Greetings, welcome to the Halcon Resources Fourth Quarter 2018 Earnings Conference Call. At this time, all participants are in a listen only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note this conference is being recorded. I will now turn the conference over to your host, Jim Christmas, Chairman of the Board. Mr. Christmas, you may begin.

Good morning. Thank you. I was recently named Chairman of the Board of Halcon. And until we hire a new CEO, I'm effectively acting as the Interim-CEO. For the record, this conference call contains forward-looking statements. A detailed description of our disclaimer, see our earnings release issued today and posted on our website. We've also updated our investor presentation for the fourth quarter and other operational items. You can access this presentation on our website. I'd like to begin my comments today saying that Halcon had a good quarter, I obviously cannot. As previously announced, we've had quite a few changes in our Executive team over the last few weeks. Despite these changes, our operations team is fully intact under the leadership of Jon Wright, our Chief Operating Officer. Our Finance and Accounting teams are in good hands of Quentin Hicks, who was recently named our Chief Financial Officer. As we reported, we're beginning the search for a new CEO. But have the people in place today to continue to run our business effectively while that search is underway. Our board and management team are focused more than ever on disciplined operations, controlling costs and maximizing our capital efficiency. We've identified significant corporate overhead savings and we also are seeing significant improvements in drilling and completion costs in the field. Jon Wright, will comment further about these recent results, we've had in our operations later in the call. The Board and the management team believes that our assets are significantly undervalued as reflected in our share price, and we're highly focused on realizing that value disconnect for the benefit of our shareholders. We have hired advisors to assist us in a comprehensive review of the best path forward for Halcon. This engagement will include a review on various financing alternatives, as well as strategic options, including M&A. Although we're looking at M&A, asset sales and other strategic options, we may indeed find that the best way to maximize value is to continue to develop our assets in most capital efficient manner possible, which will allow us to gain scale and relevance in the market, while at the same time reducing our leverage and de-risking our acreage. We are considering all options and we'll advise it as to our path forward when appropriate. For now though, our team is focused on cutting costs and continuing to develop and drill our acreage position in an efficient manner. I'll now turn the call over to Quentin for some comments on the fourth quarter results in our 2019 guidance.

Thanks, Jim. Production for the fourth quarter averaged 17,196 barrels of oil equivalent per day, comprised of 69% oil. Our overall production on a per BOE basis was below our guidance range, but oil production was within our guidance range. Our lower gas production was primarily related to the gas takeaway constraints we saw at Monument Draw, where we've been relying on interruptible third party sour gas sales outlets. Fortunately, most of these issues should be in our rear-view mirror as our Halcon owned sour gas treatment plant will be operational in a few weeks. I'll let Jon discuss the progress on this plant as part of his comments later on. Our realized fourth quarter oil differential was 83% of NYMEX, which was improved from the 79% differential we saw in the third quarter. This was largely driven by stronger Midland pricing during the quarter. Our fourth quarter natural gas differential came in at 29% of NYMEX, which was lower than previous quarters, because of weak Waha pricing in the quarter. Our NGL differential for the fourth quarter was 34%. We expect our oil - our realized oil differentials to improve in 2019, given the combination of stronger Midland pricing in addition to our selling majority of our oil in the Gulf Coast beginning later this year. Our adjusted operating expenses, including LOE, workover and gathering transportation and other were elevated in the fourth quarter for a variety of reasons. First, we incurred higher than anticipated water disposal costs in West Quito Draw, as our first two Wolfcamp wells there had higher water cut than anticipated and we had to dispose most of this water using third party trucking. We expect water disposal costs in West Quito Draw to be lower going forward, as we are now fully tied into…

Thanks, Quentin. As Quentin indicated, we had incurred significant non-recurring well level cost in the fourth quarter in Monument Draw. We anticipated these higher treating cost for the quarter and we expect more non-recurring treating cost in the first quarter, although those should be significantly lower than what we saw in the fourth quarter. Fortunately, our Valkyrie liquid REDOX H2S treating plan is expected to be operational within the next few weeks, which will dramatically reduce our treating cost. We expect to be fully operational by the 1st of April, if not sooner. Once operational, this plant will be capable of treating all of our 2019 expected gas volumes in Monument Draw at around $2.25 per Mcf. This is based on our current weighted average H2S concentration rate for the fuel. As Quentin mentioned, we have five Wolfcamp wells which we plan to put online in Monument Draw, shortly after the Valkyrie plan is operational. This includes returning the previously shut-in 7506H well to production. This well was shut-in on early October before reaching peak IP because of high levels of H2S. We also have two 5,000 foot laterals in the southern area of our acreage and two 7,500 foot laterals, in the northern area of our acreage being put online within the next few weeks. We are excited to get back to work on drilling and completing wells in Monument Draw after more than a six month drilling pause in activity, while we built our - built out our sour gas infrastructure. We plan to run about 1.25 rigs here for the remainder of 2019. In West Quito Draw, our first two 10,000 foot operated Wolfcamp wells were put online in early November. These wells - these two wells had an average peak 30-day rate, of 1,525 BOE per…

