Greetings, and welcome to the Halcon Resources Corporation's Third Quarter 2018 Results. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mark Meisz, CFO, Executive VP and Treasurer.
Okay. Thank you. Good morning to everyone. This conference call contains forward looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website.
We've also updated our investor presentation for the Q3 and some other operational items. You can access that presentation on our website. I'll kick off the call with a few comments on the company's financial performance for the quarter, and then I'll turn the call over to John and Floyd followed by Q and A. Production for the Q3 averaged 14,609 barrels of oil equivalent per day comprised of 73% oil, while overall production on a per BOE basis was slightly below the midpoint of guidance. Oil production was in line with expectations.
The lower gas sales were primarily a result of some flaring a Monument Draw this quarter and John will address that more when he makes his comments. Our realized 3rd quarter oil differential of 79% in NYMEX was less than the 90% differential seen in the quarter due to weaker Midland pricing as a result of increasing production in the basin coupled with some continued takeaway constraints. Our 3rd quarter natural gas differential came in at 47% in NYMEX and our NGL differential for the 3rd quarter of 45% was higher than the 2nd quarter differential of 39% and that was due to higher purity product prices, most notably ethane, which had the most significant increase quarter over quarter and is also the product we sell the most of. Our LOE and workover expense came in at $6,800,000 for the quarter or $5.02 per BOE, which was much lower than the $6.25 per BOE seen in the 2nd quarter. Gathering and other expense as adjusted totaled $5,100,000 for the quarter, which equates to $3.77 per BOE.
We expect adjusted LOE and gathering transportation and other per BOE to continue to trend down in the Q4 and going into 2019 as we continue to gain scale and improve operational costs. G and A expense, as adjusted totaled $9,100,000 in the current quarter versus $10,100,000 that we had in the 2nd quarter. We had a significant amount of non recurring expense this quarter primarily related to gas treating cost and Monument Draw. You'll see in the selected items table, we had $20,800,000 of non recurring expenses, which did include the treating cost of $14,000,000 dollars as well as an administrative charge that came through. John will address the treating plan in Monument Draw during his comments.
With respect to D and C, we incurred $96,000,000 during the Q3, which was lower than $132,000,000 incurred in the second. We did spend about $39,000,000 in the Q3, the majority of which was on infrastructure. As far as hedging, we realized the net loss on settled derivative contracts of about $10,000,000,000 during the Q3 this year. We have 15,504 barrels of oil hedged in 2019 at an average price of $56.27 We have 4,000 barrels a day of oil hedged in 2020 at an average price of $58.56 We also have 9,463 barrels a day of Mid Cush basis swaps in place for 2019 at an average price of 3.83 dollars And then turning to gas, we currently have 24,000 MMBtu a day of gas hedged in 2019 at an average price of 2.81 and we have 25,500 MMBtu of Waha basis hedges in place for 2019 at 1.18
As
far as NGLs, we have 4,252 barrels per day of NGLs hedged in 2019 at $29.51 a barrel. The final comment that I'll make, we did recently go through our fall borrowing base redetermination. The borrowing base was increased to $275,000,000 from $200,000,000 That increase will go effective upon the closing of the water infrastructure assets. So, and as of September 30, 2018, pro form a for the water infrastructure sale proceeds and the new borrowing base of $275,000,000 we had 4 $18,000,000 of liquidity, which does consist of $145,000,000 of cash on hand plus $275,000,000 committed on the revolver. With that, I'll turn the call over to John.
Thanks, Mark. As Mark indicated, we had quite a bit of gas flaring during the 2nd during the 3rd quarter in Monument Draw, driven by 2 factors. First, we lost the 3rd party sales pipeline in late June that was unexpectedly taken out of commission for repair. Secondly, we are developing our high spec gas gathering infrastructure and treating capacity in this area to handle the sour gas these wells produce. During the Q3, we primarily used H2S scavengers treat the gas down to pipeline spec at the well ahead.
This is an effective but expensive temporary treating option. As of last week, we were able to begin putting most of our gas into a 3rd party sour gas pipeline, which will lower our 4th quarter trading costs versus Q3 levels. However, we are still required to do some trading of gas to get to this 3rd party pipeline. Our medium term solution is the construction and installation of a large scale liquid redox unit at our central processing facility in Monument Draw. We are currently underway on the construction of this system, and we expect to have it operational by the end of Q1 of 2019.
