Greetings. Welcome to the Halcon Resources 4th 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. 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 and 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 Q4 and other operational items.
You can access this presentation on our website. Well, 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 John Wright, our Chief Operating Officer.
Our finance and accounting teams are in the 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. John 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 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 will hire advisors to assist us in a comprehensive review of the best path forward for Alcon. This engagement will include a review of various financing alternatives as well as strategic options, including M and A. Although we're looking at M and 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 the most capital efficient manner acreage. We are considering all options and will advise 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 4th quarter results and our 2019 guidance. Thanks, Jim. Production for the
4th 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 3rd party sour gas sales outlets. Fortunately, most of these issues should be in our rearview mirror as our Halcon owned sour gas treatment plant will be operational in a few weeks. I'll let John discuss the progress on this plant as part of his comments later on.
Our realized 4th quarter oil differential was 83 percent of NYMEX, which was improved from the 79% differential we saw in the 3rd quarter. This was largely driven by stronger Midland pricing during the quarter. Our 4th 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 4th 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 4th quarter for a variety of reasons. First, we incurred higher than anticipated water disposal cost in West Quito Draw as our first two Wolfcamp wells there had higher water cut than anticipated and we had to dispose of most of this water using third party trucking. We expect water disposal cost in West Quito Draw to be lower going forward as we are now fully tied into the water bridge disposal system and are no longer reliant on 3rd party trucking. We also had quite a bit more workovers in Hackberry than expected during the quarter and as compared to previous quarters. We expect our workover expense to moderate going forward in Hackberry Draw as most of our older wells have now been put on jet pump and are no longer on ESPs.
G and A expense as adjusted totaled $8,000,000 for the 4th quarter versus $9,100,000 in the 3rd quarter. This reduction was a result of continued focus on cutting corporate overhead costs as we and we expect this downward trend to continue into 2019. Similar to the Q3, we had a significant amount of non recurring expense in the 4th quarter primarily related to the well level chemical treating of H2S and Monument Draw. As I mentioned earlier, we have our plant coming online here in the next few weeks and we expect these costs to materially improve for the rest of the year, somewhere around $2.25 an Mcf is what we expect. With respect to D and C Capital, we incurred about $94,000,000 during the Q4, which was in line with expectations.
We spent another $41,000,000 in the 4th quarter on infrastructure, seismic and other, with most of this spend related to the continued build out of our sour gas handling and treatment facilities in Monument Draw. Looking forward, our 2019 production guidance of 19,000 to 22,000 BOE a day is intentionally wide and somewhat conservative. This is driven by 2 things. First, even though we expect our H2S treating system to work well out of the gate, it is difficult for us to predict the H2S levels we will see on future wells and mine withdraw. It's been variable in the past.
Therefore, we wanted to bake in a level of conservatism. Furthermore, we are still in the early development of our West Quito Draw asset and we want to provide a level of cushion to account for the early stage nature of our development there. Our D and C CapEx guidance of $190,000,000 to $210,000,000 is predicated on a 2 rig plan for 2019 with the split of drilling time between Monument Draw and West Quito Draw. Our infrastructure and other capital spend will be front end loaded as we complete our build out of the sour gas infrastructure and treating facilities in Monument Draw in the Q1 of 2019. Our operating cost guidance includes the impact of higher water disposal costs associated with our recent deal with WaterBridge and that amount equates to about $2 per BOE higher LOE costs than we've seen historically.
I want to conclude by saying although we are not happy about our results for the Q4, we're excited about the future. Once our H2S treating plant is in place in the next few weeks, we will put 5 new wells online in Monument Draw, which is our best area. We will have 5 we also have 5 new wells flowing back in West Quito right now. When coupled with the other 5 wells in Monument Draw, we expect the 2nd quarter to be a strong quarter for us. Further, we have seen real improvements in recent cost trends in the field, especially related to drilling and completion costs, which we expect to continue for the rest of the year.
John will elaborate on that further in a moment. We look forward to ways to continue to improve our business in an effort to maximize value for our shareholders. With that, I'll turn it over to John.
