Battalion Oil Corporation (BATL) Q4 2017 Earnings Report, Transcript and Summary

Good day, and welcome to the Halcón Resources Fourth Quarter 2017 Earnings Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Mark Mize, EVP, CFO and Treasurer. Please go ahead, sir. Mark J. Mize - Halcón Resources Corp.: Okay. Thank you. 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 fourth quarter and other operational items and that document has also been posted on our website. I'll begin the call with comments on our financial performance during the fourth quarter, and then, I'll turn the call over to Floyd. Production for the fourth quarter averaged 6,283 barrels of oil equivalent per day, comprised of 70% oil. This production rate is consistent with the update we provided a few weeks ago when we announced our West Quito Draw acquisition and related financings. We expect production to grow significantly in the first quarter 2018 and Floyd will comment on that in a few minutes. Our realized fourth quarter oil differential of 95% of NYMEX was better than the 91% differential seen in the third quarter, largely driven by our production shift into the Delaware from the Williston. Our fourth quarter natural gas differential came in at 71% in NYMEX and the NGL differential for the fourth quarter came in at 47%. Looking forward to 2018, we expect differentials to be relatively consistent with those seen in the fourth quarter. Our per operating unit costs were elevated in the fourth quarter versus prior quarters, primarily because of the divested production associated with our Williston Basin operated asset sale, which did close in early September of 2017. I wanted to quickly highlight a few expense line items that include significant non-recurring items in the fourth quarter. First, our gathering, transportation and other line item included approximately $1 million in rig stacking charges, which will be eliminated in the mid to latter part of 2018. Additionally, we incurred about $1 million in contract labor in the fourth quarter in gathering, transportation and other related to operating our water and infrastructure assets. Many of those contract positions have now either been eliminated or absorbed and brought in-house. We also had approximately $7 million in non-recurring charges associated with G&A during the fourth quarter. And these non-recurring items included various professional fees associated with some divestiture activity as well as tax service fees, which by the way generate a significant AMT cash tax savings above and beyond the fees incurred. And finally, there were some one-time severance cost, relocation cost included as well. We'll provide formal revised 2018 expense guidance including the impact of the West Quito Draw acquisition after the deal closes in the second quarter. Having said this, we expect our per unit field operating cost on our existing assets to be in line and within the ranges of 2018 guidance that we provided in November of 2017. With respect to D&C CapEx, we incurred right at $94 million during the fourth quarter. This included additional costs associated with running three frac crews late in the quarter in addition to general cost inflation that we had recently experienced. We also spent another $37 million in the fourth quarter on infrastructure and seismic. These dollars were invested in the infrastructure development in Monument Draw and Hackberry Draw where we've accelerated the development of our water infrastructure and gathering assets. We expect 2018 D&C CapEx, excluding the impact of the West Quito acquisition and assuming a three-rig program, to be 10% to 15% higher than the previous guidance range of $280 million to $320 million and that's really driven by service cost inflation. Regarding acreage deals, we did spend $104 million in the fourth quarter on the acquisition of 4,413 net acres adjacent to our Monument Draw position. And in January, we paid for the exercise of our option on the Monument Draw North acreage which was $108 million. As far as hedging goes, we realized the net gain on settled derivative contracts of just under $1 million during the fourth quarter of 2017. For 2018, we currently have 9,510 barrels a day of oil hedged at an average price of $52.65 a barrel. We also have 8,247 barrels per day of oil hedged in 2019 at an average price of $54.41. On the gas side of the equation, we currently have 7,500 MMBtu a day of gas hedged in 2018 at $3.16. And as usual, we'll continue to watch the markets and layer in 2019 positions as opportunities present themselves. Finally, as of December 31, 2017, a pro forma for the exercise of our Northern Ward County acreage option and our February debt and equity raises, we had $678 million of liquidity, which consists of $580 million of cash plus a fully undrawn $100 million availability of revolver on the RBL. Our next borrowing base redetermination is scheduled for May of 2018. And we do expect strong growth in the RBL going forward with each redetermination. We are currently sitting with a very strong current and projected leverage and liquidity position, which will allow us to execute our growth plans in the Delaware Basin over the next several years. We do not have any needs under our current business plan that would require raising outside capital. And with that, I'll turn the call over to Floyd. Floyd C. Wilson - Halcón Resources Corp.: Thanks Mark. Good morning. Thanks for listening today. We find ourselves in an interesting place today. Our recent wells are beating our type curves. We're approaching 13,000 barrel of oil equivalent per day, up from just over 6,000 barrel of oil equivalent per day average for the fourth quarter. Our very most recent well hit 1,925 barrel of oil equivalent per day this morning and it's still cleaning up and it's over 85% oil, and our stacks are getting roasted. So it is an interesting point that we find ourselves at today. We've announced a couple of recent acquisitions here a couple of weeks ago in Ward County, our West Quito Draw acquisition is set to close in the second quarter. It's in a very active area of the Delaware Basin and we acquired it at a very attractive price. Recent results from offset operators have been excellent in that area, as you may or may not know. We'll take a rig out there after we close early May maybe. We'll concentrate on 10,000 foot laterals as we do in all of our areas. We added some land