先鋒自然資源 (PXD) 2017 Q4 法說會逐字稿

Welcome to Pioneer Natural Resources' fourth quarter conference call. Joining us today will be Tim Dove, President and Chief Executive Officer; Joey Hall, Executive Vice President, Permian operations; 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 March 4, 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 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, Investor Relations, Frank Hopkins. Please go ahead, sir.

Thank you, Annette, and good day, everyone. And thank you for joining us for our fourth quarter 2017 conference call. I'm going to briefly review the agenda for today's call. Tim is going to be up first. He'll provide the financial and operating highlights for the fourth quarter of 2017 and also take a look back at the highlights that were generated last year. He'll also discuss our plans for 2018 followed by a progress report on how we're tracking towards achieving the operating and financial targets in our 10-year plan. After Tim concludes his remarks, Joey will review our strong horizontal well performance in the Permian Basin, which is resulting from our successful completion optimization program. He'll also provide details regarding our 2018 Permian Basin drilling program. Lastly, Rich will update you on our increasing oil takeaway capacity for Midland to the Gulf Coast and the financial benefits we're receiving from growing oil exports and having the ability to move oil to the Gulf Coast. He'll also cover the fourth quarter financials and provide earnings guidance for the first quarter. And as usual, after that, we'll open up the call for your questions.

So Tim, I'll turn the call over to you.

Thanks, Frank, and welcome, everybody. Pioneer's fourth quarter results were quite strong, and they reflect our continuing high drilling and completion-level returns. And that, of course, results in impressive production growth that we've seen from the campaign. We'll also be discussing several other topics this morning, some that are very important, 2018 initiatives later in the call. And they'll include matters regarding our 2018 capital budget, our year-end reserves disclosure, our planned divestiture program, our long-term return and cash flow metrics and an increase in our dividend coupled with a share buyback program.

But first, what I wanted to do is review our fourth quarter results and turning to Slide 3. We reported fourth quarter 2017 income of about $209 million or $1.22 per diluted share. Importantly, we also exceeded our production guidance range by 3,000 barrels a day ending up on a BOE basis at 305,000 BOE per day. Production was up substantially in the quarter, up about 11% on a BOE basis compared to the third quarter, but more importantly, our oil production growth was also up substantially about 11% versus the third quarter.

The fourth quarter finished off a year which saw total production increase substantially. In fact, it increased about 16% year-on-year on a BOE basis. But our oil production grew even more significantly, up about 19% year-on-year. So 2017 ended up being a very strong year for Pioneer. Of course, that growth is driven by our Permian Basin horizontal drilling program. And focusing just on the Permian Basin oil production for 2017, it grew 26%. So it's reflective of what we anticipate being strong growth rates going forward.

Importantly, we've also done a good job of keeping production costs in tow. We've kept a lid on them essentially and, in fact, we reduced production cost per BOE by about 12% compared to last year. That's in large part due to cost-reduction initiatives, but also the fact we bring in more low-cost Permian horizontal wells into our mix in the fullness of time.

We announced separately in a press release yesterday very strong finding cost and reserve replacement data. It's also a product of our prolific Permian Basin oil resource and exceptionally strong economics of drilling in that resource.

I'm going to turn now to Slide 4 and focus in on the financial and operating highlights further, and that's to say we'll continue to have one of the strongest balance sheets in the entire energy patch. Our balance sheet ends the year with about $2.2 billion of cash on hand with very strong debt metrics.

We placed 64 wells on production in the fourth quarter. Eight of those were Version 3.0+ wells. We'll have a later slide in which we will cover the fact that these wells, on average, if you look at the 3.0+ completions to date, they've averaged some 30% to 40% uplift after about 200 days. We also announced a very significant well that being our first Wolfcamp D well featuring a Version 3.0 completion in Midland during the fourth quarter, really one of our best wells ever in the Permian Basin if you look at just on the early production data, in particular, a 3,600 BOE per day IP rate and then substantial cumulative production over 45 days of about 120,000 BOE of oil.

A significant value driver continues to be our ability to trade acreage in the Permian Basin. We added about 7.2 million lateral feet. That's a tremendous value added in the sense that it makes the pie bigger, and that would represent depending upon the speed of development of the lateral feet that were added, some $5 billion to $10 billion of incremental value from those trades.

We successfully completed the Eagle Ford campaign, that, of course, included 9 DUCs and 11 new drills last year. Those resulted in very strong well production rates from higher intensity completions, and it's -- that puts us in good stead with regard to the potential sale of the Eagle Ford that I'll discuss in just a moment.

We also have been increasing the volumes we're selling into the Gulf Coast, refining system and the volumes of export. Their size and impact will continue to increase as to their effect on our results. We exported about 90,000 barrels a day of oil production during the fourth quarter to Asia and Europe, and that amount will be similar to peers in the first quarter. Importantly, what that does is add incremental value because of the premium that's associated with the Brent, WTI differential we've been experiencing over the last few months. It added about $15 million of incremental cash flow in the fourth quarter, the fact that we could actually export oil and also ship it to the Gulf Coast.

Going now to Slide 5. I'm going to be turning now to our plans for 2018. And yesterday, we also announced in a separate press release that we plan to divest of all the assets that are essentially non-Permian. So that includes our Eagle Ford assets, other South Texas assets, our Raton assets in southeastern Colorado and our West Panhandle assets in the Panhandle of Texas. That will result in making Pioneer a pure Permian Basin player. I also want to note for everyone, these assets have been part of our portfolio for decades, in some cases, multiple decades, and they've been significant contributors to the company's success over the years. So our thanks go out to the many outstanding Pioneer employees who have been a part of that history. And we believe though, that all said, taking these steps will be a positive for the company on many fronts. Certainly, once the divestitures are completed, it will increase our reported rate of growth because we'll just be focusing on Permian growth rates. It will increase our reported revenue per BOE, reduce our operating expense per BOE and, therefore, improving our reported margins and, further to that, our corporate returns. And so it does a lot for the company. We expect the data rooms will be open probably later this quarter, probably the end of February into early March. It will take time to execute these transactions simply because there are a lot of moving parts and, needless to say, there's a few assets that need to be dealt with. But we should see results through time, probably some potentially in the second quarter and some in the third quarter. So just bear with us as we execute on this plan.

