 205,000 for the fourth quarter and already in mid-October, over 195,000 barrels of oil equivalent per day. As you see, we move up to 75% liquids by 2016. I will now turn it over to Tim to go over in more details of our assets.

Thanks, Scott. Now that we've completed a pretty substantial drilling program all the way from 2013 into the nine 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 done any drilling on, but will be shortly, as we need 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 mix completion issues. Glad to say looking at the wells we put on production in the third quarter, they are 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 will see on Slide 11 data on all the wells that have been drilled. In fact, on Slide 11, we start with a review of all of the Wolfcamp B wells, large data set now with 33 wells in four counties.

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 in the Wolfcamp A, Scott mentioned the fact we only had limited amount of data in the 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 these 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, 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 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 into full 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 a range, but 650,000 to in some cases over a million BOE, in different areas of those four counties.

Turning now to Slide 14, this is referencing the lower Spraberry shale. Nine wells now in that data set. Relatively shorter laterals, as is the case in some situations where we have lease hold 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 been 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 a 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, as I mentioned earlier, in 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, 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 barrels 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. These wells are looking very good. Both the red and the green lines, a little over 5000-foot laterals and showing ranges that could be 650,000 up to 800,000 BOE.

I would consider this still to be a relatively small data set. So we're going to continue to appraise these wells. Of course the amount of appraisal we do would 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. 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 and with the rig count building only during the middle part of the year and going to predominantly pad drilling. But 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 reason. 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 a 10-year horizon. You can 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 three of these that are the subject of the capital raisings that Scott had mentioned, that being gas processing, field infrastructure, and water. And several of these resources will be dealt with when it comes to this capital being raised.

But the capital is 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 will 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 costs, 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 limiting our reliance on freshwater 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 water from both the city of Odessa and we're finalizing an agreement with the city of Midland to deliver upwards of 360,000 barrels per day of water, effluent water, over the next three 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, buying brackish water from third sources and running several pilots for recycling. So we're really I think a step ahead here when it comes to water.

But one important part of this, as 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 a 100-mile main line, principally north-south, then going to the southeast, a very large diameter pipe.

We will also be laying fiberoptics, fiberoptic 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 will be a world class system without a doubt. We will also need to build feeder lines regarding the new water supply from Odessa and Midland, and in addition to which, in the future, we will be drilling -- building 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 the total project will be roughly $800 million to $1 billion spent over the next, say, four to five years. And it will be built in phases, of course.

The first phase of which is the subject of spending in 2015 and 2016. It's basically the main line system and the feeder lines to bring in the new water sources, and it's really the back bone of the system.

We can control subsystems and frac ponds based on where drilling occurs. 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 of the next two years, 2015 and 2016, in this initial phase of the project.

Turning to Page 20, we really believe ultimately the benefits of this are significant. It's obviously critical from the standpoint of the success of 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, gets trucks off the roads, and if you've been in Midland, you will know what I'm talking about. It's a dangerous place. We need to do everything we can to get trucks off roads out there.

And we will be heading more towards a recycling world that will allow us to utilize our produced water. Ultimately, again, leading to a conclusion we're not using any freshwater of any significance.

Scott mentioned this, but this is significant, because 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 volume.

In 2014, for example, we spent about $250 million for these facilities. We will have built over 30 tank batteries and over 25 saltwater disposal facilities this year, and expect that or more in the next couple of years, probably will be spending $300 million each in 2015 and 2016 and 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 will have the tank batteries ready for all of 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 two new plants coming on. One is already on production, the Edward plant, with Atlas, another WTG plant coming on 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 the summer of 2015. Probably will need additional plants in 2016, the way it currently looks. So we're earmarking about $175 million of capital for the next two 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 of current capacity, very significant reserves behind that of 68 million tons on a proved and probable basis.

We've got multidecades inventory of sand. And most of that, of course, is used on our own wells and, in fact, going 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 two or three years.

We calculate this to have a very fast payout. Because when you consider this volume of 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 and getting the sand down there are very significant. So we think this is a very fast payout project.