At this time, we'll be conducting a question-and-answer session. (Operator Instructions) Our first question comes from Jeffrey Cambell, Tuohy Brothers. Please proceed with your question.

Good morning. Back in December, we were told that a three rig program drilling 45 to 50 wells had better economics than a two-rig program, and that activity was protected by hedging. So I was just wondering what has changed since then to pull the program back from that earlier three-rig plan?

Yeah, I mean, Jeff, we are well hedged and we are well hedged on a three rig plan. As oil fell back down into the low 50s in late 2018 and maybe even into the upper 40s, we made the decision that the well level economics, setting aside our hedge book, just didn't justify running three rigs. We decided to drop down the two, because still as you guys can see, we can still grow our production materially with a two-rig program. And as we're early in West Quito and we're no longer drilling in Hackberry Draw, operationally it just makes more sense right now to consider two rigs. And we did take the opportunity because we were a little over hedged to monetize some of our inter-money hedges in the fourth quarter and the first quarter, given what we saw in oil prices.

Okay, now that's very helpful, I appreciate it. And you just touched on my next question, back in December, my understanding was that, Halcon intended to produce seven or eight results in the northern portion of Hackberry Draw during 2019. That was expected to improve the value of the asset. And today's presentation indicates that there is not going to be any 2019 Hackberry Draw - drilling or whatever it's been done, it's been suspended. So just wondering where we are in this delineation and appraisal process?

Yeah, I would just turn this over to Jon for his comments, but I would say that, you know, as Jim indicated, we are a 100% focused on being as capital efficient as we can in '19 and the economics in Hackberry and the returns that we see there relative to the capital we spend just don't match up or stack up with Monument Draw or West Quito Draw. So most of that acreage is held by production, so - or at least the acreage we care about there. So we don't need to keep drilling there. Jon, do you have anything further to add on that?

Yeah. Quinn, I'll just comment that the - in Hackberry Draw, our last, our last six wells averaged $9.5 million. So we had some outstanding results on not only the drilling side and completion but also the production facilities. So I think the opportunity is real in Hackberry Draw. We're just looking at maximizing our capital efficiency and if we see, commodity prices increase it's probably a great opportunity for us to take another look at that area.

Okay. I really appreciate that. I'd like to just ask one last quick one, because I'm a little bit confused and maybe I didn't hear, right? I thought the press release said that Halcon would run two operated rigs in 2019 focused on Monument Draw and West Quito Draw. But I thought, I heard Jon say that the average rig count is going to be 1.25 rigs in 2019 going forward. So could we just sort of nail that down? And also, does it suggest any likelihood of where and the CapEx range you may be more likely to land in 2019?

Jon, you want to clarify?

Yeah. Just to clarify that, we'll average two rigs for 2019. A 1.25 rigs will be dedicated to Monument Draw and approximately 1.75 rigs will be allocated to West Quito. So Monument Draw

It's 0.75.

Sorry?

It was 0.75, not 1.75 in West Quito.

Yeah, sorry, 0.75. Thanks.

Okay. All right. Fair. So that's like what - yeah, that was linked to the press release. I just misunderstood. So thanks for clearing that up.

Our next question comes from Jason Wangler, Imperial Capital. Please proceed with your question.

Good morning. Wanted to just ask, as you - as you turn on these wells, both the West Quito and in the other area, what are you seeing in the change in operationally, are you guys doing anything different on the completions or is it pretty much the same? Because it sounds like at least the operations are going over smoother and maybe even a little bit cheaper. But I didn't know that there is anything that maybe you guys had been changing in that situation.

Jon?

