Greetings, and welcome to Halcón Resources Corporation's Third Quarter 2018 Results. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mark Mize, 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 third quarter 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 Jon and Floyd, followed by Q&A. Production for the third averaged 14,609 barrels of oil equivalent per day, comprised of 73% oil. Our 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 at Monument Draw this quarter, and Jon will address that more when he makes his comments. Our realized third quarter oil differential of 79% of NYMEX was less than the 90% differential seen in the second quarter due to weaker Midland pricing as a result of the increase in production in the basin, coupled with some continued takeaway constraints. Our third quarter natural gas differential came in at 47% of NYMEX. And our NGL differential for the third quarter of 45% was higher than the second 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 $6.8 million for the quarter or $5.02 per Boe, which was much lower than the $6.25 per Boe seen in the second quarter. Gathering and other expense as adjusted totaled $5.1 million for the quarter, which equates to $3.77…

Thanks, Mark. As Mark indicated, we had quite a bit of gas flaring during the second - during the third quarter at Monument Draw driven by 2 factors. First, the loss of third-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 this wells produce. During the third quarter, we primarily used H2S scavengers to treat the gas down the pipeline stacked at the wellhead. This is an effective but extensive temporary treating option. As of last week, we were able to begin putting most of our gas into a third-party sour gas pipeline, which will lower our fourth quarter treating cost versus Q3 levels. However, we are still required to do some treating of gas to get to the third-party pipelines. 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 first quarter of 2019. The ultimate solution here, which will radically reduce gas treating cost, 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 2019. We expect flaring to be reduced in the fourth quarter as mentioned and going into 2019 as we work on these solutions. We have also included a slide on our investor deck that lays out our treating - gas treating plant in Monument Draw over the next several quarters and the related treating costs going forward. Despite the…

Thanks, Jon. 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. Jon 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 three rigs for a while. We could add a fourth 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…

[Operator Instructions]. Our first question comes from the line of Jeffrey Campbell from Tuohy Brothers.

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 entire unit of 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 10x just on the first payment and up to 14 or 15x if we earned the rest of the $125 million. 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 the 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 1.5 years or so.

Okay. So unless - if I can follow up on that. It sounds like that you feel like 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've gotten now. And if we could somehow think about total return, it's much better to hold onto the asset and develop it out more than sell it later. And plus, you don't really need the money right now anyway.

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 Halcón accelerating a sale of Hackberry Draw on the argument that Monument Draw is a much higher-return area. I just was curious to have your thoughts on 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 to come up with the best results, whether we shuffle it 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 is under consideration here. There is no sacred cow in terms of assets. And I would just tell you that our background as you might - 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 a no or anything like that, but this is certainly something that we've considered and continue to consider.

Our next question comes from the line of Jason Wangler from Imperial Capital.

I wanted to ask, Floyd, as far as the 3-rig program, thinking about moving forward. Should we think about one being stationed in each of the 3 plays? Or kind of how you think about that cadence around the asset base?

You know if you're trying to model, I think - and again, it would be more like half a well at Hackberry Draw and 2.5 wells kind of split evenly between the other 2 areas for the year.

Okay. And then you mentioned, moving the pad, drilling, I'm sure there's some variability here. But how many wells are you kind of looking out for the average pad? And are you targeting a couple formations? Or just is there a spacing that you're going after? I'm just curious how you're looking at that side of things.

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. In certain areas, we're doing spacing test with and evaluating those results with 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 will be more to talk about there really quickly.

Our next question comes from the line of Mike Kelly from Seaport Global Securities.

Looking at Slide 30, I just wanted to understand what the CapEx outspend - or not outspend, the CapEx spend should be for you guys and the 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 has caused us so much money in the third quarter. 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'll have 100% different answer than if you end up into disposing deeper zones like the Ellenberger. A few million dollars to $10 million or $15 million. So we're working those numbers pretty hard. When we give guidance for '19, 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 '19, but if I just want to look at a couple of the big factors there in our model, which should be just well costs. And it sounds like you're doing all these 10,000-footers for the most part, 3 rigs. Just curious on how should we think about costs in the 3 areas. And then also cycle times, if you have some rough estimates there for us?