The ultimate solution here, which will radically reduce gas feeding costs, is to develop and utilize an acid gas injection or AGI well. We are currently working through the permitting process and expect to have an AGI well in operation sometime in the second half of twenty nineteen. We expect flaring to be reduced in the 4th quarter as mentioned and going into 2019 as we work on these solutions. We have also included a slide in our investor deck that lays out our treating gas treating plan and Monument Draw over the next several quarters the related treating costs going forward. Despite the elevated short term treating costs in Monument Draw, we are more excited than ever about this area given the excellent well results we saw in the Q3.
We put 8 new wells online and all were looking very strong and exceeding our expectations. Our average 30 day peak IP rate for the 5 wells, which have reached peak 30 day rates, was 17.53 BOE per day at 80% on average. Our average 60 day IP rates on these same 5 wells was 15.58 BOE per day at 80% oil. The Telluride and Trinity wells were exceptionally strong with 30 day average IP rates of 1911 and 2,182 BOE per day, respectively, at 81% oil. These two wells are still averaging over 1400 BOE per day each after about 3 months online.
This is all illustrated on Slide 9 of our investor deck. With 14 very successful horizontal Wolfcamp wells across our Monument Draw position, We have done a lot of work towards de risking this asset. As you can tell, we are very excited about the results we are seeing in Monument Draw. Our wells are consistently outperforming our type curve by a significant margin. We look forward to bringing your rig back to this area in December.
We put one well, Wilkamp well online in Hackrates Roll in the Q3 of 2018 and 2 more were put online in late October. We continue to see good productivity on these recent wells as we've been focused on growing our best areas of this position. We are continuously evolving our completion design to lower our D and C costs and improve rates with the ultimate goal of improving the economics of this play. We expect to put online 2 additional wells in November and we'll continue to run a rig here in early 2019. In West Quito Draw, we put our first two wells online last week and expect to put online 3 more right around year end.
All of these wells are 10,000 foot Wolfcamp laterals. Although it's early days, the pressures and rates we are seeing on these two wells flowing back right now are extremely strong and we're excited to report on these wells sometime in the near future. We will continue to keep at least one rig running here through early 2019. With that, I'll turn the call over to Floyd.
Thanks, John. Well, just to recap, drilling is going great. We're making wonderful wells at Monument Draw. Early stage flowback at West Quito on our first two wells is as good as we've seen. John didn't mention it, but early stage flowback on a couple of new wells at Hackberry Draw are as good as we've seen in that area as well.
This transaction that we've entered into to sell our water infrastructure at a very good value is a great situation for us in terms of our liquidity and moving forward with a little bit less CapEx, but also aligning ourselves with a partner with significant other water infrastructure assets in the Delaware Basin. And of course, as I mentioned, materially reduces our infrastructure capital spending this year and beyond. So it's a good deal all the way around. Our borrowing base was recently increased. We expect that to continue to increase as we continue to bring on strong wells and increase revenue and EBITDA.
We are going to continue to focus in Monument Draw and West Quito. We'll bring a rig back to Monument Draw in December next month. And we're just really excited about all that. We're particularly focused on early stage results at West Quito. We have, as I said on an earlier call, we pulled one of the best shuttle logs we've seen in the basin and the early stage flowback is looking great on those first two wells.
We're going to continue with 3 rigs for a while. We could add 4th rig sometime next year, but we don't need to, to meet our growth plans. We'll report on those plans early in 2019 and give some guidance. We're not doing that quite yet. A couple of interesting things to note for your own databases, it's all multi well pad drilling going forward, no singles, most all 10,000 foot laterals.
And we're already switching to more in basin sand. So this is in the the 100 mesh in basin component that's being increased and we're still using the very strong Wisconsin white for the fortyseventy, but we're working on getting those costs down in that way. The Q4 production will be about 19,000 barrel, will be the midpoint of our guidance. So less due to flaring and shutting in one of our wells at Monument Draw, just coming on that had high sour gas levels. We'll expect to put that well back online in just a few weeks early in 2019.