Turning to Slide 23, turning away from Permian into Eagle Ford, 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 Shale 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 of a situation where the upper well actually exceeds the volume and the lower well and that of the parent well next door.

So we're very pleased with how this program's going. It will be a large part of our program going forward in 2015 and beyond.

Turning now to Slide 24, results are very good in the Eagle Ford. In fact, record production of about 47,000 BOE per day.

You will notice that was not up very substantially from the second quarter. However, it was expected number, simply because we knew we would have quite a large volume of wells off production due to offset fracs that were being performed. We probably lost a thousand 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. You can see in our expectations for the fourth quarter that production continues at a substantial ramp up to 50,000 to 52,000 BOE per day.

We did put 35 wells on production. We're doing a great job of utilizing two-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're still seeing a 20% to 30% increase when it comes to pumping more sand, pumping higher volumes of 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 six cargoes during the July-to-November timeframe. And we are seeing pretty substantial increases in pricing related to the export of the condensate as compared to leaving it in with a swamped US 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're 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 discussions 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 at a lower cost environment on only the very best intervals. As I mentioned earlier, that's probably focused on the Wolfcamp B, A and lower Spraberry shale. And probably defer drilling in some of the other zones that are quite excellent in terms of how they are performing, but we have less data and might as well focus on the highest return wells first in this environment.

We also will continue our optimization testing. You will recall that similar to what we did in South Texas and the Eagle Ford, we 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 will continue doing that.

Of course some science costs, we probably will try to limit if we're in a lower price environment in 2015. I think it goes without saying that the 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 DNC 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 two-string design concept we're using at Eagle Ford, we're 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 simultaneous operations when it comes to completions of wells. We're actually putting wells on production at the same time we're actually drilling out other plugs and so on, and that's cutting several days. In some cases, about eight days out of the 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 stop in terms of cost reduction on capital, though. We are doing a lot of work on initiatives when it comes to reducing LOE.

You can see our LOE costs have done phenomenally well. Has to do, first of all, with high volume wells, but we're also attentive to these costs. For example, using plunger lifts as opposed to gas lift or ESPs or rod pumps, which are more expensive where we can do so.

You will see us continue to pursue these initiatives. We 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 game. I'm going to turn it -- turn the call over to Rich for a discussion of our third quarter financials and fourth quarter guidance.

Thanks, Tim. I'm going to 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. That did include noncash mark to market derivative gains of $216 million, or $1.49. I thought it was primarily a result of value of our derivative portfolio going up, as 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. Adjusting for those two items, we were at $195 million of earnings, or $1.35 per share.

Looking at the bottom of the slide where we look at results relative to guidance, you can see, as Frank mentioned, we had another great quarter, being the top end of production guidance. I won't go through all the line items here, but as Tim mentioned, production costs were below the guidance really, and I will 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 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, which 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 will strengthen it as well. So excellent financial position for the next couple of years of infrastructure buildout 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 are generally consistent what we've shown for past quarters, so I'm not going to go through each of those, but they are there for your review. So with that, Shannon, I think we will go ahead and open up the call for questions.

(Operator Instructions)

We will take our first question from Doug Leggate of Bank of America Merrill Lynch.

Thank you. Good morning, guys. Sounds like you might be traveling today, so I appreciate you still making time for the call.

I have two questions, if I may. The first one in the midstream, clearly, the decision to sell the Eagle Ford Midstream, it begs the question with 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 to make.

What is the prognosis for how you think about Midstream going forward? And I have a follow-up, please.

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 the processing plants in the Spraberry/Wolfcamp field, allows us to execute, get tied in quicker. And so it's a very, very important integrative 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 of the various parties, just like we did with Atlas. It took us a couple 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.

Okay. Thank you for that. And my follow-up is really about the high grading of the Pioneer capital.

So per your prepared remarks, if Pioneer's going to be putting Pioneer dollars, if you like, into the better parts of the play. We saw what looks like a big step-up in oil next this quarter for what you did deliver by their production.

