先鋒自然資源 (PXD) 2018 Q1 法說會逐字稿

Good day, everyone, and welcome to Pioneer Natural Resources First Quarter Conference Call. Joining us today will be Tim Dove, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President, Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings and Webcasts. This call is being recorded. A replay of the call will be archived on the Internet site through May 28, 2018.

The company's comments today will include forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in the future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's new release on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to the Pioneer's Senior Vice President, Investor Relations, Frank Hopkins. Please go ahead, sir.

Thanks, April, and good day, everyone, and thank you, again, this quarter for joining us. I'm going to briefly review the agenda for today's call. Tim's going to be up first. He'll provide the financial and operating highlights for the first quarter of 2018 and give a quick overview of what expectations are for the remainder of the year. He's also going to highlight our continuing strong horizontal well performance in the Permian Basin and that will be followed by a review of Pioneer's template for enhancing shareholder value.

After Tim concludes his marks, Rich will update you on our firm transportation commitments to move oil from Midland to the Gulf Coast, and the financial benefits we're receiving from growing refinery and export sales in this market. He'll also discuss the agreements we have in place to ensure that our gas production flows out of the Permian. Rich will also cover the first quarter financials and provide earnings guidance for the second quarter. And after that, we'll open up the call for your questions.

Before turning the call over to Tim, as many of you know, this is going to be my last conference call. I'll be retiring from Pioneer at the end of May. I want to take this opportunity to say thank you to all the investors and analysts that I have had the privilege to interact with during my past 13 years at Pioneer. It's been a truly rewarding experience, and I can only hope that my successor, Neal Shah, will enjoy leading the IR team at Pioneer as much as I have.

And with that, Tim, over to you.

Good morning, everybody, and thanks, Frank. I'd certainly like to follow up on your commentary by saying all of us here would like to express our sincere gratitude to you for all the years that you've been our top IR executive for 13 years. And as you joined me, as we both know, and our management team on more than 50 quarterly calls, on a myriad, countless investor conferences and meetings over the years. You've been the consummate professional in your craft, and for that, we're very appreciative. You've been voted the top IR executive as cited by (inaudible) in the last few years. And you can't do any better than that. But we're very confident, Neal Shah will do a great job in filling Frank's footsteps. And Frank, all I could say is we'll see you off in Naples, Florida, whenever the weather is bad in Dallas.

So let's now turn to Slide 3 and talk about the results for the first quarter. Our first quarter results were very strong, and they clearly demonstrate a highly profitable growth plan going forward, a product really that's very much a function of high-return wells and increasing productivity per well.

For the quarter, we reported adjusted income of $284 million or $1.66 per diluted share. Our Permian Basin production for the quarter came in at the top end of the range at 260,000 BOE per day. That's an increase of about 9,000 BOE per day or 3% compared to the fourth quarter last year. The production results, of course, would've been even better had it not been for the loss of about 6,000 BOE per day due to the January freezes that we experienced. Oil production at Permian was solid as well, 170,000 BOE per day. We're right on target with regard to our annual expectations for POPs. We put on production 63 wells in the quarter. The overall company production was 312,000 BOE per day.

We continue to maintain the strongest balance sheet in the energy sector with about $1.8 billion of cash on hand. And as a result, we continue to have very low debt statistics.

I'll turn now to Slide 4. A hot topic among investors and analysts, as many of you know, continues to be oil and gas takeaway capacity and their impact on differentials. In particular, we've seen a pretty significant blowout when it comes to the Midland-Cushing differential and also from the standpoint of gas at the Waha differentials. I can very clearly state to you that Pioneer is in excellent shape in this regard due to the fact we have extensive firm transportation agreements for both oil and gas. But toward that end, we delivered about 160,000 barrels a day of oil to the Gulf Coast under FT contracts during the quarter. Of that, about 87,000 was exported. And about 3/4 of our gas is sold under pipelines contracts, FT contracts into Southern California and it's priced along the lines of that market. The balance is sold under term contracts at Waha. But what that's done is allowed us to make sure that our volumes will continue to flow uninterrupted and at strong realized prices. And Rich will have a couple more slides with some granularity on that in his section. But what it's allowed us to do also is to add value. And in this case, in the first quarter, we added about 16 million of incremental cash flow related to our sales to the Gulf Coast and exports.

On the gas side, our realizations today are about $0.60 per Mcf higher due to the SoCal sales than they would be if we were selling all of the gas in basin. So not only it is allowing us to move volumes but it's allowing us to add value in doing so.

We did, during the quarter, close on the sale of our Eagle Ford West package for $103 million. That's a very positive result for the company. And as promised, late last year, we have included in our 2018 compensation program for our management team in the incorporation of return on capital employed, ROCE measures as well as per share production and reserve targets. And you'll see those as we progress through the year.

Albeit relatively small, we also began our stock repurchase program with 17 million of stock purchased in the first quarter.

Turning now to Slide 5 and continuing the update for 2018. The plan remains very solid. Again, it's based on a D&C program that's focused on very high rate of return wells. We continue to operate 20 rigs in the basin, and we'll continue to have a POP schedule of 250 to 275 wells. By all third-party accounts, we continue to be drilling the most productive and high rate of return wells in the basin where we operate.