We've spent it looks like we'll spend about $85,000,000 in the 4th quarter. That will result in about $430,000,000 for the year. Important to note that nearly 10% of that amount is involved in 2 big ticket items and one is presetting casing, surface casing and intermediate casing on a number of wells we drilled in Monument Draw and running more shuttle logs in microseismic than we might have thought that we would because we're getting such great information from those efforts. Infrastructure spend, expect to be about $25,000,000 in the 4th quarter. And again, that's oil and gas infrastructure spend.
John mentioned our path towards lowering cost at Monument Draw in terms of the sour gas treating. There's a slide in our deck, I think it's number 30. It's an interesting slide and it's a result of a lot of hard work and complicated issues, but it's something that we're well versed in and we've got the right people to handle this. We're happy where we sit today. Liquidity looks great.
We're making great wells. Our goal is always to make a lot of money for our shareholders. Our balance sheet is looking good. We did risk our acreage. So we're doing quite well.
With that, operator, I'll we'll take some questions if there are any.
Our first question comes from the line of Jeffrey Campbell from Tuohy Brothers. Please proceed with your question.
Good morning and congratulations on the water system sale.
I wanted to ask you first, could
you just sort of give us some high level color on the decision making that surrounded deciding to sell the discrete water system infrastructure as opposed to just selling the entirety of the midstream assets?
Sure. It's an easy thing to think about. The water side of our infrastructure business is much more mature, making about 90,000 barrels of water a day, I believe, here in the last several weeks. The EBITDA multiple that we got for that asset would be 10 times
just on
the down on the first payment and up to 14 or 15 times if we earn the rest of the $125,000,000 So
it's quite
a financial coup to bring that in. It also reduces our CapEx dramatically on the water side so that we can focus on some of these issues that we're facing in some of the other areas. So I think it was a good move. The maturity of the water business relative to the oil and gas business, it's about 1.5 years apart. So we would expect EBITDA generated in the future from the oil and gas infrastructure business to catch up with that, that we've already projected for the water business within a year and a half or so.
Okay. So unless if I can follow-up on that, it sounds like that you feel like if you had if you hold on to the oil and gas and continue to develop it, you're going to get a much better return in the future than you would have gotten now. And if we could somehow think about a total return, it's much better to hold on to the asset and develop it out more and then sell it later. And plus, you don't really need the money right now anyway. Well,
you said it better than I could.
Thank you.
I got lucky. My other question is another kind of broad one. There's been some discussion in the investment community about Halcon accelerating a sale of Hackberry Draw on the argument that Monument Draw is much higher return in area. Just was curious to have your thoughts of whatever pros or cons you might see in trying to have such a sale at this time? Well,
first off, we're appreciative of ideas that come in from shareholders and we take them seriously and we look into all those things. We're always looking at shuffling our asset deck and to come up with the best results whether we shuffle in terms of capital intensity or shuffle in terms of ownership. So I would just say that we're just now bringing on a few wells at Hackberry Draw that look really good. We haven't really drilled what's well known to be the best part of the acreage. We started out down there to capture leases.
So everything's under consideration here. There's no sacred cow in terms of assets. And I would just tell you that our background, as you might as I hope you might know, is we're very active portfolio management managers. We're constantly thinking about that. So I'm not going to give you a yes or no or anything like that, but certainly something that we've considered and continue to consider.
Yes. I think your record speaks for itself. So don't have any second thoughts about that. Appreciate the answer.
Our next question comes from the line of Jason Wangler from Imperial Capital. Please proceed with your question.
Good morning. I wanted to ask, Floyd, as far as the 3 rig program, thinking about moving forward, should we think about 1 being station in of the 3 plays or kind of how you think about that cadence around the asset base?
If you're trying to model, I think, and again, it'd be more like a half a well at Hackberry Draw and 2.5 wells kind of split evenly between the other two areas for the
year. Okay. And then you mentioned moving the pad drilling. I'm sure there's some variability here, but are you how many wells are you kind of looking at for the average pad? And are you targeting a couple of formations?
Or just is there a space
that you're going after? Just curious how you're looking at that side of it.
Well, it's a little different across the asset base. They're all 2 to 4 well pads going forward and even heavily weighted towards more wells per pad by 2020. But for 2019, it's all multi well pads. Certain areas, we're doing spacing test with and evaluating those results tracer surveys and microseismic and production results. In other areas, we're testing different benches.
