Industrias Peñoles, S.A.B. de C.V.

Thank you, operator and good morning, everyone. With me on the call this morning are President and CEO, Matt Gallagher; Chief Operating Officer, David Dell'Osso; and Chief Financial, Ryan Dalton.

Our remarks today may contain forward-looking statements, so please see our earnings release for a discussion of these statements and associated risks including the fact that actual results may differ materially from our expectations. We also make reference to non-GAAP measures, so please see the reconciliations in the earnings release.

During this call, we'll refer to an investor presentation that can be found on our website and our prepared remarks will begin with reference to Slide 4 on that presentation. After our prepared remarks, we'll be happy to take your questions.

And with that, I'll turn the call over to Matt.

Thanks, Kyle. 2018 was a strong operational year for Parsley, any way you slice it.

As we both expanded operating margins to company record levels and greatly enhanced our operational efficiency. These achievements are truly a testament to the bench strength we have across multiple disciplines and throughout the organization in Midland, in Fort Stockton, and in Austin, Texas.

2018 was a volatile year for oil prices, especially in the Permian. As you can see on Slide 4, we successfully navigated a challenging midstream takeaway situation throughout the year and delivered a realized oil price that comfortably outpaced both, our peers and local Midland prices.

Even more importantly, our proactive marketing strategy delivered ample flow assurance without burdening our long-term pricing structure. So we would expect to stay near the top of the class on this measure in coming years.

On the cost side, a tireless effort by our teams in the field and the growing benefits of scale push our annual lease operating expense down to $3.61 per Boe, which was below the bottom end of our initial 2018 guidance range. Later in this stringent cost control on top of strong realized pricing produced robust operating cash margins, and partially set a company record on this front during 2018 with an annual operating cash margin, north of 75%.

Another key accomplishment I want to touch on is the step change we saw in our drilling and completion efficiency with footage for operational day up significantly year-over-year. Simply put, we recaptured the top rate operational efficiency Parsley expects to deliver.

David will go into more detail on this front later in the call, but it gives me great satisfaction to declare victory on one of our top goals for 2018. Finally, we streamlined our portfolio with numerous accretive acreage trades and an opportunistic divestiture at year-end.

Hopefully, the combination of these efforts lends a little more weight to our upcoming goals as we look ahead to 2019. Moving on to Slide 5; I want you to discuss our investment framework.

On our third quarter call in early November, we discussed the guiding principles of Parsley investment framework, discipline, stability and foresight, and outlined an organic path to self-funded growth. This plan was built in a $70 WTI environment.

In the face of significant oil price volatility in the weeks that followed, Parlsey's commitment to these guiding principles and action plan remained steadfast. We crystallized this message in December with the unveiling of our 2019 budget which reduced our baseline activity from 16 rigs and five frac crews to 12 rigs to 14 rigs and three to four frac crews.

This budget was designed to ensure Parsley takes another major step forward on our path to self-funded growth this year in any commodity price environment while continuing to build upon hard earned operational efficiency gains. To unpack Slide 5 a little bit more; everything still starts with our guiding principles on the left hand side of the page which helps set the course for our corporate strategy.

On the far right side of the page, you will see our longer-term targets. Ultimately, this is the prize we are all playing for as shareholders, achieving and growing free cash flow and delivering top tier corporate returns.

Helping connect our guiding principles to these longer-term goals is a well-defined 2019 action plan and intangible scorecard of sorts for this year. Clearly, we operate in a dynamic landscape that can and does change quickly.

Therefore, it is incumbent upon us as operators to be adaptive and nimble, yet at all times, and in all environments we must be focused on returns of each incremental dollar invested. With that in mind, let's turn to Slide 6.

One of the cornerstones of our 2019 development approach is a deliberate shift to prioritize project level rate of return over project level NPV. As depicted by the transition from the light blue box to the orange box and the graph.

This will shorten our pathway to free cash flow and we have conviction it's the right action plan for Parsley. So what does taking this development approach from the whiteboard to the real world mean in practice?

In short, it means hydrating our well selection process, it means more activity in our highest return areas, a greater mix of wells in the Midland basin, specifically Martin, Midland and Uptown counties, it means bigger completions, and is cheap and plentiful. Horsepower is a reasonably priced and more efficient than it's ever been.

