Yahoo Finance Parsley Energy Inc (PE) Q4 2018 Earnings Conference Call Transcript
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Parsley Energy Inc (NYSE: PE)
Q4 2018 Earnings Conference Call
Feb. 22, 2019, 9:00 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Good morning, ladies and gentlemen, and welcome to the Parsley Energy's Fourth Quarter 2018 Earnings Call. My name is Michelle, and I will be your operator today. As a reminder, this call is being recorded. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.
And now I'm pleased to turn the call over to Kyle Rhodes, Parsley Energy's Director of Investor Relations. Thank you. You may begin.
Kyle Rhodes -- Director of Investor Relations
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 Officer, 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 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.
Matt Gallagher -- President and Chief Executive Officer
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 pushed our annual lease operating expense down to $3.61 per BOE, which was below the bottom end of our initial 2018 guidance range. Layering this stringent cost control on top of strong realized pricing, produced robust operating cash margins, and Parsley 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 a step change we saw in our drilling and completion efficiency. With footage per operational day up significantly year-over-year. Simply put, we recaptured the top rate operational efficiency Parsley expected to deliver. David will go into more detail on this front later in the call, but it gives me great satisfaction to declare a 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 to discuss our investment framework. On our third quarter call in early November, we discussed the guiding principles of Parsley's 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, Parsley's commitment to these guiding principles and action plan remains 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 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 price we are planning 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 a tangible scorecard of source 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 in the graph. This will shorten our pathway to free cash flow, and we have conviction, is the right action plan for Parsley.
So what does taking this development approach from a whiteboard into the real world, mean in practice? In short, it means high grading 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 Upton counties, it means bigger completions, and is cheap and plentiful. Horsepower is reasonably priced and more efficient than it has ever been. We intend to take advantage of this market dynamic.
Overall, it means better wells, shorter payback periods and increase in 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 toward 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 let's 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 team stands poised to deliver on advantage program in 2019, drawing lines in the sand and committed to achieving free cash flow, with a model that sustainably generate increasing free cash flow, while achieving top tier corporate returns.
I will 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.
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Thanks, Matt. Moving to slide 7, Parsley's key attribute that enabled the shift in our development approach is our extensive set of reinvestment opportunities. As you can see on the map provided, Parsley has 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 to inventory, it is all included in these DSUs. The lighter shaded yellow on the map is our non-DSU acreage or what our land group refers to as trade (inaudible). Overtime, we expect new DSUs to pop-up in dark yellow on this map, with light yellow acreage rotating off, as 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 a 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 our 2019 action plan.
First, we've illustrated our 2018 development program in the dark blue wedge, and our planned 2019 program 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 Martin, Midland and Upton counties.
We have similarly updated the inventory life in each core geography to reflect our anticipated 2019 development activity in each area. It is important to note that the bottom of this inventory life represents a development of our DSU inventory, utilizing a higher completion intensity and 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 eight wells across per target zone. Project returns by area will dictate long-term development patterns. But even at the most conservative development spacing, we have over a decade of running room in each of our core geographic areas, allowing optionality in any commodity price scenario.
Moving to slide 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. We covered more ground and less time in 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 hiring our 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 at putting new wells on production, we continue to deliver in our day-to-day production operations. Our lease operating expense per BOE is still roughly $1 below our peer average. and we would expect to maintain a relative advantage on this metric in 2019.
On slide 9, in keeping with tradition, we shine a spotlight on one of our core operating areas every quarter. This quarter we turned to Northern Midland County, an area where we've recently stepped-up activity and a key component of our 2019 development program. As you can see on slide 9, we're bringing on 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 am excited to highlight the company's first 3-mile lateral Wolfcamp well, which is drilling only 25 days. As you can see in the graph, the entire 3-mile lateral segment has less than nine days to drill. This is a testament to our team's ability to collaborate across multiple disciplines to deliver beyond the status quo.
Moving on to slide 10, we have long mentioned the part of the reason we have maintained a peer-leading LOE was our growing water infrastructure network. However, I'm not sure investors fully appreciate the scale and cash flow savings potential of this asset. So we wanted to pull the curtain back a little bit.