We report on those every quarter. So we're doing some of each, both spacing and both delineating different benches within the areas. Of course, at West Quito, we're just getting kicked off there. And there'll be more to talk about there really, really quickly.
Okay. I appreciate it. Thanks very much.
Our next question comes from the line of Mike Kelly from Seaport Global Securities. Please proceed with your question.
Hey, guys. Good morning. Looking at Slide 30, just wanted to understand what the CapEx outspend or not outspend, the CapEx spend should be for you guys to get this kind of sour gas issue squared away?
We don't have those numbers here yet. We're focused on getting the OpEx into some reasonable status. So we haven't given guidance on that guidance on those costs, Mike. I can tell you that they're insignificant in light of what the alternative is, which is this chemical treating, which would cost us so much money in Q3. I don't really know if I have a good way to give you some guidelines.
AGI wells, if you're disposing in shallow more shallow zones like in the Dakota Mountain series, you have a 100% different answer than if you end up needing to dispose in deeper zones like the Ellenberger, a few $1,000,000 to $10,000,000 or $15,000,000 So we're working those numbers pretty hard. When we give guidance for 'nineteen, which we intend to do before too long, we'll certainly have all that wrapped in. And again, that's a little vague, but it's fast breaking news how to get to the best balance of cost and revenue as quickly as you can.
Got it. And I know you have guidance coming here shortly on 2019. But if I'm just want to look at a couple of the big factors there in our model, which would be just well costs and it sounds like you're going to all these 10,000 footers for the most part, 3 rigs. Just curious on how
we should think about costs
in the three areas and then also cycle times too, if you have some rough estimates there for us?
Yes. That's a great question for John to address on cycle times. He's had some his group has had some wonderful results here this past couple of quarters. And on the cost side, I'd like John to address that too. Between multi well pads and in basin sand and as you said, cycle times, I think there's some real meat on that bone.
John, you have a few comments?
Yes. I think if we've included some near term drilling plan and efficiencies in a slide in our investor deck, specifically Slide 7, that shows in our Hackberry draw, our drilling efficiencies have dramatically increased where we dropped days from a 10,000 lateral to 18 as of Q4 of 2018. So real proud of the results that the drilling team has done there. We've also seen those drilling efficiencies in Monument Draw while drilling our 1st intermediate section from spot to rig release. As we're up against the single basin platform, we've got a number of issues that may not be evident we're seeing in the really the core of the play.
The drilling team has done a fantastic job in overcoming some of these challenges, and that's shown we've been able to decrease the time from spud to rig release in those intervals from 12 to 17 days in Q4 of 2017 and to 1Q of 2018 down to about 4.7 day average now. So significant improvements there. That all impacts cycle times. When we think about costs, there's a slide in our deck, which outlines the our type curves and the D and C costs associated with that. It includes the impact of the higher water handling costs associated with the water infrastructure divestiture.
Money draw, we're looking at D and C cost of $12,600,000 West Quito Draw $11,500,000 and Hackberry Draw $10,900,000 dollars At the same time, we're focused on improving our costs through efficiencies, kind of demonstrate that on the drilling side, on the completion side. We've had increased use of local brown sand at the with 100 mesh. We've increased the quantity of the 100 mesh we're pumping our jobs from about 10% to more recently in our current wells about 20% to 50%. As you may be aware from our previous discussions, our proppant loading has dropped from £2,500 to £2,000 that was previous to the Q3. And obviously, all the great results that we've demonstrated, especially in our slide deck on Page 9, with regard to Monument Giroche, we haven't seen any negative effects of the decrease in that proppant loading.
We felt that we were over stimulating our reservoir box by £2,500 per foot. And the near term early time results certainly support that. Other areas that we're focused on increasing costs is we're increasing our clusters and our stage lengths, while maintaining 90% to 95% cluster efficiency. We're confirming this by tracer studies and microseismic, and we're maintaining the high efficiency through a high limited entry strategy. So that really kind of defines the completion side.
On the production side, we're focused on our multi well development, but also utilizing central production facilities. So we're not building out batteries at each individual pad. We're bringing that into central production facilities in West Quito and Monument Draw, which adds efficiency, drops infrastructure costs on the production and facility side of our D and C costs. Secondly, in Hackberry Draw, we're drilling within the floor of our area, which already has that infrastructure development in place. So we're able to utilize existing equipment, which also helps support those production and facility costs.