to our Monument Draw area, we called it a Tack-On, it was a slam dunk for us, it's adjacent to existing operations and infrastructure. The Wolfcamp is deeper and thicker there. And it offsets our most recently completed well at SR5902H that I mentioned that's approaching 2,000 Boe per day. At Monument Draw, with this press release, we announced three new wells, on the 79 pad the 02 and 03 wells. These are Wolfcamp wells, our best wells to-date, say, the brand new one that I mentioned earlier. Those two wells, IP 24 averaged 1,817 Boe per day and they're still cleaning up. These look to – these are ahead of our type curve in that area and they look to stay ahead. There are also great 660-foot spacing tests. So, we're zeroing in on spacing, and we're thinking that we're about to the right spot there. This asset is a world-class asset with multi-target zones, high oil cut, strong IP rates and low declines. Down in Pecos County at Hackberry Draw, we reported two new wells, the Jose Katie Wolfcamp wells. These are some of the best wells we've drilled at Hackberry. Initial IP rates are well above type curve estimates. These two wells averaged 1,341 Boe per day on an IP 24 basis. And as a sidelight, the 20-day rate on these – these are new wells, the 20-day rate was 1,071 on average for these two wells, 86% oil. Our type curve provides for a 940 Boe per day, 30-day rate. So, these are comparing very favorably with our type curves. Also, great 660-foot spacing test here. A well we reported on earlier, the Lindsey 1H. We previously reported it at an IP rate of 1,164. After 45 days online, we put it on an ESP and it's up to 1,250 Boe per day and still climbing. So, the takeaways, the two areas, capital efficiency is somewhat better in Monument Draw than Hackberry. It's very good at Hackberry as well. Hackberry itself, the IP rates are slightly less than we might have initially thought. The decline rates are also less than we thought, meaning that the wells declined more slowly. High water cuts particularly in Pecos County at Hackberry Draw, make fluid movement or water management critical to a well's effectiveness, also makes – of course, the water handling and infrastructure is critical to eventual success. Jet pumps and ESPs are needed sooner than some other areas of the basin and certainly sooner than Monument Draw. And as we've mentioned, all of these wells are reaching new IP maximum after being put on artificial lift. In our investor deck on the website that we posted today, we included a comparison of the well performance of over 25 wells in the Hackberry Draw acreage versus the type curve that we posted. And this goes out to 600 days with the longest history that we have down there. Our wells and those of the existing wells when we acquired the property are right in line with our current Hackberry Draw type curve. Frac efficiencies or frac effectiveness continues to improve here as seen by the increased productivity. Our last three or four wells, we do a lot of diagnostic work as we frac wells with tracer surveys and whatnot, micro seismic and everything, so we're quite happy with our results down here, generating strong returns at the strip. We would expect this performance to continue to improve over time and with the additional experience. There's also a lot of rig activity from offset operators in Pecos County. In a general sense, for rigs and how we plan the year, we're going to run three rigs in 2018. We may add a fourth rig in the second quarter if oil prices are strong and after we actually own West Quito Draw, which will close early in April. We have shifted our focus slightly more towards Monument Draw just based on capital efficiency. So, we'll drill more wells there than we will in at Hackberry Draw. We also plan to drill for half a year at West Quito Draw in 2018, assuming that we bring that fourth rig out, and that should compete favorably or perhaps even better than the capital efficiency at Monument Draw. We have high hopes for that area. So that's our comment on focus. We've had some – it's not a runaway, but it's certainly cost inflation – significant cost inflation recently. And over the past year, we've seen this every time there's been a major movement in crude prices for decades. Costs go way down when rigs slow down. They're slow coming up and they zoom up and things have to get revised. We've seen 10% to 15% cost inflation just recently. We'll put out revised guidance in the next few months once we close on West Quito and have a firm handle on our rig count for the year. We're very cognizant of these costs and we're doing everything we can to hold the line there. Permian Basin in general and Delaware Basin specifically, very competitive for services right now, more so than most other basins. So, the rig count has zoomed up out there. Personnel and services are scarce. It's just the way of a boom play and it is a boom out there, by the way. We'll test some new targets across all of our position in 2018. We've already had some Bone Spring tests drilled that we've reported on, we'll drill a few more this year. We may tag a couple of deep prospects later in the year. We're doing spacing test everywhere, and so far it looks like 660-foot with a wine rack or chevron style zone development like A versus B versus Bone Springs will be an effective spacing arrangement. And we feel pretty good about that. We're seeing that our frac jobs are being contained nicely in the way that we hoped that they would be. As mentioned on the A&D side of things we've added some acreage over the past few months. We're up over 60,000 acres. That's been our goal all along. We'll continue to look at small deals, bolt-on as I would call them, they make sense. They're usually less expensive and they fit well for existing operations and infrastructure, don't require any extra personnel. Larger acquisitions are not on our radar screen at this moment. Our focus over the next several months will be to grow production and EBITDA, continue to refine our drilling and completion techniques. They're very good now. I think we can improve. Reduce drilling days, keep working on our frac jobs, keep working the cost side of our business, get drilling at West Quito and stay well ahead of water and other infrastructure requirements in these areas. It's critical to be able to do that. So, I think with those comments, Katrina, we can take some questions if there are any.