The first point I want to highlight is our permitted disposal volumes remain well in excess of our current disposal needs, providing us with some nice optionality in 2019. In fact, we are having discussions with several nearby operators in the Midland and Delaware Basins, who have expressed interest in sourcing a disposal availability within our water network, providing a potential path to increasing revenue from third-party water volumes. There has also been a lot of private capital flowing into the water space. 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 there are multiple paths to create additional value for our shareholders with these water assets, and 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.
Ryan Dalton -- Executive Vice President and Chief Financial Officer
Thanks David. Turning to slide 11. We are reaffirming the development plan, capital budget and production guidance we outlined with our preliminary outlook in mid-December. As a quick reminder, this disciplined 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 four to five frac crews. During the fourth quarter, we dropped down to 14 development rigs and four 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 for how we ended 2018 and expect to start 2019. As we stated on our third quarter call, commitment to our 2018 capital budget, a 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 plan. 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 2019 oil guidance of 75,500 to 78,000 barrels per day, calls for modest sequential organic oil growth at the midpoint. We expect our disciplined 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. So we are modeling first quarter spending to be a touch higher than the 2Q 2019 through 4Q 2019 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 a 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 positions. We still posses a fully undrawn revolver and have no near-term debt maturities. This translates to an advantaged 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 a recent hedging activity. I'd encourage you to review our latest hedge position in the supplementary slides. Again, our hedge structure preserves meaningful upside exposure in a stronger oil price environment, which is quite uncommon in the industry.
Slide 13 highlights a very strong reserve growth, with proved developed reserves of nearly 50% in 2018. We touched on one measure, capital efficiency earlier in the deck, but we wanted to point out here, that we also screen well on recycle ratio, coming in at 2.6 times on our latest numbers.
To conclude, we are pleased to have had such a strong operational year in 2018 and we have conviction we have the right returns focused plan in place to 2019. There are a lot of exciting milestones on the horizon for Parsley this year, and we are 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 questions.
Questions and Answers:
Operator
Thank you. We will now be conducting a question-and-answer session. (Operator Instructions). Our first question comes from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed with your question.
Michael Hall -- Heikkinen Energy Securities -- Analyst
Thanks. Appreciate the time and solid update. Appreciate you guys putting the thoughts you had in the deck around kind of the ROR versus NPV framework. I was wondering if you could talk through some of the internal processes that 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, you could theoretically change that plan as we move forward?
Matt Gallagher -- President and Chief Executive Officer
Sure. Good morning, Michael. There will be a little bit of discussion about this approach and why we wanted to highlight it in detail on the slide, done lot of work on this over the last six months, and the underpinning that allows us to do this, is a robust inventory depth. 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 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 calling forward rates of return projects. So -- and we think that actually past the year 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 -- at a rate of return action plan really compounds the present value of a program. Especially if we're committed to and going to a cash flow neutral model, which we are. So essentially you're capital constrained. 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 you are committed to cash flow cap on your capital programs and you have a deep inventory. This is, we feel, the way to go.
Michael Hall -- Heikkinen Energy Securities -- Analyst
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 -- I guess the shift to the left on well density per bench, how should we think about that?
Matt Gallagher -- President and Chief Executive Officer
Yes. And you see -- that's a great point, due to immediate uplift when you have less bounding conditions. So we feel that this runs at about 8% to 10% plus right now. You're able to increase your sand loading. So as the year unfolds and we get more results under these patterns, we hope to refine that additionally. But it looks like about a 8% to 10% uplift. And then you have the benefit of moving to more productive counties, going to the Northern Midland Basin and more productive on the oil front. So we have a few tailwinds at our back.
Michael Hall -- Heikkinen Energy Securities -- Analyst
Okay. Sorry, just to follow on to that. So like if you looked at the tightest density that you tested relative to unbounded well, what was the impact on per well recovery, and then do you think it's a pretty linear relationship between those two boundaries as we move toward wider spacing?
Matt Gallagher -- President and Chief Executive Officer
It's relatively linear between the eight to six spacing about -- four, six and eight. So if you count four as completely unbounded as your starting point, you might see a 5% to 10% reduction to the six spacing, and then another in aggregate from the four, about a 10%, 15% reduction in the eight spacing. And so there are economic conditions -- they still are economic, but those are probably the productivity reductions you see. After that, we've done obviously some density testing at much denser spacing, and we see a non-linear relationship at that point.
Operator
Thank you. Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.
John Freeman -- Raymond James -- Analyst
Good morning, guys.
