Thank you, Anna. Good morning, everyone, and thank you for joining us.

Let me briefly review the agenda for today's call. Scott will be up first with some introductory remarks.

He will then discuss our strong fourth quarter and full year 2019 results, driven by solid execution and continued efficiency gains from the team. After Scott concludes his remarks, Joey will review our strong horizontal well performance optimized the rate of return, while delivering best-in-class oil production, as well as the drivers behind 2019 strong efficiency gains.

Rich will then discuss the benefits of thoughtful long-term planning and the impacts of our cash flow, as well as the benefits from our legacy acreage position. Scott will then return to discuss Pioneer’s focus on sustainable practices.

After that, we will open up the call for your questions. Thank you.

So with that, I'll turn it over to Scott.

Thank you, Neal. Good morning and thank you for joining us.

As you all know, 2019 was an excellent year for Pioneer. As we will outline, we expect 2020 to be even better.

When I returned to Pioneer in February '19, we set out a number of specific initiatives to return Pioneer to top performance. I'm happy to report all those objectives we had are now in place and now complete.

While its difficult decision, we rightsize the organization reflecting one basin company reducing our G&A to be top quartile. We organized and flatten our reporting structure, which had the intentional benefit of providing greater transparency and visibility across all levels, resulting in a company highly focused on strong execution and capital discipline.

Thank you, Scott. Good morning everybody.

I'm going to be picking up on Slide 17, continuing a theme from the last two quarters and starting on the left hand side of this slide. You can see that when you normalize gross production for all peers on a two string basis, Pioneer has the highest little percentage.

And then moving over to the right, we also have the best 24-month cumulative oil production. So simply state that Pioneer has the oil is production mix and drills the most productive wells in the basin.

These two facts, of course, combined should lead to the best margins and the highest returns in the basin over time. Now moving on to Slide 18, as Scott already mentioned, our execution teams had a tremendous year, most notably by reducing our well costs by 30%.

As you can see on the left, a large portion of these savings were driven by significant efficiency gains. Our feet per day in both drilling and completions have improved over 30% since 2017 with most of these gains coming in 2019.

And although not highlighted here, and as Scott has mentioned, our operations team also realize significant cost reductions and facility construction, and we've also achieved significant reductions in LOE.

Thanks, Joey, and good morning. I'm going to start on Slide 19.

And this slide really there is to highlight the attributes of Pioneer’s assets and the strategies that we employed to improve margin, generating strong margins, as you know, is a key to improving quarter returns, maintaining a strong balance sheet and returning capital to shareholders. You can see it on the graph on the right that we generated share-leading EBITDA per BOE margins.

This incremental margin relative to our peers is a function of the higher percentage of oil that we produce in our wells that Joey just talked about, our high net revenue interest in our wells that I will talk more about in a minute, and maximizing the price that we received from the products that we sell by moving into higher priced markets. It's also driven by protecting our cash levels derivatives, and as Scott talked about, a strong focus on reducing our cost structure.

If you look at the graph, it is just for the third quarter, just to give you an updated view, recalculated on a four quarter basis, our EBITDA per BOA increased about $31 per BOE, reflecting the benefit of higher commodity prices during the fourth quarter and the company's continued cost reduction efforts. Turning to Slide 20.

This slide really highlights the benefits of our legacy acreage position where we have low bases and high net revenue interest. You can see from the chart on the left, the benefit of having a high net revenue interest.

The chart illustrates how much incremental drilling activity that our peers must execute in order to accomplish the same level of growth as Pioneer. In addition to more efficient growth, our high net revenue interest across our acreage also provides for better returns and higher margins as Joey has discussed.

And then when you think about it from a drilling inventory report perspective, the chart also illustrates how much faster our peers have to drill through their inventory to accomplish the same level of growth as Pioneer. Turning to slide 21.

This is where we highlight the focus of our improving cash flow margins by moving our product to higher-priced markets and using derivatives to protect cash flow. In particular, during the fourth quarter, we significantly improved our gas price realizations by selling our gas outside of the Permian Basin.