We intend to take advantage of this market dynamic. Overall, it means better wells, shorter payback periods, and increasing cash flow velocity.

This approach will have a compounding effect for years to come. Ultimately, we believe this returns-focused approach to project selection will facilitate two key outcomes at the corporate level for Parsley.

First, it accelerates our progress towards self-funded growth. We now expect to turn the corner to sustainable free cash flow during the fourth quarter of 2019 at an oil price in the low $50s.

An oil price higher than that would simply expand the free cash flow profile and accelerate shareholder friendly return initiatives. We have the core inventory debt in the right zip codes which allow us to adapt, and we have the short cycle projects that allow us to be nimble.

This combination lets us turn the knob to tweak near-term capital projects and actually see a changing return profile three to six months later. We started turning that knob in November of last year, and this brings me to the second key outcome of this returns-focused development approach.

Parsley expects to see an 8% to 10% plus year-over-year improvement on capital efficiency during 2019. We expect both productivity gains and CapEx savings to drive this improvement as detailed down the right hand side of the slide.

Our teams stand poised to deliver on an advantage program in 2019 drawing lines in the sand and committed to achieving free cash flow with a model that sustainably generates increasing free cash flow while achieving Top Tier corporate returns. I'll now pass it over to David for details on our 2019 program and to discuss some of the positive developments and trends we've seen on the operational front.

Thanks, Matt. Moving to Slide 7, Parsley's key attributes that enable the shift in our development approaches is our extensive set of reinvestment opportunities.

As you can see on the map provided, Parsley's effectively mitigated its reinvestment risk by building a formidable DSU inventory. Everything in dark yellow is a Parsley-DSU with specific engineered future well locations ascribed to it.

All told, these DSUs make up about 167,000 net acres, nearly all of which is held by production. When you hear us referring inventory it is all included in these DSUs, the lighter shaded yellow on the map is our non-DSU acreage or where our land group refers to as trade bait.

Overtime, we expect new DSUs to pop up with dark yellow on this map with light yellow acreage rotating office our land team continues to take trades across the finish line. So, when we say acreage trades can be accretive to inventory, that's the process.

We're essentially transforming non-DSU acreage into DSU acreage. Moving from the development blocks to the rings and circling them, this is the way to visualize our long reinvestment runway.

You've seen this doughnut visual in our past presentations but we've worked in a couple of new features that provide more details for 2019 action plan. First, we've illustrated our 2018 development program and the dark blue edge and our planned 2019 programs in the orange wedge.

This gives a quick visualization of year-over-year shifts and activity mix with our 2019 plan underpinned by a higher concentration of activity in the Martin, Midland and Dustin counties. We've similarly updated the inventory life in each core geography to reflect our anticipated 2019 development activity in each area.

It's important to note that the bottom of this inventory life represents a development of our DSU inventory utilizing a higher completion intensity than lower density spacing pattern consistent with our 2019 development approach. The top-end of the range represents our full DSU development inventory using our historical development approach, roughly 8 wells across per target zone.

Project returns by area will dictate long-term development patterns. Even at the most conservative element spacing, we have over a decade of running room to each of our core geographic areas allowing optionality and any commodity price scenario.

Moving to Slid 8, we've now delivered on our improved operational execution for long enough to call our 2018 evolution a sustainable trend and recalibrate our go forward expectations. Simply put, we covered more ground in less time than 2018 and have a high degree of confidence we can defend and extend those gains in 2019.

The structural changes we made to some of our completion processes and the alignment of incentives with our experienced service providers are all still in place and hydrating or equipment under our reduced activity plan provides a new potential tailwind in 2019. Before leaving this slide, I'd like to point out, in addition to getting faster and more efficient and putting new wells on production, we've continued to deliver in our day-to-day production operations.

Our lease operating expense per Boe is still roughly a dollar below our peer average. We would expect to maintain a relative advantage on this metric in 2019.

On Slide 9 and keeping with tradition, we've shined a spotlight on one of our core operating areas every quarter. This quarter we turned to Northern Midland County an area we recently stepped up activity and a key component of our 2019 development programs.