Matt Gallagher -- President and Chief Executive Officer
Good morning.
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Good morning.
John Freeman -- Raymond James -- Analyst
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 well results from some combination of the increased profit loadings or the wider spacing, is that correct?
Matt Gallagher -- President and Chief Executive Officer
Yes, that's correct. And then we would hope that the mix shift plays it out over time in our favor.
John Freeman -- Raymond James -- Analyst
Okay. So the efficiencies though, the 8% to 10% is already being achieved, and then there's an opportunity to do even better than that. Is that fair?
Matt Gallagher -- President and Chief Executive Officer
Yes, that's a -- that would be an upside. Yes.
John Freeman -- Raymond James -- Analyst
Okay. And then just my follow-up as we move to sort of this more of an ROR sort of focused strategy, can you kind of just estimate on average of the wells that you're drilling in 2019 at -- let's just use the price deck, the budget was set out at $50, what's sort of the average return of the wells that you're drilling this year?
Matt Gallagher -- President and Chief Executive Officer
We go across the entire portfolio of blended average at about $50 case. All in with our facilities projects, we're looking at about a 40% return.
Operator
Thank you. Our next question comes from the line of Gabe Daoud with Cowen & Company. Please proceed with your question.
Gabriel Daoud, Jr. -- Cowen and Company -- Analyst
Hey, good morning everyone. Matt, you mentioned the action plan will have lasting positive effects. Was just kind of thinking about the business longer term, how should we envision Parsley, not just through 2019 but also through 2020 and beyond, I guess maybe on like a $50 debt. Is there a specific free cash flow number that we should be thinking about in 2020 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?
Matt Gallagher -- President and Chief Executive Officer
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 of 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 cadence at a baseline, but it should actually grow throughout 2020 and beyond. So that should be a run-rate -- a run-rate estimate for you.
Gabriel Daoud, Jr. -- Cowen and Company -- Analyst
Great. That's helpful.
Matt Gallagher -- President and Chief Executive Officer
And then uses of cash, we have to achieve free cash flow, job number one, and get on the track of returning to shareholders and we're going to have to march toward the industry competitive yield.
Gabriel Daoud, Jr. -- Cowen and Company -- Analyst
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 inflation from service providers are you assuming in that number, or does that just kind of represent some more upside?
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Yes, I would say that represents more upside. This is David. We've baked in an assumption of no inflation or deflation. We recognize there has been softness in pressure pumping, steel, regional sand, but until we start seeing changes in the basin, we're holding our base budget assumption as flat. We have seen some other peers announced this week, so we'll continue to monitor that as we go forward.
Operator
Thank you. Our next question comes from the line of John Nelson with Goldman Sachs. Please proceed with your question
John Nelson -- Goldman Sachs -- Analyst
Good morning, and congratulations on the very thoughtful 2019 action plan.
Matt Gallagher -- President and Chief Executive Officer
Thank you.
John Nelson -- Goldman Sachs -- Analyst
If we look at the exhibit on the left side of slide 8, that's 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?
Matt Gallagher -- President and Chief Executive Officer
We do some benchmarking through (inaudible) and have always stacked up very reasonably. Those are probably three to six months old, so then -- this step change has -- I would assume, improved on that parameter. I know on the pumping side, we just, there's only 24 hours in a day and our pump times or are increasingly high. So it's going to be hard to see a 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.
John Nelson -- Goldman Sachs -- Analyst
Okay. And then I just wanted to follow up on the wells per section per bench going kind of to a four to eight spacing. Is that specific just for the 2019 program or at a specific oil price and if it's the latter, at what oil price would you need to see to go back to eight being the optimal number?
Matt Gallagher -- President and Chief Executive Officer
Yes, I think that's the intent of slide 7, is to show that there is a range of outcomes. But the baseline case is to always focus on rate of returns, and I think you have to have realized prices north of $70, before you start increasing the density again because you want to see a -- you just always want to maximize that rate of return. So it is the baseline for the plan 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, we still have the flexibility on your remaining DSUs to shift to that point. So it doesn't condemn remaining inventory, but even if you use the current spacing assumptions, there is quite a bit of running room.
Operator
Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Hi Matt. A little follow-on to the 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 to date. Do you all anticipate sort of these further lease abandonments, or how do you see the total acreage settling out for the remainder of the year, assuming no acquisitions?