So I'm just trying to figure out, what does it mean for the, the rateable gold star you've given us, given you would be targeting higher EURs. And if I may double barrel the question, what does it mean for your thoughts on using third party capital to maintain the potential value of the non-core assets that obviously company makers for someone else, if you chose to go that way. I will leave it there. Thank you.

Doug, obviously we're going to wait and come out in early February with our capital budgets, so we have lots of flexibility. It depends on what happens with the Iranian negotiations coming on with Kerry November 24, the OPEC meeting on the 27, 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 --

Bringing third party capital in.

Oh, bringing third party capital -- at this point in time on 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 attractive when you do have a joint venture partner, and so we do not see any of that as an availability over the next couple years.

In our Northern acreage, because it's grade 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.

All right, fellows. Congrats on a great quarter. Thanks again.

Thanks.

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

Good morning, gentlemen. 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 the things you're focusing on, like water and sand.

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. You would have to look at the infrastructure buildout and the requirements there as something akin to the north slope development in the fullness of time.

Now, they have -- 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.

Got it, Tim. Thanks. 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--

It's a lot warmer in West Texas.

No polar bears, huh? On a little smaller scale, the Wolfcamp A, if I go back to think about the way you guys were talking about that maybe a year or two years ago, I think there was a concern there that I think you were confident about the oil in place and that 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? 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, given that Wolfcamp A is still in the early innings and looking so good, do you think there is more upside there?

Yes. Charles, you have a good memory from what we said about 18 months, two years ago. We were concerned at the time about fracking up into the Dean formation.

I think by bringing on 11 new wells, all great success, micro seismic 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.

Okay. Thank you for that detail, Scott.

And we will move next to Dave Kistler with Simmons & Company.

Good morning, guys.

Hi, Dave.

Real quickly, you outlined for us what you expect the rate of return to be from the water investment in your release. Can you give us color on maybe what you expect other investments to generate or maybe refresh our memory in terms of how quickly the payback was on the sand, original sand mine investment or the rate of return on that?

Dave, I think when we calculated the original sand mine acquisition, we were looking at a four to five-year payout on that project. We acquired that in 2012, and I think it's on schedule. Probably two or three more years to pay out, with the alternative being, as mentioned earlier, even in regard to our expansion, to have to bring in a lot 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 cost at least doubles to bring it in, notwithstanding all the infrastructure issues and logistics that you've heard about with regard to the rail system. We calculate the incremental values associated with expansion.

The expansion is relatively cheaper than the original sand mine. It just has to do with not acquiring reserves. We're just building a facility.

So if we spent $125 million or so on that, I calculate the payout to be probably in the neighborhood of a year and a half. And so to me, this is a really outstanding investment when you consider we have decades worth of sand.

Okay. Appreciate that. One, thinking about budgeting for next year, when you make that budget issue, going through that process right now, how are you thinking about what improvement you anticipate in well costs and EURs? Or are you going to be using current well costs, current EURs, and can you refresh us on what you think those are for the budgeting purposes?

I think, Dave, right now, I think the plan is we're giving instruction to our teams, to use the current well costs, use current EURs and basically in that sense be conservative. I think if you look at the current well costs, 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 will see incremental improvements.

I think the question as we go further towards new casing designs and other things I mentioned with regard to how to complete the wells more efficiently, you will see the costs come down. So I think we've got upside when it comes to the costs.

On EURs, we have not yet set exactly what will be the zones to be drilled. So we don't have the rig counts set yet, well counts set yet, because it's something we're in the process of doing. 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 our returns and our EURs and our production rates would be better as we high grade.

We haven't simply gotten the numbers around that. 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.

Great. Appreciate that, guys.

We will move next to Brian Singer with Goldman Sachs.

Thank you. Good morning.

Hi, Brian.

You've talked about a $1.4 billion to $1.6 billion of new infrastructure CapEx in the next couple of years. In the context of 16% to 21% growth forecast, should we think about this as a truly one-off, or is this is a good rate of infrastructure spending, or should it be greater overall longer-term period for these types of projects or others that may come up? Arguably you will need more water, need more sand, need more additional infrastructure over time.