As you can see on Slide 9, we're bringing out some strong wells in this area. Additionally, we've recently demonstrated our elevated technical and operational capability in Northern Midland County.

To that end, I'm excited to highlight the company's first three mile lateral Wolfcamp well which is drilled and only 25 days. And as you can see in the graph the entire three mile lateral segments has less than nine days to drill.

This is a testament to our team's ability to collaborate across multiple disciplines and deliver beyond the status quo. Moving on to Slide 10, we have long mentioned that part of the reason we have maintained a pure leading LOE as our growing water infrastructure network.

However, I'm not sure investors fully appreciate the scale and cash flow savings potential of these assets. We wanted to pull the curtain back a little bit.

The first point I want to highlight is our permanent disposal volumes run well in excess of our current disposal needs, providing us with some nice optionality in 2019. In fact, we're having discussions with several nearby operators in the Midland and Delaware basins who've expressed interested in sourcing and disposal availability within our water network, providing a potential package, increasing revenue from third-party water volumes.

There also been a lot of private capital flowing into the water space and some of these recent transactions were located in relatively close proximity to our assets as shown in the map. The bottom line is we believe that there are multiple paths to create additional value for our shareholders with these water assets.

We plan to assess all of our options during 2019. And now I'll pass it over to Ryan to discuss our 2019 outlook and financial position.

Thanks, David. Turning to Slide 11, we're reaffirming the development plan, capital budget and production guidance we outlined with our preliminary outlook in mid-December.

As a quick reminder, this discipline plan was built around the $50 WTI price and called for a reduction of activity from a baseline of 16 development rigs and five frac crews to 12 to 14 development rigs and 4 to 5 frac crews. During the fourth quarter we dropped down to 14 development rigs and 4 frac crews and we have laid down another two development rigs during the first quarter of 2019.

Although oil prices have climbed above $50, we remain disciplined and reiterate that we have no plans to increase 2019 equipment levels beyond our baseline budget. Next, I wanted to provide a bit more operational color on how we ended 2018 and expect to start 2019.

As we stated on our third-quarter call commitment to our 2018 capital budgets, they top priority in the fourth quarter. And adhering to this budget would likely mean taking some extended frac holidays during December and it really played out according to our plans.

Not only did we slow down, but we also sold some barrels that were part of our recent divestitures of tail end inventory. When we think about the shape of our production profile this year, our 1Q '19 oil guidance of 75,500 to 78,000 barrels per day cost per modest sequential organic oil growth at the midpoint.

We expect our discipline 2019 growth profile to be somewhat linear from there. On the spending side, we carried a little extra equipment with the two additional rigs in January and expect to have a little higher mix of Delaware activity in the first quarter.

We're modeling first quarter spending to be a touch higher than the 2Q '19 through 4Q '19 run rate. We've also rolled out additional guidance on a few other line items to help you with your models.

On the cost side, as David mentioned earlier, we expect to retain our relative advantage on LOE versus peers this year aided by our robust water infrastructure network. And we expect G&A to continue to burn down on a unit basis in 2019 as we have recently implemented numerous corporate cost-saving initiatives and expect to capture additional benefits from scale.

Turning to Slide 12, our balance sheet remains in a strong position with proceeds from divestitures that closed during the fourth quarter adding to our cash position. We still possess a fully undrawn revolver and have no near-term debt maturities.

This translates to an advantage liquidity position relative to peers. Our leverage profile is also healthy with our trailing leverage ratio holding steady at 1.5 times and we received an upgrade from one of the credit agencies in November.

We've also been actively protecting our cash flow stream and balance sheet through recent hedging activity. I'd encourage you to review our latest hedge position in the supplementary slides.

Again, our heads structured preserves meaningful upside exposure in a stronger oil price environment, which is quite uncommon in the industry. By 13 highlights of very strong reserve growth with proved develop reserves up nearly 50% in 2018, we touched on one measure of capital efficiency earlier in the deck, but we wanted to point out here that we also screened well on recycled ratio coming in at 2.6 times on our latest numbers.

To conclude, we're pleased to have had such a strong operational year in 2018 and we have conviction we have the right returns focused plan in place for 2019. There were a lot of exciting milestones on the horizon for parsley this year and we're eager to deliver on these key objectives and participate in the value creation alongside our shareholders.