Cash margins are strong. IRRs continue to be strong. In essence, our returns are excellent especially in light of the gains we have seen in oil prices during the first quarter and into April and in early May as well. We're evaluating adding some more rigs here at the end of 2018 as -- to progress our plan into 2019. We'll have more details on that as the year progresses.

We're on schedule to place our 45 Version 3.0+ completions online. These are the higher-intensity completions that were planned for the year. We have some later slides to show what the impact the 3.0+ has done to the well results. Needless to say, the results have been stellar. And as a result, we're evaluating the concept of adding new 3.0+ wells to our schedule in the second half of the year based on stellar results that we've already seen to date. I'll talk more about that in just a minute.

In terms of the Wolfcamp D, we have now on production the 3 wells we had planned. These wells have just been put on production and are cleaning up. But from what we've seen so far, we expect them to be excellent wells. As you may recall that our first higher-intensity completion Wolfcamp D well had outstanding results and, as shown on the slide, delivered 130-day cum productions of -- production of 260,000 BOE per day, really an outstanding well. I think these next 3 could be equally as good.

Finally, on the slide that we are executing on our plan to appraise the Middle Spraberry Shale, the Jo Mill and the Lower Spraberry Shale in terms of its pending future development. The idea here is to evaluate the proper spacing of the wells, the staggering and sequencing of the wells and the proper stimulations on the wells in 3 separate development areas to optimize future locations that we'll be drilling in future production. So this is an appraisal concept that we can learn from and then optimize wells when we get out into next year with a true development plan in those 3 zones.

Now turning to the next slide. That's Slide 6. We have done -- made good progress in terms of our divestiture packages for both Eagle Ford and the other assets that are in that package. Bids are expected during May for the Eagle Ford package, which is -- will be the largest of those.

After all the divestitures are completed, of course, we become a pure-play in the Permian Basin, in fact, a pure Midland Basin player. And that will enhance our reported returns because, of course, our reported cash margins will increase, our cash revenue per BOE, our operating costs will be reduced per BOE and our corporate returns will also be significantly improved. So this is important for us to accomplish. I think it can easily last through the majority of this year to execute and actually complete all of these sales. But suffice it to say, it's on the front burner, and we're making good progress.

We're continuing to forecast that Permian production will grow about 19% to 24% this year and, based on the strong performance we saw in the first quarter and the success that I mentioned regarding our Version 3.0+ wells, we now expect that production will be trending towards the high end of that range.

Now turning to capital. Cash out the door for D&C was just over $800 million in the quarter. Of course, we knew going into 2018 that we have somewhat of a front-loaded CapEx schedule, mostly as a result of the high-intensity 3.0+ fracs that we had planned and higher majority of deeper wells in the plan as well as longer laterals being concentrated in the first half of the year. Much of our 2018 seismic work as well as well science and pad construction was also planned for the first half.

Additionally, some of our capital spilled over from the fourth quarter into the first quarter in terms of carryovers. So it's also the case as we look out to the future. And as other Permian operators have reported, we're starting to see some early signs of inflation late in the first quarter into April and May. It's a product, of course, of strong industry activity levels, especially in the Permian Basin that are coupled with the high oil prices that we've seen in the high $60s.

Looking forward and based on the results I mentioned and the high returns of those 3.0+ wells that I just discussed and I'll show you a slide in a moment, it is likely we'll increase a number of these completions going into the second half. We expect these wells to add to and contribute to our ongoing capital efficiency improvements. This will be money well spent. As I also mentioned, it's likely that we'll also add a couple of rigs later in the year to prepare us for the 2019 plan as a result of those 2 factors and the prospect of potential inflation, as I mentioned, especially if oil prices and activity in the industry remain high, it's likely that our capital budget for this year of $2.9 billion will be increased. I would also -- I believe we'll have a better handle on that, of course, on the magnitude of the increase as we let more time pass, but probably around midyear, we'll have much better handle on exactly where that number will land.

In any case, our intent is to spend within our forecasted cash flow, which is now projected at $3.2 billion and to get, again, to that free cash flow generative model as soon as we can.

And finishing up on this slide, we did repay earlier this week our debt maturity of $450 million from cash.

Turning to Slide 7. This is the slide I've been referring to, which covers results from our 3.0+ well campaign. And without going into the details, by zone, you can readily see on this slide that the performance of the 36 Version 3.0+ wells we put on place -- put on production already, these are in various areas and zones across the basin over the past year have been excellent. The wells, of course, utilize higher-intensity completions, in that case, we mean more sand and more water, and they continue to really materially outperform Version 3.0 wells. And you can see on these graphs, it's somewhere between 30% to 40% minimum in general and, in some cases, up to 100%. So the designs, when it comes to the higher-intensity completions, are paying out easily in less than a year and they're generating higher returns not only for the incremental dollars but they're increasing the returns on the wells in general. And as I mentioned a minute ago, additional 3.0+ wells are likely in the second half of the year because we've just seen this impressive performance to date. I think also it's a fact that the 3.0+ wells, with the kind of results they've shown, have meaningfully increased our productivity per well. And as a result of that, overall production, as shown in the next slide, Slide 8, reflects that. You can see here that -- it's pretty clear that 3.0+ wells are leading us to a position where we're reaching the top end of our guidance range not only in the first quarter, but it supports our view that we're trending toward the high end of our guidance range of 24% for the year.