With Gulf Coast Express coming online, we transport near the all of our gas to the West Coast or the Gulf Coast selling it there versus selling it in the Permian Basin. This resulted in gas price realizations being $2.21 per MCF versus if we’d sold it in the Permian being based off of Waha Index of $1.11, so a significant uplift.

On the oil side, we transported nearly all of our 220,000 barrels a day production to the Gulf Coast and 95% of it was exported during the quarter. So you can also see on the right side of the page that we have a strong derivative position for 2020, where 67% of our first quarter oil production and 54% of our full year oil production protected with derivatives at $62 Brent prices with upside to the high 60s.

As a result of his strong derivative position, our cash flow variability between 55 and 50, as Scott talked about, is only about $200 million. So you can see that we're well-protected in 2020 from oil price volatility.

I'll stop there and turn it back over to Scott for some discussion on environmental progress.

Thanks, Rich. On Slide 22, delivering low mission barrels, you can see where shale oil is a closer to leading the pack in regard to total intensity including methane.

This is coming out of a WoodMac report, with McKinsey report that was published recently. When you look at Slide #23, where the lowest of our peers in emissions intensity where Pioneer on both greenhouse gas intensity and also methane intensity.

This is primarily due to the fact that we have some of the best LDAR programs, lead detection and reporting, low-level flyovers that we're using one of the few companies as doing low level flyovers within technology. Our VRU captures vapor recovery units.

We’re one of the first to require every gas line has to be connected on essentially all new horizontal wells. And what are the major changes we're making in our ESG in regard to compensation, we're increasing that these from 10% to 15% going forward in 2020.

Looking at Slide 24, in regard to the flaring, obviously, it's been in several newspapers, including the New York Times recently. Pioneer happy to report we're now Number 1 in regard to -- we had been Number 2, when you look at some of the data in 2018.

Looking at the data in '19, Pioneer was down less than 1%. At #1, we recently probably had the largest flaring, the first and the largest flaring conference in Austin, Texas that was put on by Columbia and UT Energy Institute.

I think coming out of that conference, we have agreed, and we'd like to get all producers committed to this. We're committed to better reporting to all agencies both in the State of Texas and New Mexico.

We're committed to sharing best practices among all producers. And thirdly, a couple of interesting ideas came out.

We think it's important to set a percent target. And Pioneer would like to be able to continue to produce below 2%.

If you look, there's only really six companies that are below 2%. I think every CEO should set a target of 2% or less.

It will help solve the problem. And the another interesting idea came out of the conference and the fact it's back to the shareholders, shareholders and public companies, shareholders and private equity companies, shareholders in regard to bonds that are being done is that if all could help and also require companies to be 2% or less, they're not 2% or less within a certain period of time, especially when the two new pipelines come on in the first half of 2021 that you would end up either not doing business or sell whatever you have in regard to that company.

That would also help. So those are some of the interesting ideas coming out of that conference.

I think it's important to remove that black eye on the Permian Basin going forward. Final slide on number 25, again, the company, tremendous turnaround from 2018, focused on returns, capital disciplines in place, return of capital in place already.

Great, probably, the best balance sheet of any independent in the US. And we have probably the best inventory of any company going forward.

So I'm going to stop there, and we'll open it up for Q&A.

So you're investigating the possibility of a variable dividend, Scott, how do you think about where the prudent think of the base dividend. You say in the deck that you will continue to increase it.

How do you think about where to take it? Do you think about percentage of cash flow, percentage of cash flow above maintenance CapEx and framework on that front would be great?

Yeah, we haven't established a percent. I mean, we're looking at other – and studying other industries that have had variable dividends.

We've had several companies in other industries that have accessible variable dividends. We've got a lot of those comments from in talking to a lot of our shareholders over the last 12 months.

We'll be going out again and visiting with our shareholders over the next two to three months in March and April, with deployment and talking to them and go into a couple of the conferences, and still trying to establish it. But at the end of the day, we already have a great balance sheet.

And we're going to establish a base and then base is going to be, say, eventually close to the S&P 500 around it, and we're slight increases going forward on that base. But then when you look at the amount of free cash flow the company has, and we've mentioned before, I did in the Barkley's conference, that we have over $5 billion in cash over the next five years, you still have sufficient amount of free cash flow.