Yeah, if you look back on our press release, in 2017, 2018, we're primarily focused on delineating into risking our acreage on singular pads. Every one of our wells now is being drilled in a multi-well pad. And on the completion side, you take a look, we're taking a large advantage on completion efficiency. In addition to this we are no longer delineating, most of our wells are in Monument Draw or within, or typically until this point, we can make some tweaks and some changes, evolve our completion design that have also helped, help not only the efficiency but also the cost side.

Okay, I appreciate it. And Quentin, you mentioned obviously the infrastructure spend probably will be front end loaded this year. As you think about maybe later in this year or even in 2020 or beyond, you know what is a more normalized spend on the infrastructure side as you continue to build that out?

If we look forward to like 2020, with a two or three rig or let just say a three rig plan, probably $10 million to $15 million a year.

Okay, that's helpful. Thank you. I'll turn it back.

Our next question comes from Tariq Ahmed, JPMorgan Chase. Please proceed with your question.

Good morning.

Good morning.

As we sort of finish out the infrastructure at Monument Draw, can you maybe just sort of give us your expectations about what the sour gas impact looks like in 1Q? Is it sort of similar to 4Q or should we start to see some benefit during the quarter?

Yeah, it should moderate some from the fourth quarter. It's going to be highly dependent on, obviously as soon as we can get this plan up and operational, it will come down. We're already in mid-March. So, but, because of the national decline of the wells there, we haven't put any new wells online in the first quarter, just as a result of lower volumes of gas, the trading cost will come down. And we've also recently we put, we had a new sour gas line come online with EPC, which has helped moderate that expense as well. So I don't have a good number to give you, but it should be meaningfully lower in the first quarter than it was in the fourth quarter.

That's helpful. And I guess just thinking about, you know, liquidity, kind of any early thoughts around how the ABL borrowing base determination process looks this spring?

We really haven't kicked that off yet. It'll be starting here in the next several weeks. We have strong liquidity as we sit here today. As Jim mentioned, we, as part of the engagement of the advisors, we are going to be looking at financing options, in addition to other strategic options. And we'll report more on that as we have more color.

Understood. It's last one for me. Just philosophically, as you think about the capital structure, sort of how do you think about the value having an ABL and sort of the relative use of hedging versus putting in kind of term debt into the top of the structure?

You know, it's the cheapest form of capital we have, so we like that. Of course, it's probably, sometimes it can be a challenge for a company without leverage profile. So we again, we're just considering all options on the table. We can hedge, we'll be able to hedge regardless of what type of financing we have on the first lien basis or ABL basis.

Got it. That's it for me. Thanks for taking my questions.

Our next question comes from Jacob Gomolinski-Ekel from Morgan Stanley. Please proceed with your question.

Hey, good morning.

Good morning.

How have well costs and returns been recently on an unhedged sort of realized prices at the wellhead? And then similarly, how do you expect well costs to change as you shift to multi-well pad development versus single-well pads?

Jon, you want to take that?

Yeah, so as I mentioned earlier, our individual well costs are trending significantly lower than - with a recent performance. And those gains are actually shown on Slide 6 with the recent performance on 9302H and the 9303H which are being replicated on our current pad that's also located in Monument Draw the north area. While these gains are associated with a Slim Hole casing design, some changes in our mud programs both in the intermediate hole sections and in the horizontals as well as targeting - in the fact that we're drilling infill wells now, we have the those shuttle logs, that we've acquired in 2017 and 2018, which will allow us to be able to access or the profile of the formation across that 10,000 foot interval, which then ties back - that data ties back into our reservoir model, so along with the seismic. So all those things are important to us. We've seen significant cost reductions. Our current expectation is that our wells in Monument Draw will average, I don't remember here, I think sub $11.9 million, and then in West Quito we're looking at sub $11.6 million, and that includes our first level of artificial lift installations as well.

Okay.

And that would be 10,000 foot lateral, just to be clear.

Yes, correct.

Okay, that's helpful. And then as you look at infill drilling, that might be too soon to tell, but have you seen any sort of performance degradation just due to sort of parent child issues as you drill those infill wells on existing pads?