Brian, I think the major expenditure in the water system will be in the next two years. The rest of it will be spread out over the three or four-year timeframe, so that's mostly the main trunk line.

So that's going to occur in 2015 and 2016. 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, you're going to see significant cutback by third parties, and that the 12 to 18-month cycle could be pushed back. So I think the processing plants will probably get delayed, not the ones that are coming on in 2015 and 2016, but that scenario could easily play out that way. And so we're front end loading with -- what's going to happen is if rigs are cut back in the first half of the year, you're not going to see any decline in US production until toward the very, very end of 2015.

So I think the US is going to continue to put a million barrels a day into the market over 2015. Permian Basin's a big chunk of it. So I would say overall that most of it's going to be 2015 to 2016.

When you get into 2017 and 2018 on tank batteries, we will have built out a lot of our tank batteries, and so you should -- we should be getting in development drilling. Been going into existing tank batteries, cutting costs there, too. So I would say more of it is front end loaded in 2015, 2016.

Got it, thanks. 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 it was probably near the Andrews County border. I want 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.

Brian, I think if you look at the Wolfcamp D mapping that we've done, and we've shown you guys from time to time, we have 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's Tier 1. I think what we're really saying is we've now well-defined the limits.

We felt like from our geologic mapping we had a pretty good handle on it, but that's why you drill the wells, to make sure you can tie to geologic mapping. What I said in the prepared remarks is naturally we're going to be focusing on Tier 1 drilling, but we need to know that in fact our modeling was correct and that we could also evaluate where the edges were of the say Tier 1 versus Tier 2, realizing the Wolfcamp D is deeper,. So it has more challenges to do with the costs, because it's a deeper well.

I guess my question is, is that the edge of the Wolfcamp D or is that the edge of some of the shallower zones as well?

No, no, different zones are in different areas. The Wolfcamp A and B are basically ubiquitous across the acreage. D is not, 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.

Great. Thank you.

And we will move next to Joseph Allman with JPMorgan.

Thank you, operator. Good morning, everybody.

Hi, Joe.

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's going to last? And follow-up to that is are you in the process right now of actually increasing activity, adding rigs, and again you're going to wait and see how the oil market plays out to decide if you're going to drop some of those?

The answer, Joe, on the first part of your question, we are not doing high grading per se, along the lines of what you would do in a low-price environment for 2014. Our 2014 deal is baked. Our plan is baked.

All those rigs are currently running, and they are 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 actually are going to be drilled.

In terms of the rig situation, of course Scott mentioned, we have a cascading or water fall 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 one-time decision. We don't -- have to decide on January 1st regarding what our rig count is for the year. We have rigs coming on and off throughout the year, and therefore, we can adjust our rig count on the fly.

Obviously, we would 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. Exact number of rigs and wells we're going to drill really throughout next year.

That's very helpful, Tim. And a second question is just on 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 change in the completion designs?

Well, first of all, as I mentioned to you, as 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 used in the Eagle Ford. So for example, increasing the number of clusters per stage from four to five, and this actually reduces the number of stages we are pumping, which is a very big economic effect.

We are substantially testing the use of more profit. Generally, we were at 1100 pounds per foot. Now we're running it up to 1700 a test.

We actually in the case of Permian, are reducing fluid volumes to try to save money. We're actually when you do that, pump the same amount of profit, you're increasing your profit concentration, which we think can potentially lead to substantial improvements in EURs and production rates.

And I think we will know the results of this only in the fullness of time into 2015. But what I expect is I don't see any reason we wouldn't see similar results as we have seen in the Eagle Ford, where we saw it's 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.

And just to follow up on 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? I know it's an ongoing process. There's no clear beginning or no clear baseline. But you've actually been tweaking things and using some of these techniques for a few years, if I understand correctly.

That's right. I think if you look at it, though, what we'd have to do in the case of this testing is establish a baseline set of wells that then we compare with. All we're saying is if you look at the baseline wells that we're, in most cases, drilled and completed and the way we were first doing it with the profit concentrations and with the volumes pump and with the stage configurations, we now offset that with new wells, utilizing these new tests and they can calibrate and calculate how much they have 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 exactly how this testing is done. It's precisely the same testing we're using in the Permian.