With that, we'll be happy to take your question.

Thanks. I appreciate the time and thought updates.

I appreciate you guys putting the thought she had in the deck around kind of either the ROR versus NPV framework. I was wondering if you could talk through some of the internal processes you ran through in arriving at your conclusions on that and arriving at what is now the 2019 action plan and then what if any sort of changes to the environment around you could theoretically change that plan as we move forward?

Sure. Good morning, Michael.

We figured there'd be a little bit of discussion about this approach and why we wanted to highlight it in detail on this slide, done other work on this over the last six months and the underpinning that allows us to do this is a robust and inventory. So we've built some quantified sensitivities through a building block model.

If you take a theoretical 10,000 acres and you develop it with one rig, what's the best of the approach to generate returns on your capital? And then when you start stacking those building blocks one on another and you compound them throughout time, you actually see increased corporate NPV especially when you use meaningful or a reasonable discount factor by pulling forward rates of return projects.

And we think that actually past, your five, the investment community is probably using something north of a 10% discount factor. When you layer that into the sensitivity, it even makes the analysis more clear that a rate of return action plan really compounds the present value of a program, especially if we're committed to them going to the cash flow neutral model, which we are.

So essentially you're your capital constrain. It really expands or drives on that analysis even further.

So there's a lot of synergies going on when you look at it this way and if your kid made into cash flow cat on your capital programs and you have a deep inventory, this is we feel the way to go.

And as you do that, what sort of uplift in, let's say, I guess productivity per well, or recoveries per well? Do you think you're seeing in the shift to the left on well density per bench?

How should we think about that?

Yes, you see, that's a great point. You get an immediate upload when you have less bounding conditions.

So we feel that this runs at about 8% to 10% plus rate right now. You're able to increase your sand loading.

So as the year unfolds and we get more results under these patterns, we'd hoped to refine that additionally, but it looks like about 8% to 10% uplift. And then you have the benefits of moving to more productive counties.

We're going to the Northern Midland basin, more productive on the oil front. So we have a few tailwinds that are back.

Okay. I'm sorry, just to follow-on on that.

So like if you looked at the tightest density that you tested relative to the unbounded well, what was the impact per well recovery and then do you think it's a pretty linear relationship between those two boundaries as we move towards wider spacing?

It's absolutely linear between the eight to six a spacing about four, six and eight. So, if you count four is completely unbounded as your starting point, you might see a 5% to 10% reduction to the sixth spacing and then another aggregate from the for about a 10% to 15% reduction in the eight spacing.

And so there are economic conditions, there's still economic, but those are probably the productivity reductions you see. After that, we've done obviously some density testing as much denser spacing and we see a nonlinear relationship at that point.

Good morning guys. Just following up, Matt on the prior question on the 8% to 10% increase in capital efficiency that you've laid out as one of your goals.

I just want to make sure that I heard you right. So you're basically already seeing that on the leading edge while results from some combination of the increased profit loadings or the wider spacing.

Is that correct?

Yes, that's correct. And then we would hope that the mix shift plays out over time and our favorite.

Okay. So, the efficiencies though, the 8% to 10% is already being achieved and then there's an opportunity even better than that.

Is that fair?

Yes. That would be an upside.

Yes.

Okay. And then just my follow-up, as we move to sort of this more of an RLR sort of focus strategy, can you kind of just estimate on an average of the wells that you're drilling in '19 and let's just use the price deck that budget was set at $50.

What sort of the average return of the wells that you're drilling this year?

We go across the entire of blended average at about a $50 case all in with our facilities projects that we're looking at about a 40% return.

Hey, good morning everyone. Matt, you mentioned the action plan will have less than positive effects.

So just kind of thinking about the business longer term as we envision Parsley not just through '19, but also to '20 and beyond, I guess maybe on like a $50 deck, is there a specific free cash flow number that we should be thinking about in '20 and/or a specific corporate return number to think about? And then also I guess within that, how do you prioritize the use of free cash?

Sure. Pulling this forward, we can see a wedge of hundreds of millions of dollars of additional free cash flow over the years from a rate or return plan versus NPV plan.