As of this point, we haven't seen that, the parent-child interference. Obviously that's something that the industry as a whole is highly focused on. And we'll continue to monitor our well results. If you then look back in the 2018 in lot of our presentations, we acquired a lot of micro-seismic. We ran a lot of tracer tests, both with the fluid systems and the proppant systems. And that technology - that application of those technologies enabled us to give a fairly quality estimate on our frac lengths. And so as we saw in the micro-seismic models, we didn't see that interference from that perspective. We haven't seen it on the limited spacing test, we have thus far. It's important to note that with early time - the wells aren't bounded on both sides by another well. So there could be - there could be a risk associated with that, we'll continue to evaluate it. The other part of it - we've also done some reservoir transient analysis, or RT analysis, on all of our areas which indicate that our current spacing assumptions are correct. But as I mentioned, we'll continue to monitor that on a daily, weekly, monthly basis.

Okay, that's helpful. Thank you. I guess, two quick - really quick follow-ups from Tariq's questions. One is on the H2S costs in Q1, you mentioned sort of materially lower than the $20 million odd in Q4. Just be curious what - when you say materially lower, that's something you could quantify, and just wanted to confirm that the recurring GTO expense in the guidance does not include those Q1 additional costs? And then the other just follow-up is on the liquidity front, if there is anything you could expand. I mean, it looks like, under the current program it could get a little bit - potentially little bit tight on the ABL - on the RBL exiting 2019. What kind of options you're considering from a liquidity perspective?

Yeah, on the GTO question, that is - that's true, recurring GTO going forward. So that guidance doesn't include any non-recurring onetime items in the first quarter related to H2S, treating temporary H2S treating solutions. You know, I don't have a good number, like I said earlier, it's probably $10 million to $13 million, if I would guess, but that's purely a guess. Maybe it could be a little higher or a little lower than that. Then, again, I don't want to comment specifically on financing options, we're right in the middle of thinking through that, with the help of advisors and as appropriate, we'll talk about that if it's appropriate and when it's appropriate. Maybe we do nothing and we continue to work with the banks. We'll just have to see.

Okay, so I understood. Thank you very much. Appreciate it.

Our next question comes from James Golter [ph] Goldman Sachs. Please proceed with your question.

Hi, it's actually Jason Gilbert for James. Just got a couple of asset level questions for you. West Quito, can you talk about what's going on there? If we look at maps and offset operators, maybe we would have expected slightly better results from the initial wells, I'm just wondering, is there - is there a rock or is there a completion thing or is something else? It also seems a little gas here than maybe we would have thought.

Jon, you want to take that?

Our development primarily has been in our southern West Quito area, and that's an area that is a little higher on structure with regard to the well pad. It's also south of the Gushing Fall [ph]. And so what we've seen in that area is that, along with a lot of recent results from offset operators, is that, that area has a little higher GUR than what we initially expected. We haven't been able to test our northern West Quito assets yet. So we've got a number of units there, that we'll hit in 2019. The GURs there are materially lower than what we have in the southern part of that acreage position. So I think it's just important to note that the areas is a little different from the north part to the south part. On average, the wells are - will perform great, certainly within our - with in line with our expectations. It's just notably that those two areas are - there is a difference in GUR and that's kind of driving on that. But what's I think encouraging about that area is our initial flowing pressures are well above 3000 pounds in either well. In addition, we also had, we also took a shuttle log and it's on our first pad in this area on the [indiscernible] well. The shuttle log indicated similar rock properties to that of the Monument Draw. So when you think about what makes an asset successful, while the rock is important and having pressure is important. So you know, we're delighted with the results there. We've been managing our flow backs. We're concerned about reservoir management and obviously, differentials. So from that perspective, we've taken a conservative approach. It is, as we noted earlier, that the GURs in that southern position are probably a little higher than we expected.

That's helpful, thanks. And then shifting over to Monument Draw for a second, I think you mentioned earlier that it's a little more complicated than you expected. And I was just wondering, I want to see your 21,000 acres there if I remember correctly. What's the extent to which you've de-risked that position and are you getting consistent results across the area?

Yes. Well, I wouldn't say that the area has been - has been more complex than what we understood it to be. It is, it does have geological highs and lows with somewhat many basins. So from a geo steering our perspective it's challenging. There is obviously the closer you get to the Central Basin platform, you know, you see the reflows coming off of the platform. But those - so we've got to be able to geo steer around those carbon flows. But it's also from a different perspective, it's also a positive, because those carbon flows are actually at the seals. And so we're on the frac side, we think that we're - when we've seen it from a micro-seismic as we're very compartmentalized with regard to maintaining our frac with an interval. So that's a positive aspect of it. The results that we've seen across the acreage have been fairly consistent from the north to the south. We're seeing great results in the north. I'm not sure that we fully expected that. But the performance in the north has been just as good as the south. I would say that including our pilot holes in the northeastern corner of the acreage, we're probably 90% delineated within that position.