And importantly, I would say also that the high return on these wells gives us confidence that we're on track to achieve our longer-term objectives, which are further captured on the next slide, Slide 9. This is essentially reiterating our plan for enhancing shareholder value. First and foremost, it's based on a long-term focus on returns both at the well level and then further to -- at the corporate level. In other words, strong returns on capital employed. Capital discipline and capital efficiency are important parts of that because they drive strong growth and growth within cash flow. Eventually, this kind of discipline and efficiency leads to a return of capital to shareholders, which is, of course, an important part of our plan going forward. And it's critical in association with this that we also have a very strong balance sheet and significant financial flexibility to execute the plan really in any reasonable price scenario.

And finally, the message from the Permian Basin assets is significant. It says it's highly repeatable, it's low risk, it's process based and it's going to be many decades of drilling. Fundamentally, our assets give us an advantage in the Permian Basin on the basis they give us an opportunity to drill not only high-return wells but also increase our ability to return capital to shareholders.

So now I'm going to pass this over to Rich, and he's going to be discussing with you more granularity on the benefits from FT on both oil and gas as well as his review of the financials.

Good morning, and thanks, Tim. I'm going to start on Slide 10, and then talk about our firm transportation of oil to the Gulf Coast. If you look at the upper left figure there, you can see the pipelines that we have firm transportation on to the Gulf Coast. And we send about 1/3 of our volumes to each of those locations being Corpus Christi, Houston and Nederland. If you look at the upper right bar chart, as Tim mentioned, we did send about 160,000 barrels a day of oil to the Gulf Coast or about 95% of our net production was there, which was all sold at Brent-related pricing. Of that 160,000, 87,000 was exported during the quarter. And we forecast a similar amount to be exported in the second quarter. However, we do anticipate as we move to the second half of the year that we'll be able to export essentially 100% of our volumes once new export facility comes online in the Houston market late this summer.

As Tim missioned, we did benefit by $16 million of incremental cash flow associated with our sales to the Gulf Coast that equates after transportation to about $1 a barrel. So clearly these -- we are deriving benefits from our firm transportation today, but it even gets better as we move into the second quarter, especially when you think about what's happened with Mid-Cush differentials. Just as a point of reference, Mid-Cush differentials averaged $0.40 for the first quarter. In April, they averaged at $5.15 and, at the end of April, they were $7. So we should see a significant uplift in our cash provided by moving these volumes to the Gulf Coast in the second quarter relative to what we saw in the first quarter.

Longer term, we are continuing to target to be at 90% or more of our production moving to the Gulf Coast. We've structured our firm transportation contracts such that they ramp up over the next 3 years to match our production growth profile, and so we're in good shape through 2020, early 2021. And at that point, we'll start layering on -- more on top of those FT contracts that run out to the mid-2020s.

So to suffice it to say that we're essentially insulated from Mid-Cush differentials. And really -- by moving our barrels to the Gulf Coast, really provide us substantial uplift of the company's cash flow going forward.

Turning to Slide 11 and looking at our gas position. Similar to oil, we are well positioned with FT contracts to move about 75% of our gas to the Southern California market, where we're selling it at a premium to Waha prices. And significant, as Tim mentioned here basically today about a $0.60 uplift compared to Waha or that's about equivalent to $2 million to $3 million per month of incremental revenues.

The remaining 25% is sold at Waha under term contracts. So we do have firm contracts to sell that gas in Waha. So in total, we have basically demonstrated that we have the assurance that we can move our gas either to Southern California or that we have contracts to sell it in Waha until, because we've recently taken on extra capacity on Kinder-Morgan's Gulf Coast express pipeline that is expected to come on in late 3Q of 2019. And that will give us access to LNG exports, where we've already actually locked up some contracts, refineries, petrochemical facilities and actually be able to export into Mexico as well.

So overall, we are in a great shape to ensure our gas moves out of the basin into better pricing markets and that it can have flow assurance during that time period. I guess the one thing having said all that is gas revenue still is a small portion of our total revenue stream, so it's less than 5% of our forecasted Permian Basin revenue. But it is important that we have flow assurance, and we think we've done a good job in positioning ourselves to make sure all the gas flows.

Turning to Slide 12, earnings summary. Net income attributable to common stockholders was $178 million or $1.04 per diluted share. It did include noncash mark-to-market derivative losses of $106 million after-tax or $0.62, really related to the increase in oil prices over the quarter. So adjusting for that item, we are at $284 million or $1.66 per diluted share, so really another great quarter operationally and financially.

Looking at the bottom of the slide, you can see how we did relative to guidance. On a production basis, we are at the upper end of our guidance range at 312,000 BOEs a day. On the production cost, which I'll talk more about later, the $10.30 does -- per BOE does reflect the new revenue recognition standard. I'll talk about more in a minute. So it is $1.53 per BOE in that number associated with the new revenue recognition.

Exploration and abandonments came in at $35 million. This is really, as Tim mentioned, our front-end-loaded seismic that we had going on in the first half of the year, so that's included in there. We had some 3-D seismic surveys. And then, really the rest of these items are fairly consistent with where we would have expected them to be. So I'll move to Slide 13.