Matt Gallagher -- President and Chief Executive Officer
Sure. We will provide a full detail of remaining expired exposure acreage in the 10-K. But it's essentially immaterial, especially when you look at the 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 lion's share.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Makes sense. And then just one follow-up on that lastly, just how much -- on this tail of inventory that you all sold, how much production was associated with that?
Matt Gallagher -- President and Chief Executive Officer
It's about 1,200 Boe per day.
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Okay. Thanks guys.
Operator
Thank you. Our next question comes from the line of Leo Mariani with KeyBanc Capital Markets. Please proceed with your question.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Yeah, hey guys. Wanted to ask little bit 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 royalty potential in the company as well. If I had to kind of look at both of those, is there any potential in your guys' minds to maybe see some kind of the transaction from Parsley on those fronts in 2019?
Ryan Dalton -- Executive Vice President and Chief Financial Officer
Yeah. It's Ryan. We really want to highlight this water slide, because we think it's something that's probably underappreciated outside of Parsley. We're open to all strategic options 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 would really just help 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.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Okay, that's helpful. And I guess just shifting over to the Delaware Basin, sort of couldn't help to notice, but 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 returns? So I think clearly you're implying that the rates returned a little better in some of the areas in the Midland that you've identified. I mean, you can see it is more of a well cost issue on your Delaware acreage, maybe just some more color around why the shift?
Matt Gallagher -- President and Chief Executive Officer
Yeah, that's exactly the right reason, maximizing rate of return at our assumed commodity price deck of $50. We see the transition to different slope of returns in the Delaware, so it has got a lot more torque toward higher oil prices. And so about $55 to $60 realized, we have a program that is more balanced toward the Delaware, as we look into 2020. So it's nice having that flexibility in the portfolio.
Operator
Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your question.
Jeff Grampp -- Northland Capital Markets -- Analyst
Morning guys. Just sticking on the theme of the water assets. Was just curious if you guys could potentially share with us what throughput volumes are? I know you guys have the permitted number there? But do you have what throughput number was, and can you guys touch on -- of the water disposal capacity, is that primarily commercial and can take third party or just trying to get a sense of the materiality that you guys see on the third party side as well?
Matt Gallagher -- President and Chief Executive Officer
Right now, we're moving about 250,000 barrels a day on the existing infrastructure, and most of that permitting capacity is already in existence, its already consisting of gathering lines in SWD wells. So that's a pretty small fraction of our total permitted capacity. So we do think we have plenty of capacity in certain areas to look at third parties. And as I mentioned in the script comments, we've had several entities reach out to us and ask about both freshwater and SWD availability. So we're in some discussions with some of those operators right now.
Jeff Grampp -- Northland Capital Markets -- Analyst
Great, great. Appreciate that. And for my follow-up, you guys mentioned going back and doing some more compressed stage spacing, and since I recall, you guys had some good results on that a couple of years back. So I was just kind of curious if you guys could touch a little bit on what side -- I guess type of test program you all are looking at, and when you might have some results to come back to us with?
Matt Gallagher -- President and Chief Executive Officer
Yeah. We've done about 10 of those to date and compressed stages are just a little bit over half of our typical stage length. We've been encouraged by what we've seen so far. I think it's a little early to draw the line on exactly what optimal is. But there is of course incremental costs with it, but we have seen some incremental production uplift. So right now we're working on testing that further and tightening in that balance of performance and cost. It's an encouraging -- it's an encouraging possibility for us going forward.
Operator
Thank you. Our next question comes from the line of Asit Sen with Bank of America Merrill Lynch. Please proceed with your question.
Asit Sen -- Bank of America Merrill Lynch -- Analyst
Thanks. Good morning. With these well design changes, could you update your assumed well cost this year? And then, Matt perhaps if you could frame for us a DNC cost per foot, and kind of compare Midland to Delaware conceptually, that will be (inaudible)?
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Yeah. So, this is David. I'd say on average, our well costs are round $9.5 million (ph) in the Midland for a 2-mile lateral, about a little under $12 million (ph) in the Delaware for 2-mile lateral. And for 2019, there's a few things that are kind of opposing forces on those. You got a shift in the Midland, but we're also putting more RBS in to the ground, which helps and -- increasing in the overall frac size. So, I'd say those two things, the net effect of that gets you toward that $9.5 million in the Midland, a little under $12 million in the Delaware.