What do you do with it? And like I said, don't want to -- and most of our shareholders that we've discussed, do not want an EMP company getting your base up so high.

And so it leads toward a variable dividend. And so we'll have to come up with the mechanics as we develop our first year -- significant free cash flow over and above our base dividend in any stock buybacks.

That's what's left and have to come up with a plan. And we'll be visiting with everybody as we speak with you over the next several weeks.

Yes. And Scott, just one other thing to add to that, we believe that it's important to have a stable and growing dividend.

So I think that’s kind of underpinning on the base. But we also think about that growth needs to be consistent over time with the S&P 500 or slightly better.

So -- and that's where we want to -- overtime, lead the base dividend.

Great. And unrelated follow-up.

If I look at Slide 5 in the deck, you guys have made great progress on well costs during 2019. You showed continued efficiency gains into '20.

If I divide the midpoint of your core CapEx, it’s like about 315 of your top guide of around 360. I come to an average well cost at around the 2019 average.

Why isn’t that simple math showing a greater reduction? Is there something that's impacting the year-on-year comparison?

Hey, Scott. It's Neil.

If you look at what we did in 2019 and a capital program, the 2020 capital guidance also includes any potential rig gas towards year end that we require for 2021, again, similar to what we did last year. So that's embedded in there as well.

Also that range encompasses somewhat and correlates to the range in POPs. So there's a correlation between the two.

Also, I'd say, if you look at a strong efficiency gains that we experienced throughout 2019 that led us to over accrue slightly based on Q2 and Q3. So there's a one-time benefit to Q4 such as the Q4 run rate would be somewhat higher.

So, if you encapsulate all those three factors, that kind of leads into the range where we currently stand.

Scott, you've previously talked about $5 billion of cumulative free cash flow over a 5 year period. I'm curious with the significant reduction in well costs that you've shown here.

What you were assuming in that $5 billion number. I'm just curious how you see that free cash flow visibility today at under the same price deck?

No. The number really hasn't changed, Doug, since my announcement in September, at the Barclays Conference.

So the number is still about, look, it's a little over. We’re rounding off that to $5 billion of free cash flow, and that's in $55 WTI flat during that timeframe.

Obviously, more bullish, especially with U.S. shale essentially slowing its growth significantly going in 2020 once we get through the coronavirus demand issues.

I'm more optimistic that we're going to see a much higher price deck over the next five years. And that number will increase substantially.

And as we go out over time, that number will increase, even in a flat price of the market, because the first couple of years, it's a little bit lower and then it increase significantly as you get into year 2022 through '23, '24. The number keeps increasing significantly.

Thanks for the color. My follow-up is just a couple of things you mentioned in your prepared remarks about DrillCo and the water still under evaluation.

I just wonder if you could just bring it up-to-date as to how you see that the potential for additional noncore. I don't want to say divestments, but initiatives through lease additional volume, especially from your longer-dated acreage.

And if you could bolt-on for that, just remind us what the invested capital in the water business is as of today? I'll leave it there.

Thanks.

In regard to the water, as I stated before, we do not want to trade costs. I think most of the companies that are doing water deals, they’re doing disposal deals, and they're basically trading -- they're bringing in capital or cash for the balance sheet and their operating costs are going up.

And so, we just don't want to trade costs. And that's why we're taking more time and we won't make a decision until late 2020.

So we just don't want to trade costs. We see an increase in our LOE costs.

And Doug, in terms of the dispositions, I think as we did in 2019, similarly, we'll look to opportunities to continue to monetize long data to noncore inventory in an effort to pull that value forward to shareholders. But they'll have to be when they come to fruition.

So nothing on the docket, just we'll continue to look at it.

I was going to say how's he appetite for acreage deals at this point? Is it pretty quiet or how would you characterize that?

And I leave it there. Thank you.

I characterize it pretty quiet. I think, here's the activity level.

They’re strategic in nature. What you've seen this people doing deals that are locking up acreage, similarly doing trades.