So Slide 13 is -- gives an overview of our new revenue recognition standard. And so similar to what you've heard from other companies in the earnings season that we've been in, we adopted this new standard effective January 1. And for Pioneer, this is just a geography change with no impact to cash margins. Essentially, we had gas processing fees, fractionation fees and transportation fees for NGL and gas that was netted out of revenue. Under the new rules, no longer we will net it out of revenue, but instead we'll record it in production costs. So if you look at the bottom of the page on the right-hand side, you can see that the impact of that for the first quarter was $1.53 per BOE increase in -- per BOE related to NGL sales and gas sales and $1.53 increase in production costs for no net change in our cash margins.

Turning to Slide 14, where we talk about price realizations. On this slide, we have adjusted to make them comparable -- our prior periods for NGL and gas revenues price realizations to put them on a comparable basis. So if you look at the bar charts, now you can see that oil was up 17% quarter-over-quarter as we also have seen with the oil price increase, we participated in that. NGLs on a comparable basis were up 1%, so not much change there. And gas prices were down 7% quarter-over-quarter from a price realization standpoint.

At the bottom of the chart, you can see our derivatives impact what they would add to our realization, so they're there for your benefit.

Turning to Slide 15. And similar to the prior slide, we have adjusted prior periods to make them comparable for the revenue recognition standard. And so adjusting for that, you'll see that production costs for the first quarter were up 13%. You'll see that each of the categories were up slightly. But the 2 main drivers for it was higher oil prices, which caused production taxes and ad valorem taxes to be higher quarter-over-quarter. And then we did see some increase in LOE, mainly related to activity levels in the Permian Basin, so higher labor costs, and then especially with commodity price increases, higher fuel and hot oil rates. So those 2 are the main components of the increase.

Turning to Slide 16. Looking at our liquidity position, Tim said it already, excellent financial condition for the company, one of the strongest balance sheets in the industry, $900 million of net debt at the end of the first quarter, plenty of capacity under our credit facility with nothing drawn. And as Tim mentioned, we did repay our May 1 debt maturity of $450 million earlier this week with cash on hand, so still in excellent financial condition.

Turning to Slide 17 and really focusing now on second quarter guidance. You can see here from a production standpoint, we're forecasting total corporate production of 312,000 to 322,000 BOEs per day. That does reflect all of our existing assets if we close some of these debentures, we hope to, prior to quarter-end, and obviously, that would come out of our production numbers when we report them into the second quarter.

Permian Basin production is forecast at 268,000 to 276,000 BOEs per day. The rest of these items are consistent with prior quarters for the most part, so I'll leave them for you to go through. And at that point, I'll turn it back to you, April, to open up the call for questions.

(Operator Instructions) And we'll first hear from Arun Jayaram of JPMorgan Chase.

Tim, I wanted to clarify a little bit about your comments on the guidance in CapEx. First question really relating to the guidance. You mentioned that the company is trekking towards the upper end of the 19% to 24% Permian Basin growth range. Does that just contemplate the 45 Version 3.0+? And I guess, my follow-up is just on that. If you did increase the mix of Version 3.0+ wells, would you expect production -- there to be a corresponding impact to production from that?

Yes. Arun, I think, first of all, the production numbers we're seeing so far have been outstanding, and we continue to operate the strong rate of growth, so I think the numbers we're reflecting today really don't yet contemplate adding additional 3.0+s because we haven't determined that number yet. What I'm pointing you to is the fact that we are going to increase the number of 3.0+s and, as a result, we'll come out with production guidance at that time. But needless to say, one of the reasons we're hitting the top end of our ranges is because of 3.0+, the more we drill, the better we're going to do.

Great, great. And just to clarify your comments on CapEx, you mentioned that CapEx would likely trend higher. You'll update the Street kind of at the middle part of the year. But you did mention that while it could be higher than 2.9, did you mention that it could be less than 3.2, which is your current cash flow? I just want to get a sense of what the potential magnitude of the CapEx increase is related to inflation adding some rigs for '19 growth, et cetera?

Determining the exact number of rigs we're going to add yet, so that number is unclear. We have not exactly finalized the 3.0+ number of additions as well. So we don't really have a number in mind yet. And we also aren't really clear on where this inflation thing ends up. We can point you to several categories where we can say what the current estimate is -- would be for inflation, but there are so many moving parts so we got to get our arms around that. So rather than saying it's going to be 3.1 or 3.2 or any particular number, you've got to give us some time to really -- we've got to sort out what's going to happen in all of these parameters.

Next we'll hear from Doug Leggate of Bank of America Merrill Lynch.

Frank, it's been a real pleasure. I wish you the best of luck. I hope to see you down in Naples some time. Thanks for all your help. Tim, I guess, the question that hasn't been asked in a while is the cadence of infrastructure spending. I'm just wondering if you could give us a little bit of guidance as to how we should think about that going forward as you step into next -- this next phase of growth, especially with some of these bigger wells. Do you still anticipate the breakeven trending down to that $50 and, then ultimately, $40 level? I'm really more interested in the next couple of years. And I've got a quick follow-up, please.