Thank you. And our first question comes from Asit Sen, Bank of America Merrill Lynch. Please go ahead.

Thanks. Good morning, all. I was wondering if I could ask two questions. First on this likely lower oil cut this quarter, what would the specific drivers and what should we – how should we think about oil cut in 2018? Floyd C. Wilson - Halcón Resources Corp.: Well, I can say that all of our new wells are cut – all of the new wells are higher oil cut than what we've experienced in the past quarter. We were a little bit low, but I think that's just a mathematical thing that occurred during the quarter. All of our recent wells are cutting well over 80%, some of them over 85%. So, I don't think the lower oil cut is anything to – that we'll see continuing.

Understood. Fine. And then regarding the comment on the addition of a fourth rig and I appreciate the close of West Quito, what do you need to see to, say, accelerate or defer the timing? In other words, how you're thinking about incremental CapEx in 2018 on that front? Floyd C. Wilson - Halcón Resources Corp.: Well, we're looking for that balance where a rig can pay for itself, and that's in the mid-60s as you know, roughly. We're not there yet. If prices continue to go down, we'll defer that rig. If prices firm up and go up a bit, we'll bring a rig in. We just – we can stay fluid on that decision. Our growth plans as we've outlined are not tied to additional rigs. Additional rigs would change that, both the CapEx scenario and our production projections and EBITDA calculations. So, it's all dependent on a reasonably good, stable outlook for crude oil, which we've kind of had over the past month or so but not the past few days. We'll take our signal from....

Understood. And what... Floyd C. Wilson - Halcón Resources Corp.: ...from crude price. If they're bad, we won't bring a rig. If they're good, we will.

It looks like $60 to $65 is the magic number? Floyd C. Wilson - Halcón Resources Corp.: Actually, we'd like to see it better than $60.

Got you. And last one for me. Floyd, what's your current DUC count and how should we think about the normalized level, and at what point would you consider adding a spot crew? Floyd C. Wilson - Halcón Resources Corp.: Current – did you say debt level?

DUC count. Floyd C. Wilson - Halcón Resources Corp.: DUC. DUCs?

Yeah. Floyd C. Wilson - Halcón Resources Corp.: We have – we caught up. That's one reason CapEx was a little higher last quarter. We brought in two spot crews last quarter. We're caught up. I think we might have one or two wells that aren't fracked just yet just by circumstances. We don't really have an inventory of DUCs, and we don't plan to take a – build a big inventory. One frac fleet will almost service three rigs, so we require an additional spot crew periodically for about, I'd say, about a third of a year for one crew if you're running three rigs. And we've got those outlined in our plans during the year if we do build up our inventory of uncompleted wells.

Great. Thanks, Floyd.