I think one of the most important points about this sale is that it will allow us to not only become, as I said, a Permian pure-play but actually, it also makes us the only Midland Basin public pure-play. And I think that's important because that's where all of assets are. That's where we're going to be focusing. One of the effects of this is the company becomes more oily on a percentage basis, which I think helps in the face of current commodity prices.

As to the rig count and back to operations, we are going to continue with the current rig plan we have in place and have had since the fourth quarter. That is 16 rigs operating in the north and 4 in the south in the Wolfcamp JV area. As we mentioned in the fourth quarter, a couple of those rigs in the north are building DUC inventories so that we can make sure we improve our flexibility and in which case, they'll be turned to more production-oriented activities as we get to the second half of the year and into 2019. For the year, we are anticipating POPs of 250 to 275 wells.

Part of our efforts to reduce cost include reducing the number of four-string wells we'll be utilizing in the program for 2018. We anticipate that number to be about 50% of the wells as opposed to about 75% in the second half of last year. For the time being, we're going to be testing additional Version 3.0+ wells, a total of 45. Those will be anticipated to be completed in the first half of the year. I think once we've had a chance to look at the results of those wells and completed them, we'll then evaluate the next steps after we see the results from the wells. It could easily involve utilizing more Version 3.0+ wells on the remaining part of the campaign this year, realizing more and more as we go through time that completions have to be customized. They have to be customized based on the area we're drilling, the target zone, the spacing of the wells, what is the situation vis-à-vis offset wells and so on in order to optimize the completions. And so for the time being, in terms of our planning and what you see in our numbers, we're assuming the remaining wells for 2018 would only be Version 3.0 completions. But stand by, we'll see exactly how that changes in the second half. And accordingly, what we have built into our production forecast reflects that completion mix for the time being.

Now I'm going to turn to Slide 6, a little bit more detail surrounding the 2018 plan. We anticipate that the drilling program will again deliver really excellent results, growth in the Permian Basin oil production rates of 19% to 24%, and that also corresponds to a similar BOE production rate of growth that is 19% to 24% compared to 2017. And we're still seeing very strong economics. We see IRRs about 65% today. That includes facilities costs, but importantly, that's all based on $55 (inaudible) . So to the extent we have commodity prices maintained where they currently are or strip prices in that sense, we'll be able to achieve substantially over that rate of IRRs as we process the plan if that were to continue.

I have more detail in a minute on Slide 10, but our capital program is shown here summarized at $2.9 billion. You can see the splits there between drilling and completions and other infrastructure needs. We're assuming right now that the industry will be facing somewhere in the neighborhood of 10% to 15% cost inflation. When you net out what we do internally in terms of our vertical integration, that would end up being about a 5% net inflation to the company. And then I anticipate by some of the steps we're taking regarding efficiency gains and optimization, we will offset that 5%. So net-net, we're not really baking in any inflation to speak of in our planning.

The cash flow, of course, looks very robust. At a 55 and 3 case, it's $2.8 billion. Of course, we'll have the proceeds from asset divestitures we hope as well as cash on hand to fund that.

The capital program for our drilling and completion costs and related capital costs is expected to be basically cash flow breakeven if we were to achieve $58. So we have a chance, actually, if current commodity prices to be in excess of our capital needs for our oil and gas operations for 2018. We still remain well-hedged, about 85% at oil, 60% for gas based on the Permian production. And where our caps on the three-way collars would otherwise be struck at a place below where current prices are, we are definitely enhanced by the fact that we're selling oil and gas into the Gulf Coast markets into export markets at premiums, that offset the effect of that cap to a great extent.

Now I'm going to turn to Slide 7. And when you couple our current balance sheet with the potential for the proceeds from the divestitures and then you look at our potential going forward, it's very clear the company's financial flexibility is a clear strength. And toward that end, we anticipate paying off our debt maturity, which comes in May this year, $450 million from cash on hand. Our debt statistics are expected to remain very strong. And based on all of that, we anticipate an excellent year from a financial standpoint. And as a result, the company has increased its semiannual per share dividend from $0.04 to 16% -- $0.16 effective here coming up in the end of the first quarter into the second quarter. We also have announced our plans to initiate a common stock repurchase program associated with the dilution that would otherwise be associated with stock compensation awards to employees and their long-term incentive plans. That will be in effect for 2018. And stay tuned, you'll have to wait until April, but then you'll see that we're going to incorporate metrics in our compensation goals that are per share based and return based for 2018.

I'm going to turn now to Slide 8. And now sort of stepping back and looking at things from a bigger picture perspective, we're now in year 2 of our 10-year plan, and this slide encapsulates what is behind that vision. First and foremost, our cost structure is really what's the most important driver. Our cost structure in the Midland Basin is very clearly industry-leading. And you can see that on the left-hand graph here, in which we are showing our actual 2017 Permian horizontal cost structure, this is fully burdened for G&A and interest on a BOE basis. And what you can see very clearly is that if you sum all of those costs up, we are able to put barrels on production for essentially $19 on average. And so as a low-cost producer with that $19 basis in our costs, it's clear why the 10-year plan works even at oil prices substantially lower than where they are today. It's because our returns are essentially industry-leading. We show that on the right in a set of graphs. We start with the fact that we're drilling low cost and high return, very prolific oil wells in the Permian Basin. That's where it all starts. And with that having been said, what that allows us to do is to grow our corporate ROCE annually, to grow our annual cash flow and to generate free cash flow in the model. In fact, it shows us generating free cash flow at $50 in 2020 if that were to be the commodity price, and incidentally, reduces our cash flow breakeven price on an oil price basis annually as we bring the wells on production at high margin. So the output of all that actually is the fact that as a low cost, high rate of return driller, the model is consistent. What it yields then is long-term growth at any kind of reasonable commodity price in the form of production. And so what's clear through all this is this is not growth for growth's sake. This is a returns-based model. We believe it's going to work because we have an inventory that supports it, and we're going to go execute on this plan.