Yes. That's a great question for Jon to address on cycle times. He's had some - his group has had some wonderful results here these past couple of quarters. And on the cost side, I'd like Jon 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. Jon, do you have a few comments?

Yes. I think we've included some near-term drilling plan and efficiencies in a slide on our investor deck, specifically Slide 7. It actually shows in our Hackberry Draw, our drilling efficiencies have dramatically increased. We have moved up days from our 10,000 lateral to '18 as of Q4 of '18. So we're proud of the results that the drilling team has done there. We've also seen those joint efficiencies at Monument Draw while drilling our first intermediate section from spud to rig release. As we're up against the single-basin platform, we've gotten a number of issues that may not be evident. We're seeing really the core of the play. The drilling team has done a fantastic job in overcoming some of these challenges, and that's showing. We've been able to decrease the time from spud to rig release and those intervals from 12 to 17 days in Q4 of '17 and into 1Q of '18. It's roundabout 4.7-day average now. So significant improvements there. That will impact cycle times. When we think about costs, there's a slide in our deck, which outlines the - our type curves and the D&C costs associated with that, and it includes the impact of the higher water handling costs associated with the water infrastructure divestiture. Monument Draw, we're looking at D&C costs, $12.6 million; West Quito Draw, $11.5 million; and Hackberry Draw at $10.9 million. At the same time, we're focused on improving our costs through efficiencies, demonstrated that on the drilling side, on the completion side. We've had increased use of local brown sands with 100 mesh. We've increased the quality of the 100 mesh that's 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…

Yes. Mike, always keeping in mind that these are great wells. They're long-term assets. All the things that Jon 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 those are round numbers, but - so if you look at our 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. Great way to sum it up. And Floyd, if I could sneak one more in for you. I just wanted to see if I'm interpreting your answer properly. Just the question on Hackberry Draw and about a potential sale there. What I kind of heard from you is that you'd definitely look at it. But it might be a little bit early right now as you're just starting to get to maybe your best acreage there and starting 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, so. But as you're doing that, you have to make sure that you know what you're - what the playing field is. And the playing field is that we have laid a lot of infrastructure at Hackberry Draw. Everything we drilled so far, most have been one-off wells, but they're all - we built big pads everywhere. And we're just now, as Jon 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's 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 drill co ideas down there and 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 shlug of money in would be very attractive to us and to others. But we have to do it in a workman-like manner.

Our next question comes from the line of Tarek Hamid from JPMorgan.

This is actually Kevin on for Tarek. I just wanted to look at the G&A quarter-over-quarter. I just noticed there was a slight uptick. And I think part of it was on some embedded cost. So I just want to see if - in 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 1 item come through G&A expense. It's been backed out as a nonrecurring item in the press release. And it's just related to a legal matter that's been ongoing, and we filed this one ahead and accrued a little cost associated with it.

Okay. Is that sort of something that is expected to be recurring? Or...

No, no, no. It's not recurring at all.

Okay. All right. And I'm just curious to know that on takeaway options for Hackberry Draw, I know it's a little bit early days, but I just want to see how some of those conversations have been going with some of those operators in sort of late '19 time frame?

Jon, do you have a comment on that? We do have a contract that matures in - or Steve maybe?

Well, 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.

We have a situation with contractors maturing to get - oil contractors 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 about marketing and takeaway options.

Okay. I appreciate that color. And then my last one is just back to some like gas treating issues that you guys had. I just want to see more broadly, are there any other areas that could potentially be an issue as well? Or is this kind of isolated to 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. And 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 line, 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 - a 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 eightball, so to speak. So we're continuing to build that infrastructure ourselves as quickly as we can. And as you might know in that Slide 30, there's the most expensive thing as what we've been doing in the third quarter. 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 in NIM. And then getting down to less than $1 NIM by the second half of '19. 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 a - 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 the length of the life of the wells.

Our next question comes from the line of Chris Brett [ph] from ART Capital.

All right. Two specific questions for you. Number one, what are your current water-to-oil ratios? if you can just tell me across you base and across the whole footprint 2018. I didn't see it broken out in the supplemental information. And what are you projecting your water-to-oil ratios for '19?

You know Jon 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, Jon.