And our next question is Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning. Floyd, on slide 5, it says that HK is more attractive to a buyer, significant inventory of high-return drilling locations. Is selling HK your preferred outcome at this time, or how does that fit into your positioning of the company? Floyd C. Wilson - Halcón Resources Corp.: Well, look, Jeff, we never wavered over five, four public companies and several private companies over the years. I think as you grow a large inventory of future value that you can't access, the assets are best served and the investors are best served by trying to trade those assets into a larger capital structure with, perhaps, cheaper cost of capital. So, we're not at that juncture right now. I have to suggest that I didn't pay attention to that box on slide 5, which I'm looking at. In general, in our business, the high inventory of high-return drilling locations is attractive to a company whether you're operating the company or selling it. And so that's – our goal is to continue to build that well-defined, well-delineated inventory of quality locations that don't have geologic risk, don't have execution risk and that's what we're about. We're not at the point of talking about selling the company today by any means.

Okay. Well – and your track record speaks for itself. So that's one of the reasons that it was interesting to ask. And speaking of inventory, on slide 6, you note a three-zone base case for the Monument Draw Tack-On, but you only show a two-zone base case for the Monument Draw East. So, I was just wondering which zone is it that's not being included in Monument Draw East base case? Floyd C. Wilson - Halcón Resources Corp.: We have a different approach to these things, Jeff, or we have our own approach, let me say. We don't count zones unless we're 100% confident that they're there and they're prevalent across the entire acreage area that we're counting them. So, we don't have a test in another zone up on the north side of that acreage yet. We will. And so, what we've got up there, we've got one Wolfcamp zone and one Bone Spring and we have two Wolfcamp and one Bone down to the south. I have to tell you that recent work (22:55) south, we'll probably have three Wolfcamp landing zones and perhaps two Bone Springs. But we don't – listen, all that – those zones that we – as you count on, there's – so far in the future the PV of those is not so much. So, it's our job to delineate those on both a reasonable engineering basis and on a spacing basis that makes some sense, where you're not wasting a lot of money getting the same reserves. So, we're somewhat conservative in the way we count those zones. I would suspect that the western part of all the north acreage will have more landing zones than what we've specified, and the eastern part will have the two. But, we just haven't drilled enough. I think we've only drilled maybe 10 or 12 wells at Monument Draw so far, maybe 13 or something with half of them being online now, so it's early days. It's a lot of zones though. Think about three zones, 660 spacing, that's 24 wells. I mean, gosh, that's more than one rigs out. That's almost two rigs out but for a whole year, right, in (24:11) one 10,000-foot spacing unit. So, it's a lot of places to drill for sure.

Yeah. There's no question about that. Let me ask one final question. On slide 16, looking at the EUR, it seems to suggest that the West Quito Draw is considerably gassier than your other acreage. I was just wondering if you have any concerns about getting that gas to market over the next year or two because we know that the Southern Delaware Basin, that gas production is going to increase considerably over that time period (24:44). Floyd C. Wilson - Halcón Resources Corp.: Do we have the slide about the oil? The three bars, where is that? So, just as a companion piece to that, look on slide 19. And a point being made there is that all of these areas make up a significant amount of oil including West Quito, and we're probably conservative there. This chart was drawn based on our acquisition economics, which – rather than any historical economics. The other charts are drawn on some limited history but good histories. So, the point being that over at West Quito, we'll make a lot of oil over 1 million barrels per well of just oil – crude oil, maybe 1.25 million. But the gas is a higher gas cut over there. So maybe only half oil higher liquids. So, absolutely, yes. In future, we expect there to be issues with gas. The good news is we've – there's an arrangement at West Quito already for the gas takeaway, and it's significant. It's got a lot of horsepower behind it. So, this entire part of the Permian Basin is going to be challenged with gas takeaway over time. Like all of our infrastructure concerns, we try to tackle those things quite early. And not just gas, by the way, crude takeaway, WAHA differentials, all these things, we're looking at these all the time. So, we think we're good on gas for the moment. We've got long-term arrangements in all three areas now, so that we think we'll be ahead of the game somewhat. But it's a powder keg out here in terms of rig count and new wells coming on. It's just growing almost exponentially last year and this – next year. We're also doing some hedging out here to protect bases. We hedge – we're hedging WAHA, the WAHA differentials so as to protect that price. But that doesn't really address the actual takeaway, and the physical takeaway is a concern, I think, for the entire industry.

Great. Thanks. I appreciate all of that color.

And we'll take our next question from Jason Wangler with Imperial Capital. Please go ahead.