Going to Slide 9. This is a way to think about it from a longer-term perspective as to how the long-term plan affects our financial metrics and you can see that they improve significantly. If you look at the top-left graph, for instance, you see that the cash flow modeling, this again is based on 55 and 3, is a consistent CAGR of over 20%, which actually yields in the full plan period an increase to over $11 billion of cash flow again based on 55 and 3, so substantial cash flow growth. And importantly, associated with that, you see at the bottom-left graph, significant improvements in returns. Of course, you expect that as we're drilling very high rate of return wells. That as we drill those wells through time, we continue to positively impact our corporate return metrics and it's shown here. It shows us actually increasing our ROCE from 5% to 15%. But in actuality, if you look at our internal modeling, we're actually adding 2% to 3% ROCE per year. So that in actuality, if you look at 2023, that ROCE reaches 15% that year. Again, all of this is based on 55 and 3, so the substantial return upside to the extent we actually have prices in excess of that.

And if you look at the top right, and this has to do with the cash flow breakeven price, the price at which, on the basis of oil prices, our cash flow exceeds our capital needs for our oil and gas operations. You see that those cash flow breakeven numbers fall through time as we add higher-return wells into our production mix. In fact, they go to as low as $40 during the planned period.

So in summary, hope this gives everybody confidence that what our model suggests is that by drilling low cost and very productive wells, in other words, high rate of return wells, especially with that cost structure struck at about $19, we can deliver cash flow growth. It's self-funding. In fact, it generates free cash flow and provides for an attractive story indeed as we go forward. And that's what all of our employees are focused on as we embark upon the next 9 years in this 10-year plan.

So turning to Page 10. As promised earlier, this is a little bit more granularity on this year's capital program. I won't go through this in detail because it's well laid out here in the graph. But it's a $2.9 billion capital program. The breakdown of drilling and completion is shown on the left. In addition, of course, we have other capital requirements related to infrastructure such as our pressure pumping, our well services, our water systems, field facilities, vehicles and so on. The program will be funded, as shown in the rainbow chart, from cash flow currently estimated at $2.8 billion for a 55 and 3 case. Of course, that compares to $2.1 billion in 2017. So we're already seeing substantial cash flow growth between 2017 and 2018. Of course, some of that's pricing, but some of it also is also attributable to our growth rates. And of course, we hope to have proceeds from our divestitures and our cash on hand to fund that program.

And turning to Slide 11 then. Here, we're only showing our Permian Basin production forecast. It somewhat reflects what the company would look like post the divestitures. But you can see substantial growth rates. First of all, if you look at the fourth quarter, we did have an excellent quarter in terms of production. However, our first quarter did get off to a slow start mostly as shown in the box here due to very cold temperatures in January. We lost about 6,000 BOE per day for the first quarter if you look at quarter across the whole 90-day period. And that's because, of course, we had to shut in production and we had fracs that got delayed from this quarter into the second quarter. So the range you see of 252,000 to 260,000 BOE per day would have been higher by 6 on each side of those numbers had we had -- had we been able to avoid the freezing temperature situation.

And importantly as we look forward, and in particular if we look at the oil growth for -- and the overall growth for 2018, you can see the range is 19% to 24% for this year. That's a robust rate of growth, no doubt. But then if you look even further towards the remaining 9 years in the 10-year plan, we're exhibiting growth rates of 20-percent-plus on our oil growth rates as well as our BOE growth rates. And so we still have very good visibility on exceeding a 1 million BOE per day target in 2026 over 700,000 barrels a day of oil in that same time frame.

So to sum it up, we've taken some very important strides as we enter 2018. Returns are very robust. I think that production growth will be very strong. The balance sheet is pristine and, hopefully, divestitures are expected to do some very positive things for the company. We've taken a step towards our goal of returning cash to shareholders as evidenced by the dividend increase and the announced share repurchases.

So with that, I'm going to pass it on the Joey. He can give you some more details and a Permian operational update.

Thanks, Tim, and good morning to everyone. I'm going to start off on Slide 12 and give an update on our Version 3.0+ completions. We did POP 3 new 3.0+ wells in the Pembrook area in Q4. The rest of the wells shown were POP'd in Q2 and now have 6 to 9 months of production history. Well performance remain strong with some of the wells showing 30% to 40% early day uplifts compared to their 2.0 and 3.0 wells in similar areas. And because of these strong results, as Tim mentioned earlier, we do plan to test an additional 45 Version 3.0+ completions in the first half of this year. But as Tim also mentioned, it's more important than ever to stress that one size definitely does not fit all when it comes to completion design. And as we progress, the number of recipes continues to grow. But as we zero in on our completion recipes, we do remain focused on delivering these large stimulations for the lowest cost possible and continue to evaluate new technologies. Some of the things we've been working on recently are technologies that allows our wireline operations to be performed safely while we're pumping and keeping people out of the safe zone by continuing to do work. Sliding sleeve market continues to evolve rapidly, and we continue to look at that and plan on doing some more testing here in 2018. Again, progressing on methods of diversion to potentially increase stage lengths while effectively stimulating all clusters and also looking at lower cost fluid systems that also reduce the required pumping horsepower.

I'll be moving now to Slide 13. We did POP 2 additional Jo Mill wells in Q4 in southern Martin County. They're just now approaching 2 months on production. These 2 new wells represent our second spacing pilot in the Jo Mill. The Q3 and Q4 wells were both 2-well pads and spaced at about 1,800 feet. The Q4 wells did have additional sand at about 2,500 pounds per foot and the Q3 wells were stimulated with 1,400 pounds per foot. So we'll be able to see what the difference in larger stimulations does in the Jo Mill. You are always going to notice some volatility in early time results with the Jo Mill. This is typical as a result of artificial lift challenges that we typically face in the early phases of the well cleanup. We're still very encouraged by the Jo Mill, and these 2 pads are critical step for other tests we will conduct in 2018 that I'll discuss here in a couple of slides.