First of all, on your question regarding the cadence of incremental spending above just D&C, we have some significant projects this year that you're familiar with. One of them is our Midland wastewater plant investment so as for them to be able to take 240,000 barrels a day of effluent water from the system. That's easily $100 million plus this year, we think. That's going to be spent later as we get into the year. In addition to which, we have regular capital needs for our pumping services fleet as well as other items corporately. The other thing to note is we do continue to spend money at a relatively even cadence on tank batteries and saltwater disposal systems. Our estimate continues to be that by the end of this year, we'll be about 65% completed on the whole field-wide implementation of that. So we do have a few more years of spending at that level. Our longer-term modeling is to add roughly $300 million per year. And when we put out our 10-year plan, that was the number we included. And it could be a combination of things. It could be gas processing. We have 2 gas processing plants coming in this year, 2 coming in next year. So this is the important part of our capital in the sense it prepares us for the long term.

I appreciate that. I just -- obviously, it's something that comes up periodically. We just wanted to make sure we had it baked into our numbers. My follow-up is really more about the longer-term target, the impact of the asset sales on that target, and if I can risk a third leg to that question, any updated thoughts on what you'd do with the proceeds of the pending asset sales? Obviously, it's got -- it's a fairly meaningful number. Do you stick with the [$1,000,010]? Do you make up the difference with some of these bigger wells, for example? And I'm guessing you've got a lot of flexibility in there. Just if you could frame that for us and I'll let someone else jump on?

Yes, Doug, we do have a lot of flexibility. But I would point out to you that if we were to spend no money on those assets in the next 8.5 years that remain on the plan, they would basically get to a point where they're insignificant as to their contribution. That's certainly the way we have it modeled. So therefore, in the fullness of time, even if we kept those assets, didn't spend money on, they will be immaterial to the ultimate goal of reaching that goal in 8.5 years. And so asset sales really -- are really not meaningful. They will be meaningful in a quarter or 2 here and there, but not in the long term simply because they sort of asymptotically reach 0 in terms of production over 8 years. So that's important. So I don't think the asset sales really have much to do with that. As to the use of the cash, right now, we're planning on trying to execute on these sales. We don't have any particular plans for these -- for that cash per se. It will be part of our calculus when we start focusing on the 2019 plan and, in particular, the notion of returning -- of return of capital to the shareholders as we get to where we're cash flow generative.

Maybe just a quick bolt-on to Rich. When you sell those assets, what happens to the other expense (inaudible)? Does that roll off with those assets? Or specifically, I'm talking about the [MVC] costs?

Yes. So the vast majority of it will roll off so -- once they are sold, so there should be very little left at that point.

John Freeman of Raymond James.

First off, I'd also like to share my congratulations, Frank, on your retirement. It's been a pleasure working with you over the years, and I certainly wish you and Eileen all the best. My first question, as you all are now contemplating these additional rig adds, you all previously talked about considering, revamping and renovating a couple of your frac fleets and I'm just wondering if there's been any decision made on that front?

Yes, John, first of all, the fleets we have, 1 or 2 fleets probably need some refurbing. One particular is really on ice today. And that is something we have to evaluate really for as a late 2018, '19 decision. Realizing today, of course, we're using, depending upon the day, 6 or 7 of our own fleets and one outside fleet. The calculus is such that we need about one fleet for every 3 rigs. So let's say, for example, we were at 24 rigs at any particular time, we would need 8 fleets. So we're sort of within the bandwidth. We might just refurb one of ours or bring in a third party. We're evaluating. It's sort of a lease versus buy decision. Going further though, we'd have -- we'd have to make that decision in a bigger sense. That really becomes a 2020 issue, so we have to make the decisions really in 2019.

Great, that's helpful. And then just my one follow-up question just to make sure that I'm kind of thinking about the export market and what you all have done a good job on in terms of the Gulf Coast. Basically, whether -- the last couple of quarters, it looks like now for 2Q, you all are going to be kind of trending around that 90,000 barrel a day export number and I recognize you all are expanding the capacity to 150,000. But am I thinking about it, right, with the 160,000 or so right now that's going to the Gulf Coast, it's kind of almost indifferent for you all whether you export or whether you sell it to the Gulf Coast refinery, you're basically just doing whatever is going to give you the highest value, right?

That's correct. Other than some of the Gulf Coast sales are term in nature, they're not really very long term, but they might be for 3 months, for example, something like that or 6 months. The rest of the export sales as it relates to today are all spot sales. And so you have to wire around whatever you have in terms of term contracts. But overall, you're right, our whole objective is we just send it to the highest market.

(Operator Instructions) We'll now hear from Brian Singer of Goldman Sachs.

Frank, congratulations, again. Tim, you highlighted the return of capital to shareholders over time. At the same time, at least for now, you're talking about using the cash flow from strip prices for greater CapEx, fully recognize the benefits on the rate of return front from enhanced completions, but how do you and the board view the near-term preference for return on capital by redeploying the potentially $300 million from strip prices to the drill bit versus an earlier-than-expected return of capital to shareholders?