All right. Very helpful. Thank you.

And we will move to our next question from Matt Portillo with TPH.

Good morning.

Hi, there.

Good morning.

Just one quick follow-up from your prepared remarks. You mentioned service costs. I was curious how you guys are seeing current trends and potentially in initiatives that you have in place to lower your overall cost structure or service costs specifically heading into 2015.

I mentioned we were in the initial stages of that. We let out a substantial number of contracts for all of our services, both capital and operating cost services for the upcoming year. That's -- those contracts have been let out. We're evaluating them.

Essentially what we're doing is going 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 taking another crack at cost reductions with our major service providers across the board.

So I would say we're in the initial stages of that. It won't be finalized until we get further into year. Nonetheless, we do expect some significant improvements in costs.

Great. Thank you very much.

And we will take our next question from Leo Mariani with RBC.

Hi, guys. 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 years, I guess corporate-wide. Could you help to maybe put a few parameters on the lower end versus the top end?

Is the lower end the zero incremental Northern Midland rigs and the top end closer to 10? Can you just help us with some of the thinking around that?

Yes, that's the range, Leo. I'm sorry. As Tim says on well costs, we don't know -- we're going to know in a couple 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 two unknown items. We got to wait and see what happens with these two events in November with the Iran negotiations on nuclear sanctions and secondly, followed by the OPEC meeting. Those are all big events. We just don't have the data points yet.

That's why you can take our infrastructure and spread it out over two years. You know what the current capital is for 2014 and the current rig count. And so you can probably back in, if you can.

Okay.

That would not incorporate any accelerated drilling if we would choose to do that.

No.

Or cost savings.

Or cost savings.

Right. That's helpful, for sure. And I guess you guys talked about high grading within the Northern Midland basin, as a potential outcome, lower oil prices for next year should.

We also assume that you guys may also try to put a higher percentage of activity in Northern Midland versus Eagle Ford or southern Midland. Can you maybe talk to that dynamic?

I think, Leo, everything we're doing is based on where the rates of return are per well. I think we will try to high grade also essentially along the lines of returns.

It's one thing to say wells where we have the best EURs. We're really saying we're going to drill the best economic wells that we have. We haven't really landed on how many wells that is in which areas.

We have quite a large number of economic wells in today's environment in the Eagle Ford Shale, needless to say. Same is true in the southern Wolfcamp area, especially 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, which is basically a capital allocation exercise towards the best returns.

And Leo, just another factor in 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 Eagle Ford. And those discussions are just going on right now.

Okay. That's helpful. And I guess just to hone in one of the prepared remarks that you all had made here, I know you talked about saving 500,000 a well, maybe a little bit more than that based on your water system.

Did I also hear you guys say that you could potentially could save another 500,000 from the installation of your saltwater disposal and tank batteries? Just wanted to clarify that.

Yes. As you know, we are installing larger tank batteries to handle the first group of wells over the next two years. As you get into 2017, 2018 drilling, Leo, you can basically go back in and tie those directly into the existing batteries. It's what's happening right now in Eagle Ford.

The Eagle Ford costs are down because we're going into existing CGPs. We pretty much have built out all the CGPs in Eagle Ford. It's the same example, so costs come down.

All right. That's helpful. I appreciate it, guys. Thanks.

We will move to our next question from Evan Calio with Morgan Stanley.

Good morning, guys. Congratulations for leading the way in condensate exports, and we're seeing our first self-classified condensate exports announced today.

But while it's early, do you see a faster pace to crude exports, given the preliminary election outcome last night and any road map there with next key catalyst? And I have a second question. Thanks.

I'm personally getting more optimistic, spending a lot of time in DC. And we will spend a the lot of time over the next few weeks in DC. That's our number one 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 2015. We are making headway on both the democrat and 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 two trends narrow instead of spread out, like they are, over the next several years. And so US producers can compete with the rest of the world.