I'm going to move now to Slide 14. It's been a couple of years since we POP'd a Wolfcamp D well, so our completions have obviously evolved over this time period. And we just recently POP'd a Wolfcamp D well in Eastern Midland County. It's only been online for 2 months, but as you can see, it's significantly outperforming the 33 previous wells. This is quite meaningful to us considering that 60% of our acreage is prospective for the Wolfcamp D, so looking forward to further results there.

Moving now to Slide 15. As we progress on our long-term development strategy, it's time for us to come to the same level of understanding on developing the Spraberry intervals as we have in the Wolfcamp. As a part of our 2018 program, we're going to execute 3 pads and 19 wells where we're going to be testing various stacking, spacing, sequencing and completion variables between the Middle Spraberry Shale, Jo Mill and Lower Spraberry Shale. We're also excited we're going to be POP-ing our first Clearfork well here very shortly, and we recently completed drilling on another Wolfcamp D 3-well pad in Reagan County, which will hopefully POP in Q2.

Now I'm going to be moving to Slide 16. We are going to be staying at our 20 rigs throughout 2018. You can see there we've included our budgeted well cost and estimated EURs. As Tim's already mentioned, our operating costs remain low and returns are very strong, especially on our 3.0 wells.

You can see our activity mix there in the bottom right. It's really not too dissimilar to 2017 with some slight shift in Wolfcamp B and Wolfcamp A and incorporating some Jo Mill and Middle Spraberry in conjunction with the Lower Spraberry Shale as I mentioned previously.

Now I'm going to move on to Slide 17 and my final slide. Here, we discuss our infrastructure and vertical integration spending. We are highlighting for the first time our 24-well pad below-grade well cellars. We did begin deploying this concept in 2017. In essence, it reduces the surface acreage needed to develop an area by over 80% and allows simultaneous operations during drilling, completion and production without shutting in the wells. It further reduces cost by centralizing facilities and reducing the number and length of flow lines.

Gas processing spend includes capital for 2 new plants that will be starting up in Q1 and Q3 of 2018 and 2 more additional plants slated for start-up in Q1 and Q3 of 2019.

We continue to focus on expanding our water subsystems and minimizing freshwater use by constructing produced water reuse facilities. And we do plan to commence construction on the Midland wastewater treatment plant upgrade with a start-up in late 2020 or early 2021.

Lastly, we are executing contracts for West Texas sand to get our sand cost as low as possible. And as a result of that, we're going to be delaying our expansion of the Brady sand mine.

Overall, a really good quarter for the Permian team and a great year, and we're looking forward to successful execution in 2018.

And I'm going to turn it over to Rich now to discuss marketing and financial highlights.

Thanks, Joey, and good morning. I'm going to start on Slide 18 where we highlight our transportation arrangements to move our Permian Basin oil down to the Gulf Coast for either export or sales to the refineries. Our growth aim for the fourth quarter was -- or currently, we're transporting about 80% of our Permian Basin oil to the Gulf Coast. If you look in the upper left corner of Slide 18, you'll see the places that we're moving and really equally to 3 major refineries and export hubs along the Texas Gulf Coast, that being Nederland, Corpus Christi and Houston. Today, were exporting out of Nederland and Corpus Christi and plan to add Houston late this summer when the construction of the export facilities there are complete.

As Tim mentioned, we are exporting about 90,000 barrels a day out of -- in the fourth quarter, and when you add that to the Gulf Coast sales that we had, we added about $15 million of incremental cash flow during the quarter related to those sales. We do expect a similar amount of exports to be done in the first quarter. We've completed January and February sales and we have one sale done in March and looking to complete March exports over the next couple of weeks.

Currently, we are delivering about 160,000 barrels total to the Gulf Coast. About 110,000 of that can be exported today. And as I mentioned earlier, once the facility is done midyear or so, that'll increase to about 150,000 barrels a day that can be exported.

So long term, we continue to see ourselves exporting about 80% or so of our oil and getting it to the Gulf Coast and then really we can sell it either to the Gulf Coast refineries or the export markets, whichever offers the highest value.

Turning to Slide 19 and focusing more on earnings. As Tim mentioned, we did have net income attributable to common stockholders of $665 million or $3.87 per diluted share. That did include noncash mark-to-market derivative losses of $169 million or $0.99 per diluted share. That's primarily due to higher oil prices at the end of the year compared to the end of September. We also benefited during the quarter from a reduction in our deferred tax liability related to the Tax Cuts and Jobs Act that was enacted in December and effectively what it did is reduced our future -- our tax obligations today from 35% where they were booked in our records at down to 21%. So a big benefit hitting the quarter.

So adjusting for those items, we are at $209 million adjusted earnings or $1.22 per share.

Looking at the table at the bottom where we show our results of operations relative to guidance. As you can see as Tim mentioned, we exceeded our production goals. And when you look at the rest of the items, they were within guidance or on the positive side of guidance. So overall, as you heard from Tim and Joey, excellent operational quarter, but also an excellent financial quarter for the company.

Turning to Slide 20. Looking at price realizations, as you can imagine, this was a big part of our strong quarterly results where we see oil prices increased 16% quarter-over-quarter to $52.81. And similarly, we saw NGL prices up about 14% to $21.64. Virtually all the products were up when you break down our NGL sales.

Looking at gas, gas was down slightly at 2%, so it was the only product that was slightly lower for the quarter.

We continue to benefit, that you can see at the bottom of the slide, from our hedging portfolio. So at the bottom there, you can see by each of our products that we did, bringing extra cash flow from our hedging portfolio.

Turning to Slide 21, which is another significant contributor to the quarter was reduction in our production costs. So quarter-on-quarter, our production costs were down 6%. If you exclude taxes, which were up because of the higher commodity prices, production costs were actually down 11% versus Q3. And as Tim mentioned, the decline is primarily related to the increasing production from our low-cost horizontal Permian Basin wells that we're putting on. If you look at this quarter, the production cost excluding taxes was $1.87 related to those -- quarter related to horizontal wells. If you look at it over the past 2 years, it's been under $2.25. So those low-cost wells, as we add more of those, will continue to drive down our operating cost.