And so just making drill longer laterals.

Scott, I was wondering if you could, perhaps elaborate on details of the target agreement and how this will impact, I call it, the go forward financials as you're no longer going to be incurring that CapEx.

Hey Arun, it's Rich. I'll tackle that one.

We've been working with Targa as Scott mentioned for a number of months on our non-content agreements that we recently completed. So with that agreement done, they will fund the capital going forward on 100%.

And they'll get 100% of the revenue on new plans, but we'll still retain our cash flow from the existing plans. So the benefit that we show in LOE and have been showing will continue from our existing ownership and those plants that we invested in the past, but future ones Targa will take the revenue from that.

Great. And just maybe a follow-up to Scott’s question, on the variable dividend.

What is the path from here? You're going to be evaluating this with your major shareholders.

Scott, what are your philosophical views on this? And if you did decide this year to shift to a variable dividend call it distribution type model in addition to the base dividend, what are you thinking about in terms of timing of implementation?

Well, like I said Arun, the first thing, the first comment is that I'm going to say most maybe 75% to maybe as high as 90% plus of shareholders that I've talked to, and we'll talk to, they prefer dividends over share buybacks. So I'm starting with that premise.

Secondly, we don't want to get the base too high as we are seeing with major oil companies. And we have seen with refining industry as to where the EMP industry can’t support it.

So that leads to an alternative when we have $5 billion plus of excess cash flow. And I think we're generating, right now, our dividend payout is roughly $360 million a year times five years.

So what's that $1.8 billion, close to $2 billion. So we're paying out $2 billion already with our dividend of $5 billion.

So we have $3 billion left to pay out under that price scenario. And so that leads toward a variable dividend.

We've got a fluctuating commodity price market. And the question is how much of that and the timing of it, and when to pay it out?

And we're still working through the mechanics in learning about how other companies do it in other industries. And we'll be speaking with people over the next several weeks about how to put it.

My question is on your FT agreements. My question is on your FT agreements.

I believe Pioneer has now well over 200,000 barrels a day of firm transport to the Gulf Coast. And I think that's supposed to grow over time with production, maybe not exactly in lockstep, but that it would kind of keep pace.

I'm not sure if I'm thinking about that credit lease or any color would be helpful. But, I guess, what I'm getting that is the WTI Brent spread has been narrowing relative to where it's been over the past two years or so.

And you've got some kind of spread that you need to breakeven on your contract. So I just wanted to check in to see if there is any appetite to revisit the amount of incremental FTE you take on from here on out over at a medium or the long-term?

Yeah, Jeanine, you are correct that we are moving about 220,000 barrels a day. That does grow over time to over 300,000 barrels a day that matches our growth profile going forward FT.

I still think that moving it to the Gulf Coast in long term will be advantageous for getting it to higher priced markets, where we can get Brent pricing for it. Yet today, it’s kind of a neutral breakeven proposition, but for the year, we made $283 million.

So I think there will be time to still -- is advantageous to get the higher price markets. So I don't think we're going to change that strategy.

I think in general, with the differential between Midland and Brent price is being $4 to $5 a day, it's a breakeven type transaction. But we are making sure that we're available in there and we could benefit when we see price spikes in the future.

Thanks. I appreciate the time.

I'm just kind of curious as I think about efficiencies and all the costs improvements that you rolled through the system in 2019 kind of set yourself a pretty high bar there. How do you think about further efficiency gains in 2020 and beyond?

What can really move up from there? Or are we really just kind of looking at incremental changes?

And what sort of key initiatives you have in place for further improvements in 2020?

This is Joey. Yeah, I think, as we pointed out that whenever you have a year, where you get almost 25% efficiency gains in one year and 30% cost improvement, it's not reasonable to expect that you would duplicate that the following year.

And I think one of our slides basically references a trajectory we shouldn't expect it to be the same. Having said that though, that doesn't mean that we're not still being relentless about focusing on those initiatives and continuing to drive our costs down, and we continue to do so even as we move forward, we see efficiency gains every day.

But like you said, we shouldn't expect to see a similar step change. But as for what are we going to focus on that we're going to continue to focus on the things we've been focused on.