Yes, I think, first of all, I'm very confident when I say the returns on this incremental spending are very, very high in the sense of the 3.0+ wells. The adding of rigs really is a matter of cadence, keeping the RPMs upward and to the right as we execute on the plan. So it's just a matter of exactly what that additional capital entails. 2019, of course, is -- excuse me, 2018, of course, is a year where we're relatively high in terms of derivatives, which have an effectiveness of not getting the full benefit of the high prices. And so had it not been for -- had we not been as hedged as we are today, we'd actually be in that mode today. In 2019, our derivative packages were significantly lower. 2020, we're completely unhedged. And so the numbers actually jump off the page at you when you take that into consideration. And so we have not changed our plan anyway whatsoever. We're trying to get the cash flow generative positions as fast as we can while executing at a higher rate of return on the capital invested. And this really doesn't change anything regarding our long-term objectives in that regard.

And then with regards to the potential to add 3.0+ completions, on one of your slides, Slide 7, you show the well performance, outperformance of the 3.0+ across different areas. Can you add a little bit more color where you would expect to be increasing relative to your initial case the 3.0+, is it disproportionately some areas versus another? And how differentiated should we expect you to be?

Yes, Brian, what I'll do is I'll let Joey answer that question.

Yes. This is Joey. Whenever we look at our completion recipes across the field, the way you asked the question is exactly the way the result comes out. One size definitely does not fit all, as I've mentioned many times in the past. And I would say as we continue to expand the 3.0+ completions, that applies as well. And so it's going to be across the board in different areas based on what kind of stacking plan we have, what kind of frac barriers we have. So it's going to vary. And I couldn't really characterize it geographically because it just varies so greatly across the field.

Yes. The only thing to add there is if you look at what we set out in Slide 7, these wells are all over the place where we've shown you the uplifts from 3.0+ wells. I would expect that to continue. They're going to be spread throughout the field.

Next we'll hear from Bob Morris of Citi.

Tim, last year, you added 2 rigs to build the DUC inventory (inaudible) Cushing as you move forward. Where does that DUC inventory build stand at this point? And going forward, is that something you just maintain for Cushing going into the future? Or at some point do you plan to draw down that inventory?

Yes. I think the objective, of course, by adding the 2 rigs was to move our DUC inventory into a position where we would not be subjected to any rig-induced delays. The objective is to hit a target of about 30 DUCs in the second half of this year. So we're building in that direction. The second quarter is important period during which we're building the DUCs, at which point, in essence, that DUC build will have been completed. We feel comfortable at that level, and then we just essentially are turning those rigs to production at that point.

Okay. And then second question is, last quarter, you'd moved down about 50% of your drilling program still using the 4-string casing, but I know you were looking at a deeper disposal well to the Ellenberger. You were looking at recycling. You were looking at spudding out the drilling so you wouldn't pressure out that upper zone. How is that progressing as far as continuing to move that percentage down on the 4-string casing design to then further improve the efficiencies going forward?

Yes. We're now averaging depending upon the exact time period, look at 45% to 50%, 4-string case wells, so we're hitting our target there really well in that sense. But we have a lot of initiatives going on as well as you might expect. We're planning on 5 Ellenberger wells this year. First well was spudded here at the end of the first quarter. The anticipation also though is -- that we would increase substantially the amount of produced water that we used. The rates were more 5% to 10% last year, we're hitting more, and hopefully, quickly to 15% to 20%. Ultimately, that's a very important objective because reutilizing the produced water is a significant economic benefit because we're already paid for it. Now we're just going to reuse it by cleaning it up a little bit but also taking that water out from underneath our drilling footprint is important when it comes to this business of 4-string versus 3-string. So we've got a lot of initiatives moving forward, they're all on target.

Next we'll hear from Michael Hall of Heineken (sic) [Heikkinen] Energy Advisors.

Michael Hall with Heikkinen. So I guess just curious if you could provide some color around like sensitivities on how the cash flow benefit from your marketing arrangements looks as we move into what looks like a much wider spread in the back half of the year, maybe just provide like what's the cost to get from Midland to the Coast and then what sort of handling fees from -- are you paying on the export barrels from the Coast to Brent, so we can work out a sensitivity on that?

Sure, Michael. So roughly it's -- call it $2 to $2.50 a barrel on average to get the volumes to the Gulf Coast, and then there's usually a, call it, $0.50 or so between storage and getting it on the water for export. So you're all in, in that $2.50 to $3 range of transport cost per barrel. And then depending on where the Mid-Cush differential is, what that uplift will ultimately be and how much incremental cash flow that is relative to what we would've gotten had we sold it in Midland, it is really highly dependent on what the Mid-Cush differential is. Generally, we've been receiving on the Brent versus WTI basis, 70%, 80% of that differential as an uplift over WTI.

Okay, that's helpful. And you guys have had obviously good foresight in building out the, I guess, the portfolio you have as it relates to the marketing side of the business. Do you have any views on how sustained you think this tightness ends up being? Do you think the pipes that are planned for the back half of '19 will resolve the situation? Or do you think this is something that will likely drag out beyond that and that additional infrastructure builds beyond what we've seen announced will be required in 2020 and beyond?