Turning to Slide 22, looking at our liquidity position. As I've mentioned in prior quarters and Tim noted it, we've got a pristine balance sheet. It's excellent liquidity. We ended the year at $2.2 billion of cash on hand. Our net debt was about $550 million. We've got completely unsecured credit facility and we plan, given our balance sheet, to pay off our May maturities and bonds that come due with cash on hand.

Turning to Slide 23. A couple of points to make here, this is our guidance for the first quarter. Just so everybody understands, this guidance includes all of our assets and our guidance will continue to include all of our assets until the divestitures are completed. As Tim mentioned, we are forecasting for the total company 304,000 to 314,000 BOEs a day of production that was impacted by the early January weather to the tune of about 6,000 BOEs a day of production for the quarter. So that's reflected in that guidance range. We do put in here for the first time Permian alone at 252,000 to 260,000 BOEs a day for that information.

The other items here are pretty much similar to where they've been in the past. I'll note 2 of them: one, that we did lower our range for our DD&A going forward, that reflects the reserve adds that we added during 2017 at a low F&D cost. So that will continue to drive down our depletion rate.

And then lastly, on the effective tax rate, you can see here 21% to 25%, really is reflecting the new tax change that came effective January 1, 2018. And really, that tax, while not only was it great for corporate America and the U.S. economy, but specifically for Pioneer, given our extensive portfolio of drilling locations, it's a big uplift to our NAV as well.

So with that, why don't I stop there and we'll open up the call for questions.

(Operator Instructions) We'll take your first question from Dave Kistler from Simmons/Piper Jaffray.

Impressive results, and thanks for the added color on the 10-year plan. Looking specifically at Slides 8 and 9 with your production growth trajectory outlined, declining cash flow, break-even oil prices and total cost structure, free cash flow looks to expand pretty substantially even at the forward strip, which is backward dated. Given the shareholder-friendly actions that you guys have initiated today, is that basically trying to provide incremental line of sight to us in terms of how that cash flow or free cash flow will expand? And as free cash flow is generated, should we expect it to be returned to shareholders?

Thanks, Dave. First of all, as I mentioned in the call, we've taken a first step towards returning cash to shareholders here by virtue of increasing the dividend and announcing the share repurchase program regarding basically buying back creep from long-term incentive plans, shares that are granted to employees for compensation. What we'll do in the face of what you commented on is evaluate that situation over time. It's very clear if you look at the modeling associated with this that we should be generating very substantial free cash flow, I mean, seriously, in billions of dollars over the plan period and that's based on a 55 and 3 case. So we'll be evaluating that through time. And as we head towards a free cash flow generation model, hopefully it's this year, it very well may be next year, of course, with the volatility in commodity prices, we'll make the next set of decisions at the board level. But for the time being, we believe we're taking a good first step and then we'll be evaluating that as we go forward.

Okay, I appreciate that color. And then kind of looking at your details on the operating cost structure at about $19 a barrel in the Permian, obviously attractive as it stands right now. But can you talk about the additional levers or initiatives to drive that lower as part of the 10-year plan? It doesn't look like it's factored in to go lower yet, but I suspect with the infrastructure investments, et cetera, it should be positioned that way. Am I thinking about that the right way?

Well, I guess, you're right. I think there's a couple of angles there. One is, as was mentioned, we'll have completed about 65% of our infrastructure build-out by the end of 2018. With the 35% remaining over a few more years, you ought to see us then begin to reduce how much we spend from an infrastructure standpoint. We have baked into our planning about $300 million a year of infrastructure build-outs in that 10-year model. That very well may prove to be too high, but we want to be conservative in that way. Secondly, what we haven't baked in at all is any sort of improvement from a standpoint of productivity gains, innovation benefits, technology improvement. And those should serve to reduce costs at the D&C line item and I think also potentially in production costs and G&A as we head more towards utilization of new technology and innovation. But even probably more importantly is the fact that as we increase the productivity per well, in other words, as we continue to unlock the secrets to improving completion technologies, to optimize the field operations, then you're improving on the BOE line item. When you're all done with all that, you should see improvement from these levels. And so we're not baking that in, but it gives us more confidence that achieving our goals is doable.

We'll hear next from Arun Jayaram from JPMorgan.

Tim, I wanted to get your thoughts on just the macro picture -- or micro picture in kind of West Texas. Big oil including Exxon has outlined some really ambitious growth targets from the Permian. So just wondering if you could discuss some of the on-the-ground challenges do you think the industry and PXD will face just given your long-term growth profile, which did raise despite the asset sales.

Yes, thanks, Arun. I think, first of all, we're encouraged to see companies like Exxon and Chevron talk about the long-term perspective of their growth rates, and if you look at their data, their ambitions are not dissimilar from ours as to the amounts they want to grow and the doability of that. I think if you look at it from this standpoint that we're all going to be in a mode of growth, one of the critical current issues is to make sure we can man the frac fleets, man the rigs, personnel needs are going to be significant. That's why some of the companies are coming together to start this process of looking at Permian Basin infrastructure needs, which should be able to make sure we can support the drilling campaign going forward. And so we're working in a new group effort among CEOs called the Permian Strategic Partnership to do just that, to look at opportunities to support infrastructure build-out, to get to meet people we need and to provide for the development of the basin over what's going to be decades of drilling.

Got you, got you. And just to that point, in terms of the future build-out of the vertical integration, how do you plan to invest between kind of company-owned fleets and third-party fleets on a go-forward basis?

That's a great question. I think we've really been the beneficiary through time of owning our own vertical integration when it comes to pumping fleets. And the reason I say that is when times are really strong as they were in 2010 through '14, we quickly paid for all of our equipment investment when margins were 100%-plus. When margins have been lousy in the downturn, we've been able to keep active, which is one of the reasons to make sure we maintain our rpms of the organization, but in doing so, we keep our employees. And so we're ready to roll with our 6 or 7 fleets in any given time coming out of the downturn where others are scrambling to get people. So there's tremendous value in owning our own pumping fleet. That said, we do use one outside fleet today and the decisions going forward are surrounding just the basic buy-versus-lease decisions. We know if we own these fleets, we control our own destiny, we can control the costs and we can make sure that they are there when we need them there. But there's a lot of great companies who are pumping wells as well. ProPetro has done a fantastic job for us as a third-party provider. And so they would be the model example. Someone we might want to bring in as third parties -- more third-party fleets. This is in the fullness of time something we'll have to evaluate. In our case, we have 2 fleets that we're considering revamping, renovating that would put us up to 9 fleets. That would certainly take care of us for the next year or 2. At that point in time, we've got some decisions to make.