That's super helpful. Thanks very much. I'll turn it back.

Our next question comes from David Meats, Morningstar. Please proceed with your question.

Hey, guys, I want to follow up on an earlier question about parent child infill. I'm looking at the inventory slice in your deck here and it looks like you're assuming about 35 to 40 wells per DSU with your industry estimates, just wondering if that's realistic. And in the previous question you talked about something called RTL analysis, I don't know what that is. But just in general, if you can give some more color on the confidence that you have in those inventory estimates?

Yes. So the inventory estimates, if we look at the slide that specifically addresses Monument Draw, the inventory summary. It shows in the Wolfcamp that our spacing assumption is 660 with roughly 7 to 8 wells per DSU. And then, the third Bone Springs with the same eight wells per DSU. I think it's important to note that in every area that we've created an inventory summary for, these are engineered. So as we look across Monument Draw, we see, as I mentioned before, with the geologic highs and the many basin geologic lows, the reflows coming in, we see different intervals within each area that are productive. So in some areas, we may see three stacked intervals in the Wolfcamp, Third Bone Springs and others there is two. So when you look at the remaining inventory, if you were just to calculate eight wells per interval, it doesn't add up, and that's the reason we're taking account from an engineering basis on a reservoir basis, what's actually achievable.

I'm guessing you guys have already - it sounds like already tested that the 660 foot, that's implied with that Third Bone Spring number. But how do you know or maybe is it a question, a silly question about how do you know that there is no interference if you later try to drill the seven wells in the Upper Wolfcamp as well, that the Wolfcamp and the Third Bone Spring are not interfering with each other?

Undoubtedly there is risk with that and until we have more cases of infill wells with bounded results, we'll have a better idea of how that looks. Today, we're very early in our program. We're being very thoughtful in how we develop this area, taking account that the potential for child-parent interference.

All right. Thanks a lot, guys. I appreciate it.

Our next question comes from Marianna Kushner, Nomura Asset Management. Please proceed with your question.

Hi, I just wanted to clarify a couple of things regarding the sour gas trading costs. You add those that for the EBITDA calculation, I'm curious if that's how or how that expense is treated to calculate covenant compliance?

Yeah, so it's a full add back for EBITDA for purposes of calculating our leverage under the revolver covenant.

Okay. Thank you. And also curious if you could provide a PV 10, pre-tax PV 10 at some sort of strip pricing. And if you particularly estimate or give some guidance on what PV 10 could be at strip pricing similar...

You know, we typically do not provide that. We have it, I think you can look at what we have in our 10-K and you know on approved basis it was 150 million using SEC pricing, I'm sorry, 850 million using SEC pricing. Obviously SEC pricing is a little higher than strip right now, but that gives you a good kind of ballpark of what total proved is, as of yearend?

Okay, do you have any estimate for PD value, either its SEC - maybe SEC pricing? Because I did not find that in the 10-K.

Oh, you mean PDP?

Yeah, PDP, I didn't…

Yeah, it's somewhere in the $500 million-ish range.

Okay. Thank you.

Our next question comes from Sam Goble [ph], Private Investor. Please proceed with your question.

Couple of simple questions. Can you - because you're so long far into the quarter, can you estimate what the revenue is going to be reported for this quarter, when it's reported and then most recent daily production?

We will report on our first quarter sometime in early to mid-May. We wouldn't comment on where it's taken out at this point. So it's just something we wouldn't do at this point. Production, it's highly variable. Again, as we mentioned, we are looking forward to the second quarter. It's going to be dependent on how quickly the Valkyrie unit, the H2S unit comes on line, and we can turn those wells online, and how quickly they clean up and start producing oil and gas. I would just say that we feel real good about where we're headed in the second quarter onward for 2019. The first quarter is going to again be a little bit muddied by third party gas takeaway constraints as well as higher H2S treating costs than we expect going forward.

Okay, what about liquidity then? Do you project liquidity position at the end of the quarter?

No, we typically do not provide that until we actually report on the quarter.

Okay. Thank you.

We have reached the end of the question-and-answer session, and I will turn the call back over to Quentin Hicks for closing remarks.

Thank you all for your interest and feel free to reach out to me anytime with any questions and we look forward to the rest of 2019. Thank you.