Asit Sen -- Bank of America Merrill Lynch -- Analyst
Okay. And your pad size is increasing methodically here. What's the embedded assumption in 2019 over 2018 and any plans for 3-milers in 2019?
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Yeah. We do have some additional 3-milers, not a lot of them. That's more a function of our land layout. So I think the key and the reason we highlighted the 3-mile that we put in the earnings presentation was, to show we can do it, and we've proven that for ourselves. We do have opportunities and we will take those where they are. I think generally speaking, our sweet spot on lateraling is still probably close to that 2-mile, 2 plus mile length. But, we'll certainly take them as they come, and as we do trades and bolster DSUs further, those opportunities may continue to grow.
Operator
Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.
Charles Meade -- Johnson Rice -- Analyst
Yes, good morning Matt, to you and David and Ryan and the rest of the team there.
Matt Gallagher -- President and Chief Executive Officer
Good morning.
Charles Meade -- Johnson Rice -- Analyst
If I could, actually just pick up on that 3-mile lateral question. I get -- I believe that was David who was saying really, it's merely a function of your land set up and where you could stack those three sections together. But are there other more mechanical or kind of fluid mechanics limitations on those on the 3-mile laterals? And if they are not, is there a -- there some limit that we now think, could you go to 4-mile or 5-mile laterals?
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Yeah, Charles. It's David. I think we have clearly shown from a drilling standpoint, the limit is beyond 3-miles. We executed that well quickly and efficiently. On the frac side, certainly there are friction effects that you need to take into consideration on a realized well, you have a large number of plugs. So what we've done is a lot of forward modeling in preparing for this 3-mile lateral, and we haven't completed it yet. We haven't drilled it out yet. But we have customized our pumping schedule. We've varied (ph) a few design parameters, including types of plugs that we run, depending on where you are in a lateral, we've done a lot of torque and drag on drill up and that's all 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 in this 3-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 to your question of what that technical limit is.
Charles Meade -- Johnson Rice -- Analyst
Great, David. Thanks for that. And Matt, you mentioned I think at least once or 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 you also mentioned that your 2019 program is going to benefit from the mix shift. Can you confirm that, that is the case that you are expecting more productive wells there and give us an idea of what that order of magnitude is?
Matt Gallagher -- President and Chief Executive Officer
Well, if we just look at our results in that area. To date, we can confirm that it is oilier, and it is more productive in the early timeframe. 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 shift, and I think you can just pull industry results and see the long-term results. They are anywhere from 5% to to 15% depending on the zone -- on the oil productivity uplift in the Midland Basin.
Operator
Thank you. Our next question comes from the line of Mike Scialla with Stifel. Please proceed with your question.
Mike Scialla -- Stifel -- Analyst
Hi. Good morning, guys. Last year you had to tap the brakes a little bit with your capital plan -- to stay within your capital plan, I should say. Just wanted to see how that impacted the 2019 plan if at all, and should we -- how should we anticipate the pace of spending and completion this year?
Matt Gallagher -- President and Chief Executive Officer
This is actually our first time in corporate history to put out a Q1 -- a quarterly guidance on the oil front. We thought that was important due to this -- due to the -- being disciplined in adhering (ph) to the capital of 2018 definitely has some follow-on effects. I'm actually really pleased that it generates consistent organic growth at the midpoint, so we don't see a backwards quarter even with that -- with pumping the brakes like you mentioned. And then -- turn it to David a little bit for the activity profile throughout the year.
David Dell'Osso -- Executive Vice President and Chief Operating Officer
The activity profile so we fired everything that was idle at the very end of Q4 backup. So you would expect to see a little bit higher capital in Q1 than subsequent quarters and pair that with a slightly lower pop count in Q1 that references to Matt's point. And then as you get through the year in quarters, two, three, and four, you'll start to see that pop cadence pick back up, as the normal normal cadence for our capital activity starts to generate those increasing pop counts in the back part of the year.
Mike Scialla -- Stifel -- Analyst
Great, thanks. And then, you had mentioned the wider spacing and prioritizing IRR over NPV, and I think the depth of your inventory was really a key component of making that decision. Just want to see how that drilling inventory has changed from 2017 to 2019, if at all, if you axe out oil price into that equation?