Obviously we will be refining the 2020 plus plan, but hitting free cash flow in 2019 is a big achievement for us. And then keeping that a cadence at a baseline, but it should actually grow throughout 2020 and beyond.

So that should be a run rate ever or run rate estimate for you. And then this is a cash we have to achieve, free cash flow, job number one, and then get on the track of returning to shareholders and we're going to have to march towards the industry competitive deal.

Great. That's helpful.

And I guess just a follow-up on the 8% to 10% target or improvement in capital efficiency year-over-year, how much, I guess, if any cost deflation from service providers are you assuming that number or does that just kind of represent some more upset?

Yes, I'd say that represents more upside. This is David.

We've baked in an assumption of no inflation or deflation. We recognized there has been softness and pressure pumping steel, regional sand, but until we start seeing changes in the basin, we're holding our base budget assumption is flat.

We have seen some other peer's analysis this week, so we'll continue to monitor that as we go forward.

Good morning and congratulations on the very thoughtful 2019 action plan. If we look at the exhibit on the left side of Slide 8, just where you guys talk about drilling and completion efficiency, do you have a sense of where Parsley kind of stands versus Peers on those metrics?

We do some benchmarking through a CAs and have always stacked up very reasonably. Those are probably three to six months old.

So then this step change has I would assume improve on that parameter. I know on the pumping side there's only 24 hours in a day and our pump times are increasingly high, so it's going to be hard to see material improvement from where we're at on the stimulated foot per day.

We feel like we still have some opportunity on the drilling side. So that's where a lot of the effort is going to be placed in 2019.

Okay. And then I just wanted to follow-up on the wells per section per bench, going to get to 48 spacing.

Is that specific just for the 2019 program or at a specific oil price and if it's the latter of what oil price would you need to see to go back to eight being the optimal number?

Yes, I think that the intent of Slide 7 is to show that there is a range of outcomes, but the baseline case is to always focus on the rate returns. And I think you'd have to have realized prices north of $70 before you start increasing the density again because you want to see -- you just always want to maximize that rate of return.

So it is the baseline for the planning for multiple years to come. However, even if we go through one, two, three, five years of this, and then oil prices rebound much higher, you still have the flexibility on your remaining DSUs to shift at that point.

So it doesn't condemn remaining inventory. Even if you use the current spacing assumptions is quite a bit of running room.

Matt, a little into that last question. You all have been pretty open and deliberate about this revising your acreage I think from around 216 last year up to the 192 today.

Do you all anticipate sort of these further at least abandonments or how do you see the total acreage settling out for the remainder of the year assuming no acquisitions?

Sure. We will provide a full detail of remaining exposure acreage in the 10-K, but it's essentially a material especially when you look at our DSU activity.

So I don't anticipate anything even on the order of what we saw in the fourth quarter, that was really annual assessment across the entire footprint. And I think that's the line share.

Now, it makes sense. And then just one pump on that.

Lastly, on this tail of inventory that you all sold, how much production was associated with that?

It's about 1200 Boe per day.

I wanted to ask a little about some of your prepared comments on the water infrastructure side. It sounds like you guys are assessing that.

I know you've also talked about the loyalty potential in the company as well. I had to kind of look at both of those.

Is there any potential in your guys' minds to maybe see some kind of transaction from Parsley on those fronts in 2019?

Yes, it's Ryan. We really wanted to highlight this water slide because we think it's something that's probably underappreciated outside of Parsley.

We're open to all strategic option to create value for shareholders, but it's probably a little bit too early to go into too much detail there. But we've got the capacity to take on more third-party volumes and that was really just helped any alternatives that we may pursue.

So yeah, I mean I said we're in the early innings of evaluating alternatives on the water side but, yes, I think it is possible that you could see some sort of activity on either minerals or water during 2019.

And I guess just shifting over to the Delaware Basin sort of could help but notice that you guys are really toning down activity there in 2019. What are kind of the key drivers there?

Obviously you're more focused on rate of return. So I think really you were implying that the rates return a little better in some of the areas in the Midland that you've identified.

I mean, do you guys see it as more of a well cost issue on your Delaware acreage? Maybe just some more color around why the shift.