Good morning. You've touched on it a bit, Floyd, but I was just curious with the three-rig program, and it sounds like you're going to focus mostly on Monument Draw. Will that basically keep that completion crew busy there, or will you be able to just kind of move that one out to Hackberry or even West Quito as you see fit and just be able to use the one crew throughout the year? Floyd C. Wilson - Halcón Resources Corp.: There's a map early in this, and you can see that these are not very distant from each other. So, once you move off of the pad, it doesn't matter that much if you're moving 1 mile or 20. So, that the dedicated frac fleet is quite mobile around all three areas. So, as I mentioned earlier, it will service wells that we have drilled in any of these areas, and then, we're bringing on a spot crew as necessary throughout the year. I don't think we're planning on needing one before the third quarter and maybe only one this year, but it could also be in any of these areas. We'll have fewer wells put online than we anticipated early, last year in Hackberry. So you'd expect to see the frac fleet down there a little less and a little more at Monument Draw, and then, West Quito not starting drilling. And so, whether we add a rig or not, we'll start drilling at West Quito this year. So you'd expect to see a frac fleet out there July, something like that once we get started drilling maybe perhaps in May.

Okay. And just as a follow-up on Hackberry Draw, it did seem like the recent wells that you kind of gave us were looking better than the original wells that you gave only about a month ago. Was there anything you think you guys did differently or were you able to refine that specifically that help that or is it just simply that we're just getting some more data from the formation? Floyd C. Wilson - Halcón Resources Corp.: Listen, a lot of it is just more data, a kind of like our – the way we count locations, our type curves are not meant to be promotional in nature. They're meant to be factual. They're not drawn by some financial guys. They're drawn by engineers, and they're based on history. So you would expect, as in every basin in the entire shale world, which is basically the United States for the most part right now, you would expect results to continue to improve. Sometimes, it's just such a small matter of pump rates or proppant size or – and we're constantly reviewing all of our history on every single aspect of how we complete these wells and how we target them. So we would expect to improve upon this year's wells. We would expect in general to be better than last year's wells. And frankly, I probably expect 2019 wells to be better than 2018 wells.

I appreciate it. I'll turn it back.

And our next question is from Philip Stuart with Scotia Howard Weil. Please go ahead.

Good morning, guys. I wondered if we could circle back on the expense side that seems to be causing some investor concern this morning from people that I have talked to. Just wondering if you could kind of maybe go into more detail on perhaps some one-time things that happened in 4Q 2017 that caused gathering and transportation and possibly LOE to be a little bit higher than expectations, and just kind of trying to give people comfort and being able to be within the guided expense range throughout 2018? Floyd C. Wilson - Halcón Resources Corp.: I'll let Mark give you an answer. I will say that some of our activity in the fourth quarter of last year was driven by bringing in a spot frac fleet, but listen, costs are higher than they were. They just increased the lot during that quarter and it's unfortunate, but it just did. In terms of comfort, I would like to suggest that we'll drill the best well at a reasonable cost structure as anybody in the business will and that our returns will be acceptable. Mark, do you have any details on all this? Mark J. Mize - Halcón Resources Corp.: Yeah. I mean it really is pretty simple and I'll just take each one of the items, the two that you mentioned, and I'll just touch on G&A again as well. So gathering, transportation and other, the kind of inflation that we had in Q4 really was just driven by contract labor. Some of the work that we were having done out there was being performed by third parties that we brought in, and we have now gotten organized out there for most of that has been eliminated at this point and a lot of those is just absorbed in-house. So as Floyd just mentioned, and as I had mentioned in the opening comments, we absolutely do expect to be within the ranges that we gave for guidance for 2018. On LOE, that really is at an operating per barrel basis that really is driven by the production that was divested of, and again, 2018, we expect to be right in line, right down the fairway of where we projected. And then, G&A probably had the largest number of non-recurring type activity that did range from a fee paid for the non-upsell at Bakken to some tax services that were rendered, to relocation fees, and just things of that nature that will not be ongoing into 2018.

Okay, I really appreciate the color there. I think that kind of answers my question. And just curious if you could give us an idea of how that will trend, I guess, on the expense side. Will it be kind of towards the higher end of the guidance range during the beginning of 2018 in general, and then, trend lower throughout the year or will it be kind of even within the guidance range kind of – across the different line items? Mark J. Mize - Halcón Resources Corp.: G&A, we've really made some very significant adjustments as is evidenced here despite what you're seeing flow through, some of the severance payments and things of that nature. G&A is going to be kind of in a $45-million type range and kind of right down the fairway throughout 2018. Gathering, transportation and other, again, should be in the range, but will probably trend towards the higher end of that range. And LOE should just be – as production continues to ramp dramatically, you're going to see it actually coming down as we go through Q4 of 2018.