I think that pretty well sums us up there, Lloyd.
Mike, always keeping in mind that these are great wells. They're long term assets. All the things that John just mentioned are somewhat expensive in the early stage, central production facilities, all this infrastructure, the science that we do, but it's well in keeping with the results that we're having. And the cost that he mentioned on a per well basis, I can tell you that internally compared to if we looked at those on a go forward relative to say the last 12 months, we're internally hoping that our historic cost per well will go down 20% or 30% per well. And that's a those are round numbers.
But so if we look at if we're backward looking view to our forward looking view, we're looking at 20% to 30% improvement on a per well basis.
Got it. Great color there. Very well to sum it up. Floyd, if I sneak one more in for you. I just wanted to see if I'm interpreting your answer properly to Jeff's question on Hackberry Draw and about a potential sale there.
What I kind of heard from you is that you definitely look at it, but might be a little bit early right now as you're just starting to get to maybe your best acreage there and start to post your best results. So, is that a fair way to think about it?
I guess I responded in Spanish or something. I'll say it again. We constantly review our portfolio, both in terms of capital intensity and in terms of ownership. And it's very clear that if you have an asset that far results are better than another asset, you have to look at that other asset pretty hard all the time. But as you're doing that, you have to make sure that you know what your what the playing field is.
And the playing field is that we have laid a lot of infrastructure in Hackberry Draw. Everything we've drilled so far, most have been one off wells, but they were all they all we built big pads everywhere. And we're just now, as John pointed out, we're just now drilling in the best part of the acreage, which before we were drilling. So I think, yes, it might be early in terms of how a shareholder might think of it, but we're rushing to conclusions all the time based on data as soon as we can get data. So I would say that anything is possible with us along those lines.
And frankly, good ideas, if you test them and they're still good, you tend to execute. So I'm not giving guidance or anything. I'm just telling you that it's a very active analysis on our part and it's a very serious analysis and it's a very valuable asset by the way. And so you don't want to just throw out the baby with the dishwater, so to speak. You want to make sure that you understand what you own and how much it's worth.
And also, you have to assess the timing in the market for that sort of any sort of a transaction that you might engender there. But we have other options. We've been approached with DrillCo ideas down there or JVs. So we're making sure that we understand all the nuances of the asset and also understand the financial implications of a sale and we understand how bringing a big slug of money and would be very attractive to us and to others, but we have to do it in a workmanlike manner.
Good follow-up. Thank you.
Our next question comes from the line of Tarek Hamid from JPMorgan. Please proceed with your question.
Hi, this is actually Kevin on for Tarek. Thanks for taking my question. Just wanted to look at G and A quarter over quarter. I just noticed there's slight uptick and I think part of it was on some embedded costs. So I just want to see if transaction costs, I just want to see if you can give some more color on that?
Mark, why don't you handle that please? Yes. We did have one item come through G and A. It's been backed out as a non recurring item in the press release and it just related to a legal matter that's been ongoing and we just went ahead and accrued a little cost associated with it.
Okay. Is that sort of something that's expected to be recurring or
No, no, no. It's not recurring at all.
Okay. And just curious, I know that on takeaway options for Hackberry Draw, I know it's a little bit early days, but just want to see how some of those conversations has been going with some of those operators in sort of late 2019 timeframe?
John, do you have a
comment on that? We do have a contract that matures in Steve, maybe? Well, on we've at Hackberry, we've got oil and gas takeaway options in place that we inherited when we bought the property a couple of years ago. So we're in good shape there as we are up in Ward County. We've got on the oil side, and this is very important for us going forward, 25,000 barrels a day that will get in service sometime in the second half of next year, maybe early second half of next year with the EPIC pipeline.
But we have a situation with contract with maturing again, oil contract with maturing?
In Hackberry, we have a on the oil side, we have a the takeaway matures or expires next August, and we're looking at our options there in terms of either extending or renewing it or looking at other alternatives or a combination.
So there's some room for improvement there and we're working it pretty hard like we do all issues with about marketing and takeaway options.