I think if you look at the numbers, we do expect it to be pretty tight. This doesn't apply to us as we have FT. But in general, new pipelines aren't expected to come on until later part of 2019. There's 3 or 4 specific pipelines heading to Corpus, in particular. So it could be pretty tight between now and then. And so as a result, I would guess that you will have a wider Mid-Cush differential during that period than you would otherwise have had if those pipelines weren't in. But that said, it's simply the case that we're going to need more pipelines through time. So it pretty clearly takes 18 months, 2 years or so to build new pipelines. And it's very possible new pipelines would be announced with the idea of start-up dates into 2020 and 2021. For our purposes, we're pretty much covered in terms of FT ramping up into 2021/'22 ourselves, so that we don't really have an issue, but certainly, could be tight. If you look at the gas side of the equation, it also will be tight we feel like in the short term. But short term means into '19, in particular when the Gulf Coast express pipeline comes on with 2 bcf a day to clear out of the Permian market. Realizing Permian gas growth is substantial, just mirrors oil growth, so this is going to be something that has to be grappled with. But again, with our Southern California market, we're pretty much not exposed to that issue in any significant way.

Okay, that's helpful and kudos for being in front of all that. If I could, one more thing. On the capital side, just curious how much in the first quarter was spent on infrastructure. Sorry, if I missed that in the disclosures, I didn't see it. And then, yes, like what in the first quarter, I guess, would you characterize as somewhat transitory or could rate down over the course of the year? And if you could expect the level of spending in the second quarter would be helpful?

Yes, on the infrastructure spending for the first quarter, it was -- it did aggregate about $35 million of our expected $250 million, so it was a little bit under our run rate. I don't have the exact numbers on the second quarter to give you, but my guess is it's probably in that $50 million range or so -- it be where I'd suspect.

Okay. I guess, for 2Q, I was thinking full corporate capital spending in 2Q, so I was trying to get at.

No, not just infrastructure.

I think, we don't have the number before you right now, but I think I would anticipate that certain things will come out of the capital budget that we're in, in the first quarter. For instance, we had about $30 million that was carried over from the fourth quarter into the first quarter. That's an example of something (inaudible). We won't see the seismic in there.

In the 3.0+ completion.

That's right. We've done more 3.0+ [stack] completions in the first quarter than we are in the second. So from that standpoint, we have science on wells that were significant. All those things don't reoccur.

Next we'll hear from Charles Meade from Johnson Rice.

I wanted to ask a question about pad size. It seems like there's a trend in the industry among your Permian peers going towards bigger pads and big multiple pads. And I know in the past you guys had settled on kind of a 3-well pad as an optimum. But I wonder if you could give us an update on your thinking there and talk about what are some of the trade-offs that you look at as you look at bigger -- moving to bigger pads?

Okay, I'm going to pass that one to Joey Hall for you, Charles.

Yes, Charles, we actually started instituting last year what we call the Pioneer pad, and it's a 24-well pad, which reduced our footprint of -- to about 1/4 of an acre per well, which is an 85% reduction. And the whole premise behind that is that we plan all 24 wells and all multiple benches for any particular area for the full field development so that we plan our wells smartly and we don't leave any reservoir behind by limiting ourself on surface. So I would say about 50% of our program this year is on these big pads. And then, of course, as you start going into the stack (inaudible) test and we have some other tests planned later this year and early next year, where we'll be doing some similar multi-well pad developments. So Pioneer has been doing this for quite some time. And on these multi-well pads, we're able to drill, produce and complete on the same pad, so a lot of simultaneous operations. So yes, we've been doing that since last year.

Got it. Just to clarify that, Joe, you don't necessarily drill all 24 before you frac and flow back. Is -- am I interpreting that right?

Yes, to put it in perspective, and I'll give you the best example I can. For example, on a 24-well pad, we'll put in a well bay for 6 wells. And in general, what you would see us doing right now is we would come in and drill the 3 Wolfcamp Bs and then get those online, and then once they're online, we'd come back in and drill 3 Wolfcamp As. And for the most part, that's what we're doing now. So the additional 18 wells, well bays would be put in, in 6 packages each and those wells will be drilled in subsequent years.

Got it. That's helpful. And then, Tim, if I could go back to that kind of takeaway question. You guys have really been ahead of the curve of the industry not just on this takeaway but also on a lot of these kind of infrastructure or macro things. And I'm curious there's talk of a VLCC port going in at Corpus Christi. I'm curious, is that going to have any effect on you as a Permian producer with FT? Or is that something that's all just kind of effect things downstream with you?

Well, I think if you're speaking of Ingleside, for example, which is OXY's terminal there, they can already berth VLCCs, but they can only half load them, let's say, because of the draft limitations in the bay there. And so what's being contemplated is a very significant project to do dredging to allow VLCCs to actually be not only brought in to berth but also to be fully laden. What's happening now is the VLCCs are half-loaded and they're brought off in the deeper water and there is -- additional oil is brought out to lightered out to the vehicle to load it up before it heads, for example, to Asia. So what this will do and this is better for you to direct to OXY, but it will reduce our cost and time significantly. And so those are all advantages, especially when you're just looking at cargo economics in terms of their deliveries into, for example, China or South Korea, what have you. I think we have fundamentally lower cost basis because we don't have to fool around with lightering oil out to a VLCC.

Next we'll hear from Bob Brackett of Bernstein.

I appreciate that less than 5% of Permian revenue is gas so in a sense flow assurance is more of a strategic issue than maybe a financial one. Can you talk about what goes wrong when you lack gas flow assurance in the basin? And what some of those fallback plans might look like?