All right. That's it for me. I really appreciate you answering my questions. Mark J. Mize - Halcón Resources Corp.: Thank you.

And our next question is from Mike Kelly with Seaport Global. Please go ahead.

Hi, guys. Good morning. Mark, I've got a couple of questions for you. You mentioned in your prepared remarks CapEx adjustment for 2018. I was hoping you could repeat that, maybe give a little bit more color on some of the things that play there. Especially interested if you could give us a sense of what CapEx could look like if you do go to a four-rig program. And then, finally, you mentioned that leverage metrics would stay strong as you move throughout 2018. I was hoping you might be able to give us what you're modeling for kind of year-end net debt to EBITDA for 2018. Thanks. Mark J. Mize - Halcón Resources Corp.: Okay. As far as CapEx, the comment that I had made is we had previously put out guidance of $280 million to $320 million. And we – I just made the comment that you can probably expect about a 10% to 15% higher and that's based on the three-rig program, and that really is just driven by a service cost inflation. As far as leverage, we don't really put exact... Floyd C. Wilson - Halcón Resources Corp.: Trend. Mark J. Mize - Halcón Resources Corp.: Yeah, we don't really put exact amounts out there. I will tell you though, from a trend perspective, it will continue to walk down as we go through 2018, and it will be at a very – I mean, a very attractive level, well below three times by the time we get to the end of the year.

Okay. Good to hear. Infrastructure spend, what should we – I think previous guidance was like 30% to 40% or – not percent, $30 million to $40 million. Is that still a decent number? Is that – it seems like that might tick higher too? Mark J. Mize - Halcón Resources Corp.: Yeah. We're kind of talking internally, $35 million to $45 million.

Okay. Okay. Good. Thanks. And if I switch over operationally, this well you guys drilled in Eastern Monument Draw looks really, really encouraging. And just wanted to get a sense, Floyd, how much of a read we could take from this well to the rest of that Eastern Option Acreage. I know just kind of the Western portion of the play, but like this is – it tells you everything is good here or is there more work to do? Floyd C. Wilson - Halcón Resources Corp.: Well, what it does, it tells us that there's some great rock to be accessed up towards the platform. And while thinner, it's high quality. What it really does though, it 100% proves everything up to the West and South, so there's no question of anything over there. So we're still going to have to feel our way eastwards if we choose to. But it's – look, a pilot well, you don't see as many of them as our industry probably should be drilling, and that's another thing that runs our cost up a little bit. I think we've drilled three pilot wells in 2017, maybe four, but at least three. And to do a good job with that, you drill them deep, you log everything and half the time you don't even whipstock that. You might say that for a disposal well or a supply well, for future deep test and you just move over and drill a new well after that, and that runs the cost up. What this really does, it highlights that all of the acreage from at least a little bit east of this to all the way west of ours is really in great shape. And again, the idea of the way that Steve was able to craft the options out here in Eastern Ward County have been spectacular and a real thoughtful way for us to approach getting into a new area of the field. So we're ecstatic over results here. Not just there by the way, we reported that Section 79 pad, the 02 and 03 wells that I think over 1,800 bopd IPs and even after 20 or 30 days, they're quite strong still. So geologically and execution wise, things are looking wonderful over it. It's a great asset.

Great. I appreciate that. Just a quick follow-up on that. I mean, do you see the geologic attributes changing much from that well you just put online, as you move further east toward the platform is your big delta between far east and far west? Thanks. Floyd C. Wilson - Halcón Resources Corp.: Yes. Yes. There certainly is. It clearly thins as you go east. It doesn't disappear, but the more east you go, you get more of these intrusions of carbonates, carbonate flows as we might call them. And those are not good territory for frac jobs. So you have to sort of feel your way, as you know you're approaching basically a drilling hazard, not a fault, but a formation hazard that would say this is not a good frac environment. So yeah, it definitely thins and it gets less clean shale as you go eastwards. Now, where the cut-off of that is? We don't have that exactly, but as I say, it's just as important for us from the results of this pilot well, they've totally cemented in our minds everything west and our entire south area that we just added this past quarter, we had quite a few sections over there. So as you go look at the platform, it kind of meanders its way eastward as you're going south. So making that a good area for production plateau a little bit to the east as you go south, so it really helps us as we're thinking about how many locations we have to drill and so on. And by the way, you didn't ask this, but when you get a more thinner zone, it's a great almost an engineering thing to consider that if you get a really wonderful completion in a zone that's only a couple of hundred-feet thick, to find out that you're doing a better job of accessing the crude near to your wellbore, to your frac job, which means higher recovery. So we would expect to get a much higher recovery in the primary producing conditions from this zone than we might get in a zone that's much thicker. So it gives us a lot of information in all different areas and it's pretty exciting.