So I think you would see a lot of hedging today if WTI had the same strip as Brent, going up to $90 a barrel or $91 a barrel in the next several years. So that's the name of the game. We hope to accomplish it in 2015.

That's great. My second question, on the longer-term infrastructure spend, maybe just a follow-up with Singer's question. You clearly map out a moderation of the $700 million to $800 million per annum spend over the next two years.

Any longer-term guidance as you think about that 10-year plan on an annual spend? And related with midstream valuations, why wouldn't you monetize those investments and make infrastructure self-funding on an asset sale basis a couple years out? Thanks.

First of all, if you look at this year, you can use tank batteries as an example, we spent about $250 million on tank batteries and saltwater disposals. That's a pretty heavy load, going to about $300 million for the next couple of years. I think you can see that load go for the next couple years and start to come down.

Overall, we're realizing, and Scott already alluded to, we don't have another sand mine expansion on the docket for probably a few more years. We could accelerate if we needed to. Gas plants, we will probably decelerate a little bit.

You're probably getting down, instead of this $700 million to $800 million zone, probably more $300 million or so as you get out, out in -- or $300 million to $400 million, I would probably say, counting water in the years 2017, 2018. So you probably have $300 million to $400 million reduction, just because you will have a lot of the stuff behind you.

Great. And the Midstream piece?

I think what I would say about that, and Scott alluded to this in his commentary a minute ago, and that is I think we will have to take a look at that. We need to make sure we get all some stuff built in order to execute our plan.

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. We will have to take a look at that when the time comes. It certainly may provide an option for us on the Capital Markets perspective on these assets.

Great. Thank you.

And we will move to our next question from John Freeman with Raymond James.

Hi, guys. First thing I wanted to look at, you placed significantly higher number of wells on production at 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 a sequential decline in POPs in the Spraberry/Wolfcamp. So just assuming base level, same level of activity, wouldn't that indicate we would have a pretty dramatic increase in POPs in Q1?

John, I think first of all, you are right. We did accelerate -- mostly because of efficiencies in the southern Wolfcamp area where we're drilling wells faster. I alluded to that earlier in my commentary.

We've actually reduced the number of days on wells and that accelerates your pop schedule. What you've seen is wells 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, fourth quarter POPs looked lower as a result, almost by definition being moved to the third.

And I think the real question for the first quarter, the same question, do we get more of these done in the fourth quarter or they slip into the first quarter? So I don't think we have a lot of color on the first quarter POPs being any significantly different really than the third or fourth quarter.

Okay, and then looking at the exporting going from 25% of your Eagle Ford condensate volumes to 50% next year, you had mentioned, Tim, it's a pretty substantial difference you're seeing here on the pricing. Can you just quantify that?

Well, we're really not prepared because there's some confidential issues pertaining to pricing, needless to say. If we were to sell this stuff in the US 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 the WTI compared to that. So it's been a substantial improvement.

Great. I appreciate it, guys. Thanks a lot.

And we will take our next question from Eli Kantor with Canaccord Genuity.

Hi, good morning, guys.

Hi.

It's been a few quarters since we've seen your gun barrel slide in the Permian Basin. Given the exciting nature of the stock pay potential in the Permian, can you just give us an update on those downspacing and staggered lateral pilots?

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?

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, everything was predicated 140-acre spacing.

It's pretty clear 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 will be the end of this year before we start seeing a lot more results. We will be talking more about that in the fullness of time when we have more data.

When it comes to stacking, the one thing we want to make sure of is we optimize the production from these pads. So that means that we want to make sure that we have wells off production, only 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 in a given time, as well as make sure that we understand the interference between the wells. Right now, we think we can easily fracking complete A and B wells in a staggered sense.

Thanks, Tim. And just as a follow-up, Permian Basin has been one of the most active areas for onshore US E and 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?

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, 4000-per acre range to allow us to drill 10,000-foot laterals. So that's the only area that we may see, so very little capital doing that, all going into primarily infrastructure and drilling on the return side.