And that's primarily just looking at the efficiency side, lane manufacturing methodologies and being relentless with KPIs and measuring what we're doing out in the field, and trying to understand better and more effective ways to go about that, continuing to leverage technology as it develops through our service companies and through our internal efforts and taking on those kinds of things. We're trying to make our practices consistent all across the field, taking kind of a Southwest Airlines methodology, or any pilot can fly any plane and having consistency across all of our drilling rigs and frac fleets.

So just the combination of all those efforts leads me to believe we still have several bites at the apple, but to expect that it would be similar to what we saw this year is probably not reasonable.

That's helpful. And I guess as a follow-up on a similar topic then, and you've talked about for a long time or late last year plus two to three wells, sorry, two to three rigs -- incremental rigs to maintain or sustain the mid-teens gross in oil.

Is that something that maybe over time the required rig adds gets muted or any evolution in that? I guess as you think about 2021 and beyond?

Yeah, Michael, I know that we always try to communicate and use things like rig adds and frac fleets and POPs as proxies to determine future performance. But you know, I think, stating the obvious, when you have a 25% improvement in cycle time in one year, you cannot change that mentality.

And frankly, my team's focused on trying to do the same amount of work with less equipment. So like you said, when you have -- or like I said when you have a 25% improvement, that implies that you need 25% less equipment.

So it's getting more and more difficult for us to explain our business based on rig adds. Having said that though, I -- that's still kind of our mentality that we'll continue to focus on the growth and our expectation would be based on current efficiencies that two to three rig adds per year would be kind of the measure by which you should see our activity increase, but those numbers change by the day.

You'll show the average pad size in 2020, moving up a little bit to four wells per pad. Is the well spacing still similar to what you all kind of characterized in the past, kind of around that 850 foot spacing?

Yeah, John, whenever we talk about increasing pad sizes, that's really not a reflection of a well spacing. It's more a reflection of doing more stack developments.

So the short answer to your question is that does not imply any change in our well spacing. Our well spacing is basically staying in the same area, 800, 850 feet for the Wolfcamp zones.

Okay. And then just the follow-up, should we anticipate the pad size sort of continues to kind of creep up in the subsequent years?

Or is kind of four wells per pad about the right number?

No, I would expect as we increase the amount of stock developments that we're doing and co-developments that we're doing that you would see that increase in time. A good example is, last year, I think 35% of our targets were a single zone targets, and this year that's down to 15%.

We'll continue to drive that down as we kind of hone in our development. And so you'll see the number of wells per pad creep up over time.

Good morning and thanks for all the comments. So my question is about natural gas and NGLs.

It’s not the most important part of your portfolio, but it's so important. What assumptions do you make about, say, Waha gas prices going forward?

Do you assume basically close to zero? What assumptions you make about NGL prices?

And what do you do to maximize the value of those assets as production increases?

Yeah, Joe, I think the big thing on natural gas is that we have very little gas. It's now exposed to Waha, virtually all of our gas is either going out West and getting out based on Socal index or going to the Gulf Coast on a Henry Hub or NYMEX Index.

So we've made steps to make sure that we're not really subject to Waha. I think, as you say, until a bunch of more pipes get built at Waha is going to be low.

So, I just think that we're focused on getting it out of basin, get into higher priced markets. What the longer term look at LNG and moving in international like we've done on oil.

NGL, it's hard to will make sure that we – all our NGLs are processed at Mont Belvieu. And, but given what's happened with the amount of liquids that are getting at Mont Belvieu and given the weather we've had in the winter and just lack of demand for it, I expect the NGL prices still to be weak for a while.

They were good in the fourth quarter or better in the fourth quarter, and they've fallen back something here in the first quarter.

That's very helpful. And then just as follow-up.

Scott, you made comments about some of your bullishness on oil related to the slowing down of shale growth. But, could you just give us your kind of macro view, kind of over the next several months into the next couple of years?

Yes. So I think, I mean, OPEC really had to go into the coronavirus.

Brent was up to $65 and WTI was up to $60. So, coronavirus hit.