Matt Gallagher -- President and Chief Executive Officer
Yes, like-for-like, it really hasn't changed. So on slide 7 in the footnote, we have -- if you look at footage and we have $35 million gross footage, if you rewind back to the beginning of 2018, we've obviously drilled wells, which has eaten into the prior 2018 footage. We have sold a divestiture that ate into that footage, and then we had trades that -- from the interior that field into the core of the field that might be 2-foot for 1.5-foot type of trade. But if you net those out, the inventory on the DSUs has not changed. So you're left with the $35 million.
And then we gave the range there, if we go into the current spacing and you blow that down at the current development pattern, you're looking at $25 million gross fee associated with the productivity, we think we have on these wells. So we've really improved -- even though the footage pass-out (ph) hasn't changed. We've really improved the quality of the footage as well.
Operator
Thank you. Our next question comes from the line of Eli Kantor with IFS Securities. Please proceed with your question.
Eli Kantor -- IFS Securities -- Analyst
Hey, good morning guys.
Matt Gallagher -- President and Chief Executive Officer
Good morning.
Eli Kantor -- IFS Securities -- Analyst
Our numbers might be stale on this, but I feel like it's been a while since you guys have published EUR for your Midland Basin development activity. Can you give us a sense with rates of return improving 2019, what kind of EURs you expect from that development program?
Matt Gallagher -- President and Chief Executive Officer
It's -- we have about 50 different type curves on a blended case, if you don't do -- if you don't take into account, the mix shift. In the developments 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 though. We've been within 3% plus or minus year in and year out on those estimates. So no changes in the type curves -- I mean in the EURs, 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.
Eli Kantor -- IFS Securities -- Analyst
And as far as your royalty acquisition program goes, any specific acreage growth you expect on that front, can you talk about the opportunity in the Midland Basin as it compares to the Delaware?
Matt Gallagher -- President and Chief Executive Officer
The opportunity is right, but we spent about $140 million in that effort last year, and pulling pulling back on that activity in 2019 by design. So really focused on the drill bit. We have a great position there as well, 7,600 net royalty acres and strong high margin cash flow coming out of that. So we're really pulled back on that budget in 2019. I don't see us pursuing actively, although there is quite a bit of opportunity.
Operator
Thank you. Our next question comes from the line of Gail Nicholson with Stephens Inc. Please proceed with your question.
Gail Nicholson -- Stephens Inc. -- Analyst
Good morning. Just looking at NGL price realizations this quarter they were very healthy, they were actually up versus third quarter, and then GAAP realizations were weaker than I was anticipating. Can you just talk about the driver between those things and how we should think about NGL versus gas price realizations in 2019?
Matt Gallagher -- President and Chief Executive Officer
For gas specifically, December was a negative print -- the first week of December on residue gas. And I think that's what drove down most of the industry in the Permian on the realizations on the gas. NGLs have been healthy and we'd anticipate that to continue to be the case. There's a lot of demand downstream for the NGL side.
David Dell'Osso -- Executive Vice President and Chief Operating Officer
And then on the oil side, we're still reaping the benefits of the diversified pricing. I think you've seen our -- our oil realization quite a bit higher than some of the other peers that have come out.
Gail Nicholson -- Stephens Inc. -- Analyst
Great. Thank you.
Operator
Thank you. We have reached the end of our question-and-answer session. And this concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.
Duration: 47 minutes
Call participants:
Kyle Rhodes -- Director of Investor Relations
Matt Gallagher -- President and Chief Executive Officer
David Dell'Osso -- Executive Vice President and Chief Operating Officer
Ryan Dalton -- Executive Vice President and Chief Financial Officer
Michael Hall -- Heikkinen Energy Securities -- Analyst
John Freeman -- Raymond James -- Analyst
Gabriel Daoud, Jr. -- Cowen and Company -- Analyst
John Nelson -- Goldman Sachs -- Analyst
Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Jeff Grampp -- Northland Capital Markets -- Analyst
Asit Sen -- Bank of America Merrill Lynch -- Analyst
Charles Meade -- Johnson Rice -- Analyst
Mike Scialla -- Stifel -- Analyst
Eli Kantor -- IFS Securities -- Analyst
Gail Nicholson -- Stephens Inc. -- Analyst
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