The only thing I would add to that, Eli, 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 5000 feet, we're swapping acreage in a lot of scenarios.

Thanks, guys. Nice quarter.

And we move next to Gil Yang with DISCERN.

Gil, are you there?

Gil, please check your mute function. Hearing no response, we will move to our next question from Sven Del Pozzo with IHS.

Good morning. I would 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.

Yes, if you look at all the different aspects of sand in terms of what makes it API quality sand, it's things like crush factor and sphericity and roundness and so on. If you take a look at Brady round on the crush factor as compared to white Sands, 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.

Do you resin coat any of that Brady Brown sand that you've got? And how much might that cost?

We're not resin coating it. Others are. You have to get with them as to what the cost of it is.

Okay. 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 how clean is it when you guys get it, or what do you have to process it further in order to utilize it?

My understanding is a lot of this water is, effluent water today is just put on the ground by the municipality, 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.

Okay, and is there a way to have a general idea of how much, 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 seems like a win for the municipality, as well as for you guys. Is there any costs you can help us to understand how much it's costing you to buy that water?

Well, the pricing terms of our contracts are confidential, as you might guess. Suffice it to say, 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 a 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.

Okay. Thanks, Tim. Bye-bye.

And we will take a question from Gil Yang with DISCERN.

Hi. Let's see if I can get this right this time. Can you hear me?

Yes. Your phone is now working.

All right. Sorry about that. I was wondering if you are 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 parameters help those conversations.

Gil, actually that was the subject of one of the slides that I had in my slide pack. I didn't really mention it. But we are now moving down from where we were, about 11 rigs vertically to about six shortly.

Very shortly we will be at six rigs running vertically, of which one of them is drilling water wells for us. I mentioned we're drilling Santa Rosa non-potable water wells for part of our water supply.

I think the answer is what we're using cash basically in relatively limited amount of cash to work with the land owners, the lease -- actually, 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 will probably be reducing that vertical rig count further as we get into the next year. Probably we will have essentially zero vertical rigs running in a couple of years.

Can you give some idea about how that will change your capital efficiency in terms of production per dollars spent? Will that be a noticeable improvement or is that more in the noise?

Well we're just going to be avoiding drilling vertical wells, if that's where you're going with that. And that means we will drill that many more horizontal wells, which we think are more efficient from a capital standpoint and from an economic standpoint.

Right, right. I was trying to get an idea of that, if you see a noticeable change to growth or more a minor blip.

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 trade-off here. In the long-term, you would much rather be drilling horizontal wells.

Right. And second question for Scott is in terms of the market share battle with Saudi Arabia, is this just, is this a street fight or is this an outright market share issue?

Or are there other things going on, hidden agendas that you can maybe speak to in terms of maybe driving down prices in the US so that they can purchase US assets, or just getting the other OPEC guys in line so they all cooperate in terms of controlling the market better? What's the real agenda here?

I think that's the real agenda. There's been articles written about whether or not they are trying to hurt the Russians or the Iranians. But you have to realize OPEC is down to just Saudi Arabia, maybe Kuwait, maybe UAE.

But when you're trying to negotiate with the bankrupt Venezuelans or trying to negotiate with the Shiite in Iraq and Iran, it's going to be a lot tougher for OPEC to come to an agreement to cut production. So the US is still growing over a million barrels a day. Most people have 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, a trillion dollar stimulus. And so prices should recover within the next two years, but it's going to be really hard for OPEC, I think, to come to some type of an agreement just because of the status of these various OPEC countries.

In Libya, who do you negotiate with in Libya to cut production? You got three factions. One of them's Al-Qaeda-related, so who do you negotiate there to cut?

It's been tougher than in the past. It's down to Saudi to cut production. They just don't want to do it, so it's putting pressure on the US shale oil revolution.

All right, thanks.

And there are no further questions in the queue. At this time, I will turn the call back to the speakers for any additional or closing remarks.

Again, thank you for listening to our great quarter. We got a great story, a great asset over the next two years, to look forward to seeing everybody out on the road. Thank you.

That does conclude today's conference. Thank you for your participation.