As that is peaking, as we get into the summer months, I'm confident that the price will be up another five bucks, and it should stay there. Most of the non-OPEC fields are coming on this year.

Very little non-OPEC fields coming on in '21, '22, '23, '24, and that's why I'm a lot more bullish in regard to price. Bullishness, I hope it doesn't go up too much, but somewhere in that $65 to $70 for Brent.

I wanted to go back, you’ve touched a little bit -- you made a few comments about the DrillCo, but I think you said 9 wells. Is there anything else you could offer about how big that was whether it's four sections, 10 sections?

And are we getting the right feel that we shouldn't look or in the current circumstances, we shouldn't look for a repeat of that?

Yes, Charles. This is Rich.

I think – I would, we would need to execute it first. And so, this DrillCo and our Southern part of the acreage, and they’ll start in the second quarter of this year.

And so, I'd say let's just wait and see overtime. And as we get that one done, then we'll see what may be next.

Okay. Thanks for that, Rich.

And then, and then this is perhaps for Joey. Going back to the pad size bumping up to four on average this year, there are two questions on it.

One, what's the dispersion around that mean? In other words, or maybe that’s the same thing differently, what percentage of your pads are going to be 4-well pads?

Is that kind of a really -- a truly representative thing? And then should we beyond the look up for anything different as those bigger pads roll through your operations and then show up in the financials?

So on the first part, that average is made up of -- we still have a relatively significant portion. I can't remember the exact percentages.

But we still have quite a few 3-well pads. I would say, 4-well pads, 5-well pads and 6-well pads are growing in percentages year-over-year.

I think for this year, 4-well pads will be the predominant percentage and then slowly followed by the 5 and 6-well pads. As for how would that show up in our financials?

Of course, the more activity we can put on one location, so there's an opportunity to continue to drive down well costs. One of the other aspects of this that may seem a little bit more subtle is in our typical cycle time for a 3-well pad is about 180 days.

Of course, whenever you have that fourth well on, that increases your cycle time. So that may have the opportunity depending on the dispersion of the pads throughout the year to make production a little bit lumpier, and the timing of bringing those pads on, create some noise in the production.

But overall, it's a net positive because it also goes back to our development strategy and doing code development, which helps us with increased well productivity. So as we move in that direction, it just shows certainty in our development plan.

And it does nothing, but reap great benefits the only downside being the slightly longer cycle times.

Take a look at your LOE cost came in below expectations grow at least below your guidance. And part of that is that gas processing, I guess recovery, I'll call it that you all get.

Could you give us some color on how you see that going forward through this year, especially now that you're going to be non-consenting on some of the target stuff? And really what are the ebbs and flows to that then?

And is that in some of your forward guidance?

Yeah, we built it into our guidance range for production costs. That natural gas processing benefit really is dependent on where NGL prices sit for the most part and to a lesser extent residue gas because most of the contracts out there are driven by POP contracts.

So that's why when you look across the bottom of that chart, it ebbs and flows little with NGL and gas prices. But going forward with the -- I don't expect it to meaningfully change over the next few years just because we're going to bring in one plant later this year, the gateway plants, the target's bringing on and so there just won't change a whole lot going forward other than tracking with commodity prices, NGL and gas prices.

Okay. That's appreciated.

And sticking, I guess, on NGLs. And your price realizations on NGLs were really strong, I guess, relative to a lot of your peers.

Again, is that attributed to some of the gas processing and the better NGL yields are getting on these new plants?

Definitely. We've seen our NGL protection up.

Obviously, these new plants have higher recovery levels, but they've also tried to increase the recovery levels across the system because NGLs are better priced than Waha Gas, where a lot of that gas ends up being sold other than the stuff that we take in kind from a processor standpoint. So, unfortunately, first quarter ethane and propane prices are a little bit lower.

So we’re not going to have quite the realizations in the first quarter that we had in the fourth quarter.

Yeah. Is there a way to explain why you guys were in the fourth quarter strong relative to some of your peers?

Is there something unique about the fourth quarter or just how you guys sell yours?