Okay. I appreciate that color. And my last one is just back to some of the gas trading issues that you guys had. Just want to see more broadly, is that is there are there any other areas that could potentially be an issue as well? Or is this kind of isolated monument draw?
Well, this is Kevin, right?
That's right.
Okay.
The sour gas issue is widespread in the basin. In some areas, it's much more acute than other areas. In some areas like Monument Draw, there's very little. In other areas, there's more. West Quito, very little, but I'm going to say that all of the conversation that you hear about treating issues and pipeline capacity issues, gathering lines, a lot of it in the basin has to do with sour gas.
And so we're trying to get ahead of it as we always do by constructing our own infrastructure to deal with it. So as we're not as we saw this earlier this year, a pipeline sour gas pipeline just went out of service for maintenance and repair. And it just put us it was unexpected. This put us behind the 8 ball, so to speak. So we're intending to build that infrastructure ourselves and as quickly as we can.
And as you might know on that Slide 30, there's the most expensive thing is what we've been doing in the Q3. We've already got a lot of that gas moved into an alternative pipeline. We're putting in a different kind of treating early in 2019. As you can see, if you kind of follow those costs down, getting down to around $2 an M and then getting down to less than $1 an M by the second half of twenty nineteen. And these are we got a little specific about it here just to make sure that people understand that this is the reason it's such a significant issue is because the wells are so darn good.
And you have to preserve the economics of these kinds of wells and we're going to we're putting in a long term solution for this issue, whether it's it is a little different from north to south and we, of course, know that, but we're providing for plenty of capacity for treating and moving sour gas for a long for the length of the life of the wells.
Thanks so much for the color. That's helpful.
Our next question comes from the line of Chris Bred from ART Capital. Please proceed with your question.
Hi, guys. Thanks for taking the call and congratulations on a pretty good quarter. Two specific questions for you. Number 1, what are your current water to oil ratios? Do you think it's coming across your basin across your full footprint 2018.
I didn't see it broken out in the supplemental information. And what are you projecting as your order to oil ratios for 2019?
John can speak to that. We don't exactly guide in that way, but we're certainly in a position to give you some pretty round numbers. Go ahead, John.
Thanks, Floyd. So the water level ratios differ as you move across the basin. We've seen an accurate drop. That's where
we're in an area where
we have our highest water roll ratios. And if you're including our actual frac load, reaching as high as 8, but that's after frac load is recovered, you're more in that 5.5 to 6.5 range. That's barrels of water per barrel oil. West Quito, on the results that we've seen on the offset wells in that area, you're looking about 4.5% to 5.5%. That seems to be about a basin average overall.
And when you move further to the east in Ward County, where Monument Draw asset sits, we're closer to about 2 barrels of water per barrel of oil. So we have some wells that are down to about a 1:one average. So it varies across each one of our assets. Obviously, as you go across the basin, up closer to the platform, it seems like those water oil ratios really trail off.
You said as you go up to the basin, those water oil ratio is really what?
Well, as you move towards the Central Basin platform, so we're talking about going from West Quito, we're probably more closer to a basin average. Our wells in Monument Draw, which are in Eastern Moore County, are about a 2:one average on overall. We're seeing wells that are about a 1:one average as well.
Okay. I'll try and follow-up because I'm just trying to get you're giving a sense of direction and I'm trying to get it clear. Are you saying as you move east, you're seeing your WRO ratios drop or are you seeing something else?
Listen, they stay very sort of consistent. They're higher when you're bringing back frac water. But John said that they're after frac, they're about 6 to 1 in Hackberry Draw. They're about 5 to 1 at West Quito and about 2 to 1 in Monument Draw. And those are fairly stable numbers to use for modeling purposes.
Perfect, perfect. Thanks. And then my follow-up is and thanks for giving me clarity on that. Currently, do you how tight are your formations? And do you guys have any EOR processes in place?
I'm just trying to get an understanding of what your asset base looks like, how tight it is. Just I'm trying to get a better view of what your water usage is currently. And then clearly, you guys have enough capacity here online to double it, given that in the high measure you've got, I think was it, you just mentioned that the pipeline that's coming up, yes, you've got 25,000 barrels per day gross agreement in place for next year in 2019. So it sounds like you have enough capacity to get yourself taken away. If you can get everything up to that point, you drop the costs, you guys should be good to go.