Yes, that's exactly the right reason maximizing rate of return at our assumed commodity price tag of $50. We see the transition to different slope of returns in the Delaware.

So it's got a lot more torque towards higher oil prices and so above $55 to $60, realize we'd have a program that is more balanced towards the Delaware as we look into 2020. So it's nice having that flexibility in the portfolio.

Morning, guys. Just sticking on the theme of the water assets, I was just curious if you guys could potentially share with us what throughput volumes are and you got to have the permitted number there.

But you have what the throughput number was and you guys touch on the of the salt water disposal capacity. Is that primarily commercial and can take third party or just trying to get a sense of the materiality of that you guys see on the third-party side as well?

Right now we're moving about 250,000 barrels a day on the existing infrastructure and most of that permitted capacity is already in existence. It's already consisting of gathering lines and SWV wealth.

So that's a pretty small fraction of our total permanent patch. So we do think we have plenty of capacity in certain areas to look at third-parties.

As I mentioned in the script comments, we've had several entities reach out to us and ask about both freshwater and SWV availability. So we're in some discussions with some of those operators right now.

Great. I appreciate that.

And for my follow-up, you guys mentioned going back and doing some more compressed stage spacing and as I recall, you guys had some good results on that a couple of years back. So I was just kind curious if you got to touch a little bit on what sides I guess type of test program you all are looking at and when you might have some results to come back to it.

Yes, we've done about 10 of those to date and compressed stages or just a little bit over half of our typical stage length that we've been encouraged by what we've seen so far. Thinks a little early to draw the line on exactly what optimal is.

But there is of course, an incremental cost with it but we have seen some incremental production uplifts. So right now we're working on testing that further and tightening in that balance of performance and costs.

It's encouraging possibility for us going forward.

With these well-designed changes could you update your assumed well cost this year? And then Matt, perhaps if you could frame for us a DNC costs per foot.

And I'm going to compare Midland to Delaware conceptually on behavioral.

Yes, so, today that I'd say on average our well costs are around 9.5 in [indiscernible 00:35:13] the Delaware for a 2-mile lateral. For 2019 there's a few things that are kind of opposing forces on those.

You know, you got the shift in the Midland end but we're also putting more RBS into the ground, which helps in increasing the overall frac side. So I'd say those two things are the net effect of that gets you towards that 9.5 in the Midland and a little under 12 of the Delaware.

Okay. Your batch size is increasing methodically here.

And what's the embedded assumption in 2019 over 2018 and any plans for three mile laterals in 2019?

Yes, we do have some additional three mile laterals not a lot of them. That's more a function of our land layout.

So basic key and the reason we highlighted the three mile that we put in the earnings presentation was to show we can do it. And we've proven that to ourselves.

We do have opportunities and we'll take those where they are. I think generally speaking, our sweet spot on laterally, it's still probably close to that 2, 2 plus a mile length.

But we'll certainly take them as they come and as we do trades and bolster our DSUs further, those opportunities may continue to grow.

If I could actually just pick up on that three mile lateral question, I get I believe that was David was saying really it's mainly a function of your land set up and where you could stack those three sections together. But are there other more mechanical or are kind of fluid mechanics limitations on those on this three mile laterals?

And if they're not is there some limit that we ought not think could you go to four or five mile laterals?

Charles, it's David. I think we clearly shown from a drilling standpoint, the limited is beyond three miles.

We executed that well quickly and efficiently. On the frac side, certainly that friction effects that you need to take into consideration and on the drill out as well.

You need to have a large number of plugs. So what we've done is a lot of ford modeling in preparing for this three mile lateral and we haven't completed it yet, but we haven't drilled it out yet, but it would customize our pumping schedule.

We've a very a few design parameters including types of plugs. We run depending on where you are in the lateral, we've done a lot of torque and drag on drill out and the through considerations for surface equipment and stream design.

So I think it's a little bit early to call what the mechanical limits are but we're certainly eyes wide open on this three mile lateral and when we come back and revisit on it later then we could maybe have a little bit more on the follow-on of your question of what that technical limit is.