Well, I think one of the issue is -- one of the issues is that we would be limited on flaring, I feel like, in the basin just as a general rule. Certainly, out of corporate conduct and doing the right thing environmentally, we would want to as an industry not be flaring gas in any significant quantity for any significant period of time. That would be something that might be an issue. What it could potentially lead to, if flaring were not to be an option for the reasons I mentioned, is shutting in some old wells that are relatively low oil producers and gassier producers that were old vertical wells, for instance. So you could actually have an effect on production if, in fact, the situation became so acute that we were having it -- not we per se, but as an industry, reduce gas production from vertical wells. Now again, as you mentioned, it's not a significant or material revenue effect, but it is one of the ways to solve the issues.

Might have to longer term consider reinjection as well.

What would reinjection do to something like OpEx?

It's still too early to tell. There's a lot of work still to be done on that. It depends on location. It's going to be important on that too.

Yes. There are other options too in terms of using gas within the facilities, using gas, for example, to run frac fleets, drilling rigs and so on. There's a lot of different options. Hopefully, we don't need -- we're not pressed into those solutions, however.

Next we'll hear from Neal Dingmann of SunTrust.

Tim, my question is you guys have been always not only about the takeaway way in advance, but in vertical integration. I'm just wondering as you look at kind of now what's going on in the industry, are you continuing to add more on the vertical integration side either through sand or frac or perhaps even rigs? Anything you could talk there, just what you all are doing?

Yes, Neal, I did mention earlier that the decision regarding our frac fleet in the future in terms of adding to it is simply a buy versus lease decision and that's something under evaluation. It has to do with a lot of factors. We are very confident that having our own frac fleets gives us a very significant advantage in terms of execution. And so that's something we'll be evaluating. Again, it's not a decision for this year. It's more of a decision for next year on my 3:1 ratio argument. In terms of sand, right now we are, in fact, taking our first quantities of Western sand that's relatively low quantity today. We're talking about ramping it up to 1.5 million or 2 million pounds -- 2 million tons per year starting potentially next year. That's under consideration today. So Western sands could be significant now. Our ownership would not really be the factor here. We'd just be getting processed sand at relatively low cost, so we don't see necessarily vertically integrating per se into more sand today than we currently have. When you look at things like water our water system is critical. I mentioned the fact that this Midland contract in the Midland construction project is significant in the sense it gives us massive quantities of effluent water. That project has to move ahead. So some areas, we're evaluating. Some areas we're clearly moving ahead, and particularly on water. Sand, we're moving more to the Western area since they can save us considerable amounts on our well cost. So it's really a mixed bag. We are continuing to invest in gas processing with our partner Target. They've done a great job keeping up with the gas production growth in the basin, and I anticipate they'll continue to do so.

Very good. And then one just follow-up, if I could. You had success, I think, it was not even in the last quarter talking about just the Wolfcamp D success you had there on the -- I think it was on the Eastern Midland as I recall. Are you seeing the advancements there when you go to the 3.0+ just as you were seeing in the other zones? I mean is there now just as much plan to drill as many Wolfcamp Ds as there was? Or is the focus more still...

I'll let Joey answer that question, Neal.

Yes, just to be clear, whenever we drilled that last Wolfcamp D well, that was an upgrade to 3.0. And so we saw a significant uptick. And the last 3 wells that we recently POP'd this quarter are also 3.0. So as we highlighted last quarter, it had been some time since we had done any Wolfcamp D wells. So our completion recipes had evolved significantly. One of the things I would say we're most pleased about in the Wolfcamp D is that we've had great success drilling these wells and also great success completing these wells because since they are deeper, they do offer some additional challenges but we're seeing great execution on these wells.

And our final question for today will come from Leo Mariani of Nat Alliance Securities.

Just a quick follow-up here on the asset sales. I think you guys talked in your prepared comments about potentially getting some proceeds in maybe by the end of 2Q. Just wanted to kind of get a little bit more color there. Is this just some kind of the smaller dribs and drabs? And is the larger Eagle Ford package more of a year-end target? Just trying to get a sense of those proceeds.

Yes, Leo, sure. I think, first of all, the Eagle Ford package, as I mentioned earlier in the slides, we're anticipating bids on that during May. And as it goes, there's time then for negotiation and discussion who would be the purchaser we're willing to negotiate with. Negotiations would continue. It'll kind of reach a point where a purchase and sale agreement will be signed, and then going -- processing all the way to a closing. It's obviously several months away, so it's a complex process and, as a result, I would not expect to see any proceeds on that really for months until we actually finalize it. The other 2 assets in question that being Raton and West Panhandle field, those are smaller. They are such that we might be able to achieve something faster on those, but those data rooms are really in effect open and we're processing the opportunity to get bids in those -- on those pretty shortly as well. So the latter 2 pretty clearly could be faster. The first of the 3, that being Eagle Ford is going to take time.

Well, thanks, everybody, for being on the call. I really appreciate it. And Frank, once again, thanks for all you've done for us. And we'll be on the road here a little bit the next -- or during May and June. And look forward to seeing you there. Hope everybody has a great summer. And we'll be updating you when that time comes. Thanks very much.

That does conclude today's conference. Thank you all for your participation. You may now disconnect.