Got it. Appreciate, guys. Thank you.

And we'll take our next question from Ron Mills with Johnson Rice & Company. Please go ahead. Ronald E. Mills - Johnson Rice & Co. LLC: Hey. Good morning. Floyd, just a few clarifications from earlier questions. When you talked about the $65 oil price to self-fund a rig, what is the anticipated timeframe to have that oil price self-funding rig given the lag time between starting the program and getting the production? Floyd C. Wilson - Halcón Resources Corp.: Okay, Ron. That's kind of a half-assed thing that I like to say. If the strip held and if cost held in the mid-60s, a rig would take care of itself in the 12-month period. In other words, your EBITDA would be nearly equivalent to your CapEx that that rig would engender which should be $130 million, $140 million in a year's time or maybe a little bit less we hope. So that's just sort of a – it's a directional thing. So if prices are trending better, it's costing you less and less to add a rig than it does if prices are trending lower, meaning that while your CapEx spend goes up, you're getting a nice boost in EBITDA whereas at the other direction, a few sad (43:15) rigs and prices are falling – crude prices are falling, you're working the wrong side of that equation. So my comment... Ronald E. Mills - Johnson Rice & Co. LLC: Yeah. Floyd C. Wilson - Halcón Resources Corp.: ...on that line was more directional in nature. And we're not there, by the way, and costs are not flat. Costs are not at all better in that (43:35). Ronald E. Mills - Johnson Rice & Co. LLC: Given where we are on oil prices, when you think about West Quito in drilling there, if oil prices stayed closer to these levels, would one of the options be to take one of your current three rigs, drill some at West Quito and take it back rather than adding a fourth rig? Floyd C. Wilson - Halcón Resources Corp.: That's absolutely what we'd do. And again, it's the same as frac fleets. If you move up a pad, it doesn't matter if you move in 1 mile or 20, right, on a rig. I mean, it matters a bit, but if you get off the pad where you're not walking the rig or dragging it, you're – we absolutely would and probably will put one of the existing rigs over on West Quito. If we add a rig, it makes it an easier thing to separate. But if we don't, we'll just divide our rigs. And again, they'll be heavily weighted towards the Monument Draw, and we'll get our first few operated wells under our belt at West Quito to make sure that our expectations are met. Those expectations are to make over 1 million barrels of crude with the well over there along with quite a bit of gas and natural gas liquids. So I mean the numbers are there. All the offset operators have done that sort of thing. We'd like to prove it to ourselves first, but yeah, option would totally be to rotate around our acreage with just the three rigs that we currently have, if prices are not cooperative. If prices are dropping, we won't add a rig. Ronald E. Mills - Johnson Rice & Co. LLC: Got it. And then, to follow up on Mike's prior question on the Eastern Option Acreage, the 1,593 Boe/d well was drilled, it looks like more on the western edge of that section. But given that option acreages only extending 1 mile to the east, do you have any incremental color on just that 1 mile to the east of additions or are you talking more about a greater risk as you move even further east than that East Option Acreage? Floyd C. Wilson - Halcón Resources Corp.: Well, unfortunately, our business, as you get around the edge of a shale field, you begin to have geologic risk and we try to set ourselves up where the geologic risk is minimal. There's more than one section involved, as you know, if you look at the maps. Yes, there's significantly more risk the further east that you go and if you get down to the office sometime, I'd like to show you the shuttle log on that well. I think we've got it in the presentation we did, but we stretched it out for you, you can really see. It's really strange that we can see that the zone gets thinner, and there's a little more indication of carbonate flow, but it's an awesome well. So that means the frac job was really contained extremely well as you try to get all frac jobs contained. So we don't have to – that thing is exercisable up until the 31st of May. We'll make our – March, I mean, we'll make our determination as time goes. But it's a great well. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. And can you just – on the water infrastructure side, you've made it a point and is evidenced during the field trip of the infrastructure spending particularly on the water side, but also just all the infrastructure at Monument Draw, is there something similar planned for West Quito or were some of those systems already in place given Shell's footprint there? Floyd C. Wilson - Halcón Resources Corp.: I think Jon is on the line. Jon, you've been out there personally. I haven't been there yet, but why don't you make a few comments about your plans for infrastructure and takeaway at West Quito? Jon C. Wright - Halcón Resources Corp.: Sure. Thanks, Floyd. Ron, for the Shell acreage position, we'll be installing our own water system. So similar to what you saw on the field trip, our standard recycling facilities, SWDs will have main trunk lines for water handling for both produced water and recycling water. We'll be laying in our own power grid, so we'll provide our own access Texas-New Mexico anchor (48:06), but we'll be laying in our own power across the acreage position. We'll make some determinations as we move forward on the oil side. The gas is dedicated and gas is sold at the lease site. So we won't be handling gas in a type of central production facility or we'd be required to gather our own gas. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Great. Jon C. Wright - Halcón Resources Corp.: That's it. Ronald E. Mills - Johnson Rice & Co. LLC: And then, maybe, Jon, since you're on, can you provide any incremental comments on the slideshow and the type curve at Hackberry Draw in terms of your wells versus the 25 legacy wells and that relatively stronger performance given a change in artificial lift design just to provide a little bit more support for that newer type curve? Floyd C. Wilson - Halcón Resources Corp.: That's slide 18, Jon, if you don't have it. Jon C. Wright - Halcón Resources Corp.: Yeah, thanks. I've got it here, Floyd. Yes. So the legacy well is about 20 Wolfcamp A-type wells with over 600 days of production gives us a pretty good handle on this type curve matching the production performance. With regard to our HK drilled and completed wells, which are showing up to 200 days at this point, we're performing above the type curve overall. A lot of the more recent wells further support this. Our focus there is optimization of artificial lift. This is really the blocking and tackling piece, and this is where we ought to make big inroads in the PDP base for those legacy wells this past year where we're able to increase that production on those PDP wells by range of 60% and the EURs on those individual wells up to 40% on average. So a lot of work going on there. We've had a lot of success with the ESPs. We'll be running jet pumps this year. We've got experience that we bring from the Bakken with that type of lift technique. So yeah, a lot of good things are happening in Hackberry Draw. I think that slide 18 really supports our type curve and the decline rates that you see there to 600 days. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Great. Thank you for the incremental color.