So the water-oil ratios differs as you move across the basin. We're seeing at Hackberry Draw - that's generally where we have our highest water-oil ratios. I mean, if you're including our actual frac load, reaching as high as 8, but that's after frac load has recovered, it would be more in that 5.5 to 6.5 range as 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 at about 4.5 to 5.5. That seems to be about the basin's average overall. And when you move further to the East in Ward County, where our 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 1:1 average. So it varies across each one of our assets. Obviously, as you go across the basin closer to the platform, it seems like those water-oil ratios really trail along.

As you go up the basin, those water-oil ratios really what?

Well, as you move towards the Central Basin Platform, so we're talking about going from West Quito, where we're probably more closer to the basin average. Our wells in Monument Draw, which are in Eastern Ward County are about 2:1 average on overall. We're seeing wells that are about 1:1 average as well.

Okay. I'll try and follow up with you. I'm just trying to get - you're giving a sense of direction, and I'm just trying to get the specifics clear. Are you saying as you move east, you're seeing your WRO - WOR 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 Jon said that they're, after frac, they're about 6:1 in Hackberry Draw, they're about 5:1 at West Quito and about 2:1 at Monument Draw. And those are fairly stable numbers to use for modeling purposes.

Perfect. And then my follow up is - and thanks for giving me clarity on this. Currently, how tight are your formations? And do you guys have any EOR processes in place? I'm just trying to again understand what you're asset base looks like, how tight it is. Just I'm trying to get a better feel for what your water usage is currently. And then clearly, you guys have enough capacity in your lines to double it, given that you initially got a - what was it? You guys just mentioned it. The pipeline that's coming out there, you've got 25,000 barrels per day growth, increasing the pace 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 in so far as your cost curve to get to that 25,000 takeaway. So if you are successful in the next year, what your water cost look like when you get to that success, given the transaction you just did?

Yes. We've modeled the water cost into the numbers that we've provided in the slide deck. The shale formations are tighter than heck. I mean, you go from 2%, 3% or 4%. Sometimes 10%, roughly, I guess. I don't know. Jon, is that close?

Yes. That's in the range of outcomes, Floyd.

Yes. And 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 other basins and beginning to think about in this basin. But they're certainly not on the - they're not high up on our lists 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.

Our next question comes from the line of Vivek Pal from Seaport.

Floyd, how much have you spent on the oil and gas midstream business so far? I'm just trying 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 like $25 million expenditure in fourth quarter, is that a good run rate? Can we analyze that?

Well, there is no run rate. But I can tell you that I think through the quarter, we spend about $175 million, $180 million on both oil, 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 the 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 a lot of the CapEx is going to be associated with these build-outs, associated with slide 30 in the deck of getting from a very high treating costs to a very low treating costs for sour gas. And we haven't guided for that spend in 2019 yet. Do we have a number for the fourth quarter of '18 in the deck here? Is there a number for that in here?

I thought you had mentioned $25 million for infrastructure spend in fourth quarter? Maybe I misunderstood it.

That's right. It's $20 million to $30 million next year - or in fourth quarter this year.

Yes.

That is part of the $85 million you're going to spend, right? Or that is in addition to $85 million CapEx that you mentioned for fourth quarter?

Yes.

So that's in addition to $85 million or part of $85 million?

No, it's in addition. The $85 million is our drilling and completion capital spend. There's another $20 million to $30 million in infrastructure, primarily related to the build-out of our gas infrastructure at Monument Draw for this H2S area.

And do you break down how much EBITDA from the gathering business - I'm sorry, the midstream business in E&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 asset?

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. As I mentioned earlier in this call, we expect the EBITDA - 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 - can you get full $125 million? Or you can get partial? I know you would like to get the full. But is it like a binary outcome? Or you can be somewhere in the middle?

It will be somewhere - the goalpost will be somewhere in the middle towards the high end. Our goal would be to get all of it, but that's strictly is a product of rig count. And then if you do anything else, if you add rigs or drill coals 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 '19 and to be reasonable in '19 but not - we probably wouldn't get it all in '19.

Right. And the drill co you're talking about is in Hackberry, right?

I didn't say that.

Ladies and gentlemen, we have reached the end of the question-and-answer session. I now would like to turn the call back to management for closing remarks.

Thanks, everybody. I think this is a fairly complete dataset. 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.