I'm just trying to understand what does water play insofar as your cost curve to get to that $25,000 takeaway. So if you are successful in the next year, what your water costs look like trying to get to that success given the transaction you just did? Thanks.
Yes. We've modeled the water cost into the numbers that we provided in this slide deck. The shale formations are tighter than heck. I mean, you go from 2% or 3% or 4% to sometimes 10% porosity, I guess. I don't know.
John, is that
close?
Yes. That's in the range of outcomes, Boyd.
Yes. In terms of enhanced recovery projects, of course, they're on our radar screen. We are so early stage in just the development of these assets that we're cognizant of some studies that people have done in this and in other basins and beginning to think about in this basin. But they're certainly not on the they're not high up on our list of things to think about right at this moment. There's a big debate as far as where the water comes from out here.
I don't think that I don't know that we have an exact answer. It's typically the shale itself is not a water rich rock.
Thanks, guys.
Our next question comes from the line of Vivek Pal from Seaport. Please proceed with your question.
Hi, guys. Floyd, what's your how much have you spent on the oil and gas midstream business so far? I just want to get a sense of the potential valuation in the future and if you could give us a breakdown of the EBITDA. And you had mentioned that $25,000,000 expenditure in the 4th quarter. Is that a good run rate?
Can we analyze that?
Well, there's no run rate, but I can tell you that I think through the quarter we spent about $175,000,000 $180,000,000 on both and water and gas. And probably sort of half of that would be on the water and a little less than half and the rest on oil and gas. Now this includes, keep in mind, it's gathering pipelines, it's treating, it's compression, it's storage, it's everything. So we're on a go forward basis, a lot of the oil and gas is driven by the good news is we've been building these central production facilities already and those are somewhat pretty much in place. And then the a lot of the CapEx is going to be associated with this build out associated with Slide 30 in the deck of getting from a very high treating cost to a very low treating cost for sour gas.
And we haven't guided for that spend in 2019 yet. Do we have a number for the Q4 of 2018 for in the deck here? Quentin, is there a number for that in here?
I thought you had mentioned $25,000,000 for infrastructure spend in 4th quarter, maybe I misunderstood it.
That's right. It's $20,000,000 to to $30,000,000 next year or in Q4 this year.
That's part
of the $85,000,000 you're going to spend, right? That is in addition to $85,000,000 CapEx that you mentioned for Q4?
Yes.
That's in addition I'm sorry, that's in addition to 85 or part of 85?
No, it's in addition. The 85 is our drilling completion capital spend. There's another 20 to 30 in infrastructure, primarily related to the build out of our gas infrastructure and Monument Draw for this IH2S area.
And do you break down how much EBITDA from the gathering business sorry, the midstream business in E and P?
We don't publicly talk about that.
Okay.
And Floyd, lastly, is it still fair to assume that you could get a similar multiple for your oil and gas infrastructure like you got for the water assets?
Well, I would like to suggest we'll get a higher multiple, but I don't really know. It's not right to move just yet. The as I mentioned earlier in this call, we expect the EBITDA on and we're not giving the exact number, of course, but the EBITDA from our oil and gas infrastructure business to catch up with EBITDA from the water business within 18 months and then exceed it perhaps. So the rest of our business, in my opinion, is going to be worth more than the water infrastructure business.
Okay. And in the water infrastructure business, the incentive payment, is it full $120,000,000 can you get full $125,000,000 or you can get partial? I know you would like to get the full, but is it like a binary outcome or
Our goal will be to get all of it, but that strictly is a product of rig count. And then if you do anything else with if you add rigs or do drill codes or something like that, you increase your earn out of that amount. I don't think we haven't modeled it exactly, but we would expect the earn out of that to grow dramatically after 2019 and to be reasonable in 2019, but not we probably wouldn't get it all in 2019.
Right. And the drill core you're talking about in Hackberry, right?
I can say that.
Okay. All right. Thank you.
Ladies and gentlemen, we have reached the end of the question and answer session. And I would like to turn the call back to management for closing remarks.
Thanks everybody. I think this is a fairly complete data set. If you think of something we didn't cover, just give us a call. We're pretty excited about we're very excited about where we are and what we're doing and all the things that we're doing to make the future look even better than it looks right now. Thank you.
This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.