And our next question is from John White with ROTH Capital. Please go ahead.

Good morning, guys. I believe you mentioned very briefly the possibility of a deeper test maybe later in the year. I think you've talked about this before, and as I recall, it's a conventional reservoir. If that's what you're talking about, can you give us the basics of that again? Floyd C. Wilson - Halcón Resources Corp.: John, there's two distinct deep plays on our acreage in our analysis. At Hackberry, it's a deeper Wolfcamp zone that's a conventional, it's a sand. We've done a lot of work on this and it's pretty exciting. It's a pretty gassy zone, but very prolific with quite a bit of crude oil we think. It's been drilled historically with vertical wells. We think that you could drill a horizontal well in it and perhaps do quite well. It's kind of a channel system of Wolfcamp Sands down at about maybe only another 1,000 or 1,500 feet deeper than where we are. So we're going to drill at least a pilot well down through there. And if we find what we think we find, we go ahead and complete it there, full well knowing that we could use that wellbore for something else. Now, that is a conventional reservoir. And we were very interested in that, because it would just add a new play, another play to much of that acreage. Over at Monument, it's a different cat. It's a Woodford shale and it has been drilled in the past and drilled through and it's just drilled vertically. And in fact, recently, one of our good peer companies has drilled a short lateral Woodford well in that area with a very strong IP I think over a couple of thousand Boe per day. So that's a different kind of thing. Again, it's not that deep. It's only another 1,500 or so feet deeper than where we're going to be anyway. So we'll intend to test that idea sometime this year with the well, call it, a pilot. And if we like what we see, we'll complete down there. And if we don't, we'll use the wellbore for our Wolfcamp well. We'd stock it up in either the A or the B area or maybe even Bone Springs and complete it up there. So these are just – I wouldn't put anything in a model about all that, but it's our business to make sure that we gauge all the possibilities and at all depths and acreage that we own and we'll do that.

Sounds exciting, and thanks for taking my question, and thanks again for the hospitality out in Fort Stockton last month. Enjoyed it. Floyd C. Wilson - Halcón Resources Corp.: You're welcome. Floyd C. Wilson - Halcón Resources Corp.: Operator, I think that's all the question and time that we have. If anybody on the line thinks of something that we didn't cover, just give us a call and thank you.