And my final question, Tim, is just the LOE on the horizontals below $2 pretty differential kind of versus your peers? Can you talk about what is driving that? Is it some of the investments you've made on the infrastructure side kind of driving that LOE?

Well, LOE generally is not related to infrastructure as much as it is. The total cost in the LOE are generally going to be personnel, they're going to be electricity and they're going to be chemicals and this kind of thing. So chemical costs certainly are something we're trying to drive down. Personnel costs probably have an increasing labor component just based on the tightness we discussed earlier. Electricity in the state of Texas, I think, has been relatively cheap and probably will remain that way. So I think the real productivity gains on LOE per BOE basis is on the BOE side of the equation. And to the extent we make more prolific wells, and there's a certain fixed cost component of drilling them and completing them and then producing them, then -- labor would be an example, then we would have the opportunity to potentially reduce that. But one thing we're looking at, of course, is doing a lot more operations remotely in our field. And this involves remote telemetry and remote surveillance such that we don't have to have people running around every single well every single day and that's going to reduce the body count when it comes to the total number of people we need as we move forward. So those, our field people, are really outstanding employees can work on actually improving field operations versus just driving with windshield times. So there's a lot of ways we can focus on it. I can assure you it's a big push internally.

We'll hear next from John Freeman from Raymond James.

When I look at the 3.0 completions, which continue to perform quite well, and Tim, you said it's something that you're basically going to evaluate kind of midyear and then determine what to do from that point forward, I'm trying to get a sense of how much flexibility there is in the plan to kind of adjust to like a 3.0+. Is it really something that's more like a 2019 event? I just assume a lot of planning goes into the '18 budget so kind of changing to a different completion design on the fly in the middle of the year, you might not be able to push it up too much in the back half of the year even if the results continue to look as strong as they have.

That's a great question. I think, John, if you look at it, we're already prosecuting this plan now, so we should be seeing results beginning probably in the second quarter. So you're exactly right, once we decide to pull the trigger, let's say, if we were to add more 3.0+ style wells, really in a lot of cases, that involves acquisition of more sand, more water, making sure it's on time and in place and we have the right horsepower in place. So it could have some effect clearly on the second half results. It's just that we want to make sure we have a full set of data to make that decision. But you're exactly right, I think, when you say what would be the main focus when we seriously ramp that 3.0+, it'd be 2019.

Great. And then just my follow-up question. You were able to reduce the percentage of the 4-string casing designs. And if you could just sort of elaborate on what allowed you all to do that? And then the outlook for potentially reducing the percentage of the 4-string casing designs further from here.

There's a lot of reasons that we actually have done that. First of all, we've done a lot of learning regarding the last 6 months or so about areas that we can use 3-string casings. We've gone back to some of those areas and reevaluated sort of a modified 3-string design and that's one thing I think you expect us to do, just improve and to understand where it is we can get away with 3-string on the basis that it is cheaper. But there are other factors, too. One is to the extent we use more of our produced water, in other words, more water reuse, which we're going to take that out to about 15% or 20% of our total water needs this year from 5% last year, that means we're taking water away from otherwise that which needs to be reinjected, which is half the battle. So we're looking in that direction. The other thing is we're doing, we're moving water away from active drilling areas, which has the same effect. And finally, we're going to be drilling this year 5 Ellenberger wells. These are deep disposal wells in certain of our more active areas so as to, again, reduce the impact of injecting water into the shallow formations that have caused us some issues in the first place. And so the reason we can go to 50% is we're taking very -- these various steps and initiatives to do so simply because it's in our economic interest to do just that.

Your next caller is Brian Singer from Goldman Sachs.

Can you add more specifics on the advantage that you're seeing from sourcing sand from local third-party mines versus expanding your Brady mine? And then what do you also see as the risks around that?

Sure, Brian. I think, first of all, it's a little bit early days for us. We have signed our first contract. We'll be taking deliveries of our first Permian dune sand or Western sand, whatever we want to call it, probably in April. Simply said, the advantages of that are associated with its proximity to the field. And in particular, the fact that the relative cost of mining that sand, simply because it's sitting on the ground, is substantial -- they are substantially less than mining in the Brady area where we basically have got to blast the sand and crush it. So it's just simply a matter of cost on the one hand. The other thing to note is this is, in principle, mostly 100-mesh or 40-, 70-mesh sizes. In other words, relatively small grain sand, so we are in the process right now of testing in various pilot projects the finer meshed sands to make sure that we wouldn't have any degradation of well results. The current feeling internally is this would not be the case, that the 40-, 70- and 100-mesh will work just as well as some of the coarser grades. But that is something we've got to be protective about. Of course, the thing about is there's going to be a lot of mines that seems like they're going to be put on reduction in such that we might have various different suppliers that would allow us to then, as was stated earlier, not proceed with the expansion of Brady to the extent that's a substantial amount of capital we'd rather put in the wells. And so I think the main objective is to go through the technical work, make sure that we, in fact, can lock in low-cost sand. We may be able to reduce our sand cost by 20% by doing this and that's -- so there's a substantial carrot out there for us to prosecute on this point.

And then you talked a little bit earlier just on some of the labor issues that are in the broader Permian area. Could you just talk about the risks and inflationary pressures? And maybe it's not this year if your plan was already in place, but do you see that as a major issue, minor issue or no issue as you think about '19, '20 and the growth profile over 10 years?