And then, Matt, you mentioned I think at least once, maybe twice in your prepared comments that as you guys are shifting up into this Northern Midland County that you expect it to be a little bit more productive and I think you also mentioned that your '19 programs going to benefit from the mixer. You can you confirm that is the case, that you are expecting more productive wells area and give us an idea of what that order of magnitude is?

Well, if we just look at our results in that area today we can confirm that it is oily and is more productive in the early time frame. So you can see on Slide 7 really looking at the comparative of the orange wedge compared to the dark blue wedge and that shows that mix shifts and they can just pull industry results and see the long-term results.

But you're anywhere from 5% to 15% depending on the zone on the oil productivity of lift in the Midland basin.

Last year you had to tap the brakes a little bit with your capital plan to stay within your capital planning I should say. Just want to see how that impacted the 2019 plan if at all and how should we anticipate the piece of spinning and completions this year?

This is actually our first time in corporate history to put out a Q1 quarterly guidance on the oil front, and we thought that was important due to being discipline. And the hearings of the capital of 2018 definitely has some follow-on effects.

I'm actually really pleased that it generates consistent organic growth at the mid-point so we don't see a backwards quarter even with pumping the breaks like you mentioned. And then turn to David a little bit for the activity profile throughout the year.

The activity profiles, we fired everything that was idle at the very end of Q4 backup. So we you would expect to see a little bit higher capital in Q1 than subsequent quarters and pair that with a lower pop and Q1 that references Matt's point.

And then as you get through the year, quarters two, three and four, you'll start to see that pop cadence pick back up is the normal cadence for our capital activity starts to degenerate those increasing pop counts in the back part of the year.

And then you'd mentioned the wider spacing and prioritizing IRR over NPV and I think the depth of your inventory you was really a key component of making the decision. I just wanted to see how that drilling inventory has changed from 2017 to 2019, if at all you were x out oil price into that equation.

Yes. Like for like, it really hasn't changed.

So on Slide 7 and the footnote, we have to look at it and we have $35 million gross footage, if you rewind back to the beginning of the '18 we've obviously drilled wells, which has eaten to that. The prior rating footage we've sold a divestiture that ate into that footage.

And then we had trades that from the anterior of the field into the core of the field that might be a two-foot for one and a half foot type of trade but if you net those out the inventory on the DAC has not changed. So you're left with a $35 million.

And then we give the range there, if we're going to the current spacing any blow that down at a current development pattern, you're looking at $25 million gross feet associated with the productivity we think we have on these wells. So we really improved even though the footage that's out hasn't changed, we've really improved the quality of the footage as well.

My numbers might be stale on this, but I feel like it's been a while since you guys have published your URLs for your Midland basin development activity. Can you give us a sense with rates of return improving on 2019, what kind of URLs you expect from that settlement program?

We have about 50 different type curves on a blended case if you don't take into account the mix shift in the development zones, we've been meeting our blended type curves in the past. So we actually saw positive technical revisions on the year on a small percentage.

So we've been within a 3% plus or minus year in and year out on those estimates. So no changes in the type curves were I mean, in the URLs we're not going to underpin reserves on this anticipated productivity uplift just yet.

We have to see that before we start to print that uplift.

And as far as your royalty acquisition program goes, specific acreage growth you expect on that front, can you talk about the opportunity in the Midland basin as a comparison at Delaware?

The opportunity is ripe but we spent about $140 million in that effort last year and pulling back on that activity in 2019 by design. So, really focused on the drill but we have a great position there as well 7,600 net-net royalty acres and strong high margin cash flow coming out of that.

So we're really pulled back on that budget and in 2019 I don't see us pursuing actively although there is quite a bit of opportunity.

Just looking at NGL price elevations this quarter, they were very healthy. They were actually up versus third quarter.

And then gas oil elevations were weaker than I was the can you just talk about the driver between those things and how would you think about NGL versus gas price realizations and '19?

Well, gas specifically December was a negative print in the first week of December on residue gas. And I think that's what drove down most of the industry in the Permian on their realizations on the gas.

NGLs have been healthy and we do anticipate that to continue to be the case. There's a lot of demand downstream for printing the NGL side.

And then on the on the oil side, we're still reaping the benefits of the diversified pricing. I think you've seen our oil realization quite a bit higher than some of the other peers that have come out.