Nothing unique that I can point you out, and I don't, I'm not familiar enough about the peers have reported or how they market it. So I can't really speak other than given our size and scale, maybe we have a little bit better POP contract.

I wanted to pick up on the topic of cost efficiencies from here. And Scott, big picture, when you came back as CEO, you noted the Pioneer’s well costs in the Permian were too high and then you subsequently lowered costs and improved efficiencies.

Are you where you want to be now? And do you now view your well costs positioned as sufficiently competitive based on the size, scale and quality of Pioneer’s acreage?

Yeah, Brian. I've seen some offset data from other peers.

And this is the first we're actually beating some of the Permian peers now, especially in the Midland Basin. I know we're beating Delaware, but you can't really compare Delaware since it's a higher cost area.

But looking at some of the Permian Basin companies and disclosures, we are definitely as competitive or better than most companies today. And I still anticipate, as Joey said, we're going to continue to achieve more reductions.

So, in our long-term plan, we show a certain number of rigs. I don't think at the end of the day, we're going to be adding two to three rigs every year to get the same growth rate over the next 10 years.

And then, my follow-up is on that mid-teens growth longer-term plan and the points that you bring out on Slide 8. You talked about the free cash flow and ROCE maximization as your focus.

And I wanted to ask about one of the other points, which is in execution. How do you when you think about trying to continue to grow from an already decently high days, mid-teens growth?

How do you focus on the short and long-term risks to execution? What do you see in 2020 as the key potential for upside and downside risks from an execution perspective that you and the team are focused on?

I think we've taken the risk off the table. So I mean, to me, I see very low risk at all.

We've taken it off the table. We've proven it after overspending $850 million in 2018, and under-spending $700 million in 2019.

It's one of those items I think that everybody is focused on. Everybody has held accountable.

So I don't even look at it as a risk anymore. And in regard to the free cash flow and capital, just to make a further point, right now, I think we have about $1.8 billion of the $5 billion spoken for -- $5 billion plus free cash flow, and that's in the base dividend.

We'll continue to allocate that mostly to buybacks and also to potentially that variable dividends.

Scott, I just wanted to follow-up on the considerations around your water business. Outside of financial market arbitrage, what would be some of the variables or considerations that would prevent you from monetizing the business?

Well, to start off with, I think, most of the peers that have done. In my opinion is that their balance sheet is still too high.

They have too much debt. And they're using the proceeds to reduce the balance sheet.

So, we don't need to do it for that reason. So, we have to decide what multiple that we do sell a portion of it.

In fact, we're probably gonna rule out selling. I think I've already said this.

We're going to roll out selling the entire thing. It's too important for us.

It’s a question whether or not we bring in a long-term partner, as we continue to build it out. Then so – and it’s just something that we're going to make a decision on by the end of this year.

So …

And then my follow-up is just this year you guys are having that consistent well mix of Wolfcamp A and Wolfcamp B is about 80% of your wells turn in. At what point in the future if you started seeing a greater contribution from some other zones, you all have made some headway at Wolfcamp B over the last couple of years of the delineation effort.

Is any color you can provide around just what that development looks for now? And if that there's a shift away from Wolfcamp A and B to some extent in the other year?

Yeah, David. We prioritize our portfolio every year based on returns.

And as far as looking from last year to this year, the major shift that you'll see is kind of more equal percentage of Wolfcamp A and Wolfcamp B together. That's primarily because of the fact that we're focused on co-development continuing to deliver a significant number of Jo Mills because they have strong returns.

Wolfcamp B will continue to be a small part of our portfolio at this point in time. We're focused on understanding the development strategy for the Wolf camp B.

And focusing on getting the returns up and whenever we feel like we've got that perfected and got other returns similar to what we'd see in the Wolfcamp A, B and Jo Mills and lower Spraberry shale, we'll start to bring those in. But, the short answer is, we're not really doing it just based on a portfolio.

We're doing it to make sure we maximize the returns that we can for each and every year.

Thank you all very much. Look forward to the call next quarter, and hopefully, you'll get to see a lot of you all over the next few weeks, and several months as we get out on the road.

Thanks again.