I think, first of all, the labor issue today is exacerbated by the fact we had the hurricanes and the needs for the repairs in both Houston area as well as Florida as well as was what's a relatively low unemployment rate in the United States and certainly in the Southwest and particularly in Midland-Odessa area. Accordingly, one of the near-term effects, I think, will be inflationary in the sense that we're estimating labor costs up probably in the neighborhood of 10% this year compared to last year. So that's more of a short-term issue. The longer-term issues are associated with bringing in a workforce, which is ready to work. And what I mean by that is since we've gone through 2 downturns essentially in the last 9 years, we've got to bring in a new style of employee, and in this case, hopefully new technologically advanced employees who are ready to work in the new model. And they're going to need training, they're going to need safety training, for example, they're going to need operational training. And we're going to have to build basically a new style workforce out of the fact that we've sent 2 groups of people home in the last 8, 9 years. So we have a new style of employee coming in. So it's going to behoove the companies, notwithstanding Pioneer, to make sure we provide infrastructure and the opportunities associated with Midland-Odessa being outstanding places to live and work.

We'll hear next from Michael Hall from Heikkinen Energy Advisors.

Just following on some of the questions around the long-term outlook. I guess, if I'm thinking about the 2018 program, you said that it's -- you'll provide some free cash flow at the current strip. If we kind of run sensitivities off that and look at the breakeven you're talking about in 2020, seems to imply couple hundred million dollars of free cash flow, but by 2026, given some prior comments around rigs, potentially upwards of a couple billion dollars a year of free cash flow given like a low 60-type rig count in 2026, is that a fair way to think about it? And do you -- is it kind of a linear, I guess, progression at 55 and 3 from 2020 to '26 as we think about free cash flow?

I will just summarize the answer to your question being our modeling looks similar to yours.

Okay, good to hear. And then as we think about the Wolfcamp D, how are we thinking about well cost differences there? Sorry if I missed it, but I don't think I saw that in the slides.

Yes, Michael, our Wolfcamp D wells are obviously more expensive because we only just recently drilled them. We're still looking at what the drilling costs are, and of course, as the drilling is more difficult, so is the completions. But the good thing that I can tell you is that in this last run because we have had so much success in drilling and progressing our drilling, that the Wolfcamp D wells have been a nonissue in regards to drilling. We've been able to successfully execute those. But because we've only got a benchmark of one, we haven't really established what that cost looks like, but it'll just be slightly more expensive than what you would see with the Wolfcamp B well.

Yes, the other way to think about it, Michael, is it's just deeper. So by definition, it's going to be slightly more expensive.

Right. Okay. Any completion challenges that come with that depth, and I assume, higher pressure?

Certainly, with deeper is more pressure, and with that, it does require a little bit more horsepower. And what I can tell you is we successfully deployed the completion on the first well and we'll be doing the next 3 wells here in the next month or so. We learned a few things on that first one that we'll be deploying on the second one, but our long-term outlook is that we don't foresee any challenges associated with those wells. It'll just -- you just kind of work your way through it like we have everything else and we'll hit our stride on it shortly and we see Wolfcamp D being a big part of our program going forward.

Okay. And then, I guess, as I think on the Wolfcamp D, you said 60% of the acreage kind of was in the fairway. What are key attributes of -- what's defining the fairway for the Wolfcamp D from your perspective?

Well, of course, just like we prosecute every single zone substantial data on the Wolfcamp D from a geologic perspective and so it's exactly the same parameters that are evaluated to assess the prospectivity of Wolfcamp D as we use with the Wolfcamp B, for example. So it's things like the hydrocarbons in place, it has to do with porosity, it has to do with the lack of clay content. It has to do with pressure and so on. So what we do is sort of a Venn diagram to assess all of those parameters and that leads you to where you have the most prospectivity and so, therefore -- and thermal maturity being another example of that. There's about 8 different -- or 10 different geologic parameters we use. And because we have such prolific data in the basin, we can actually pinpoint where it is this prospectivity is going to be actually before we even drill wells. And that gives us a huge advantage moving forward for optimization.

Your next question will come from Scott Hanold from RBC Markets.

Can I ask, you obviously talked about the asset monetizations in effectively everything but the Permian. And could you just give a sense when those proceeds do come through? How do you think about allocating those when you look at your incremental drilling and other shareholder-type initiatives?

Well, certainly, this is a bigger question for us long term as opposed to just associated with the asset divestitures because, as has been earlier mentioned by Michael, we have a substantial amount of free cash flow generated in the longer-term model. And so I think we have to evaluate all those levers. So if you look at what we've said in the past regarding the model and the 10-year vision, the last thing we want to do is accelerate faster than make sense. And by making sense, I mean, that which the organization can operate efficiently out on the one hand, but then, secondly, to make sure the margins are intact. Last thing you want to do is, in the face of an inflationary market situation, be revving up and being -- having reduced returns or diminishing returns. And so that'll always be something that's a possibility to tweak the rpms, the engine up a little bit faster as to drilling, but we'll have to temper that with the notion we don't want to impact negatively our returns. And as I already mentioned, one alternative we've already moved ahead on is the first step regarding returning cash to shareholders as has been stated many times. That is something we'll be evaluating and -- particularly when we do get to free cash flow generation model.

Okay. All right. And with regards to a lot of the testing you're doing, can you just give a sense of what is the goal and when do you think you can achieve that by? So for example, is it to figure out effectively how this is going to look in full development and that's what you're targeting? And when do you think you could have that in? And one last part of this long question, how come the Wolfcamp C is not part of the delineation and testing process?

Well, first of all, we've done a lot of work, as you know, through the years now. It seems to be a short time, it's really years, of developing our knowledge of Wolfcamp B, the Wolfcamp A in terms of how that drilling campaign is laid out unless in the Spraberry zones. So Joey talked about this. But over the next few years, there's no reason to think that the Middle and Lower Spraberry and the Jo Mill in combination, referred to as the Spraberry zones, wouldn't be a significant contributor to our growth. But we want to make sure we do the proper work in terms of sequencing and stacking, spacing and so on that allows us to have confidence that we're optimizing the development of those. So that's, in fact, exactly what we're doing right now. 2018 is a very important year as we look at that -- those series of pads to evaluate those exact questions. So those are what we referred to. On Joey's slides is one of the sets of appraisals we're doing. So once the appraisals are done and we understand what's optimal in certain areas, then we head off into more of a development scenario. So you'll notice it on his slides, he actually has several areas where we're in appraisal and in particular there are those 3 zones, but also we have the Clearfork zone. This is our first well so we're far from development of the Clearfork. In Wolfcamp D, we mentioned really an outstanding well, but then 3 more utilizing the higher intensity completions this year. So we're not really ready to head off to development at Wolfcamp B, although that may be something that is a product of the drilling campaign. Finally, on Wolfcamp C, it's, I think, very prospective for us. I think if you look at the work Parsley has done down there essentially in the Reagan-Upton line, those are some excellent wells and they set up and basically prove out 900 Pioneer locations in the Wolfcamp C. It's just that they're sort of down the (inaudible) where we've got a bunch of other things to achieve at once. So we eventually will get to Wolfcamp C development drilling. We're very happy Parsley is drilling some wells in there so we can learn from them. So that's kind of the way I look at as how it's set up for the future.

We'll move next to Bob Brackett from Bernstein.

Follow-up on this popular Wolfcamp D appraisal topic. Are those 3 appraisals coming this year, are they offsets to the Shackelford or are you testing other counties or regions?

No, they're down in Reagan County so they're further south.

All 3 of them are in Reagan?

Yes, it's a 3-well pad.

We'll hear next from Matt Portillo from TPH.

Just a follow-up question around capital allocation and the balance sheet. Obviously, a lot of conversations this morning around free cash generation. But curious to your thoughts on your business model moving forward and the use of the balance sheet and how you think about the appropriate leverage metrics as you think about your business model long term given that you start to move into a net cash position with the free cash generation.

Well, I think the main objective we've had through time is to have a pristine balance sheet. I think it's clear that we have that today. I think you have to look at this in connection with the fact it's hard for us and maybe it's the case we've been proven to be not very good forecasters of future oil prices. We can't preclude the possibility of lower oil prices than we're achieving today. And so we always want to make sure that our balance sheet is prepared for that eventuality. The long-term model has us from that standpoint in pretty good positioning because if at times we can generate free cash flow because prices are in excess of $55, then we can hoard that cash and/or do shareholder-friendly things. To the extent prices are below $55, we can utilize the balance sheet to make sure we can drill through the downturn. I think the last thing we want to do is to have a situation where we have a downturn, and I'm sure there'll be one someday again where we then don't drill because then in essence you're missing the opportunity to drill wells at the cheapest cost that you'll ever achieve, which is what we proved in this last downturn. And so we want to make sure the balance sheet is in good stead for all the ups and downs. And so I think from that standpoint, our main objective will be always to keep an exceptionally strong balance sheet.

Great. And just a follow-up question around your midstream infrastructure. You've built an extremely valuable asset base here over the last few years and continue to invest in that business going forward. How do you think about the vertical integration of midstream assets within your business model and the ownership of some of the assets, particularly around gas processing, as you progress into 2019 and beyond?

That's a great question because we have a wealth of value created by our Water business, our gas processing business, our sand business and our Pumping Services businesses just because of what they allow us to achieve. But the fact is the reason we do those ourselves is because we want to make sure we have the ability to execute on our plan. And so for the time being, what that means, if you use gas processing as an example, we want to invest in new plants with our partner, Targa, to make sure the plants are there on time and ready to take new gas supply, considering gas volumes are considerable in the Permian Basin and growing. And so to the extent we're an equity owner in that system, we can have a positive influence we feel like in dealing with our partner to make sure that we get these plants there in time for our production. Similarly, in our water business, our water business in the fullness of time, once we have it all fully constructed and sourcing the Midland water, will be saving us some $500,000 per well. So at some point in time, we may consider some change of ownership. For the time being, we're building out the system. We're making sure we have water as we prosecute our system. Eventually, we may even be further into water sales as an example. But the fact is we want to build this out and make sure we can execute. At that point in time, we'll evaluate other alternatives considering the value that we've already added.

We'll move next to Jeffrey Campbell from Tuohy Brothers.

My first question is -- will selling your Eagle Ford assets create any reduction of Pioneer's export volume potential in 2018?

No, because we're not really exporting condensate today and so I don't anticipate it changing any -- the volumes that you see on our slide that we presented are all Permian Basin ones, so I don't see any change.

Okay, great. If it proves successful, I know it's early, but if it proves successful, how repeatable do imagine the Clearfork might be in your northern acreage? The Clearfork's had a historical reputation for having heterogenous geology.

I'm not a geologist so unfortunately I'm not going to be able to answer that question. I can get you an answer from our geo team, but I think if you look at it, maybe we'll just simply say let us get a well drilled, we'll evaluate it in connection with the rest of our geologic data and then we'll come out with a view on that point.

Okay, that's fair enough. And my last question was with regard to the coproducing of the Jo Mill and the Spraberry that you're testing. At this point in time, does this look like it's going to be more of a sweet spot deal? Or does this look like it could be something that can cover -- you have a very large aerial extent at Jo Mill test that you showed on Slide 13. Is this potentially available to that entire area that you show?

So if you look at the geologic data across the basin, what you will find is especially in the northern acreage, the Jo Mill and the Lower and Middle Spraberry zones are ubiquitous across the entire acreage position. Now of course, just like everything else, there are certain areas that are slightly better than others so our objective is going to start optimizing around where to place these pads that are reaching out and touching all 3 zones. But I can tell you it's a wide swath of acreage just because each of those zones is, in fact, ubiquitous across the entire northern acreage. Less opportunity probably to the South in the Wolfcamp -- the Southern Wolfcamp area. And the reason we can tell you that is because it's the case that essentially every single vertical well that were drilled in the last 5 to 10 years prior to the horizontal campaign were, in fact, completed in the Spraberry zones and the Jo Mill. So we have a virtual complete data set to be able to answer that question.

And that does conclude our question-and-answer session. I would like to turn the conference back over to Mr. Tim Dove for any additional or concluding remarks.

Thank you, everybody, for your participation and your questions. I think it was a great quarter for Pioneer. You will see us on the road. We will be at various energy conferences coming up here for the next couple of months. We look forward to seeing everybody and looking to opportunities to discuss these topics even further. So thanks for participating on the call.

That does conclude today's teleconference. We thank you all for your participation.