Thanks, Quintin. As Quintin indicated, we incurred significant non recurring rail level gas treating costs in the 4th quarter Monument Draw. We anticipated these higher treating costs for the quarter and we expect more non recurring treating costs in the Q1, although those should be significantly lower than what we saw in
the Q4. Fortunately,
our Valkyrie liquid redox H2S treating plant 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 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 field. As Quentin mentioned, we have 5 Wolfcamp wells, which we plan to put online in Monument Draw shortly after the Valkyrie plant is operational.
This includes returning the previously shut in 7506 H well to production. This well was shut in in early October before reaching peak IP because of high levels of H2S. We also have 25,000 foot laterals in the southern area of our acreage and 27,500 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 6 month drilling pause in activity while we built our have 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 15.25 BOE per day and a 60 day rate of 14.45 BOE per day comprised of 43% oil. It's important to note that these wells are on a managed choke during flowback and they are still flowing approximately 1,000 barrels a day equivalent on average. In early February, we put on 3 more 10,000 foot Wolfcamp wells and another 2 online just about a week and a half ago. These wells are still cleaning up, but pressures and early flow rates are encouraging.
We're obviously concerned about managing reservoir pressures and we will continue to manage our chokes during flowbacks. We are encouraged about what we're seeing early on in West Quito and therefore allocating 3 quarters of a rig here for 2019. So in addition to the 5 wells currently flowing back in West Quito right now, we will put online another 4 before year end. Monument Draw has been a very difficult drilling environment with a lot of geologic complexity. However, with more than 15 wells now drilled across our position and multiple shuttle logs, microseismic and lots of G and G work, we now feel confident in our understanding of how to best drill and develop this asset.
This is evidenced by our most recent our most recent 4 wells in Monument Draw being drilled at cost below well below those that we have seen historically. In fact, on a normalized basis, these wells have averaged below $12,000,000 for a 10,000 foot lateral, which is below our budgeted costs. Although we can't promise we will drill every well going forward here with that issue, we feel that we have turned the corner with our current drilling design targeting and should be much more capital efficient going forward. We've also seen real improvements on frac efficiency throughout the year, which has resulted in additional D and C savings on recent wells. In fact, we are Liberty's most efficient operator in 2018 in the Permian Basin as it relates to the percentage of time pumping on multi well pad jobs, includes a sample set of 3 40 completions.
Our operations team is fired up about getting back to work in Monument Draw as we stated earlier and continuing to expand in West Quito Draw with a focus on finding ways to improve efficiencies and well returns over the remainder of 2019. With that, I will turn the call back over to the operator for questions.
Our first question comes from Jeffrey Campbell, Tuohy Brothers. Please proceed with your question.
Good morning. Back in December, we were told that a 3 rig program drilling 45 to 50 wells had better economics than a 2 rig 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 3 rig plan?
Yes. I mean, Jeff, we are well hedged and we're well hedged on a 3 rig plan. As oil fell back down into the low 50s in late 2018 and maybe even in the upper 40s, we made the decision that the well level economics setting aside our hedge book just didn't justify running 3 rigs. We decided to drop down to 2. We can still as you guys can see, we can still grow our production materially with a 2 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 2 rigs. And we did take the opportunity because we were a little over hedged to monetize some of our in the money hedges in the Q4 and the Q1 given what we saw on oil prices.
Okay. No, that's very helpful. I appreciate it. And you just touched on my Back in December, my understanding was that Halcon intended to produce 7 or 8 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's not going to be any 2019 Hackberry Draw drilling or whatever has been done has been suspended.
So just wondering where we are in this delineation and appraisal process?
Yes, I would just I'll turn this over to John for his comments. But I would say that as Jim indicated, we are 100% focused on being as capital efficient as we can in 2019. 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 at least the acreage we care about there. So we don't need to keep drilling there.
John, do you have anything further to add on that?
Yes. Quinn, I'll just comment that the in Hackberry Draw, our last 6 wells averaged $9,500,000 So we had some outstanding results on not only the drilling side and completion, but also the production and facility. So I think the opportunity is real and Hackberry draw. We're just looking at and 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.
I'd like to just ask one last quick one because I'm a little bit confused or maybe I didn't hear it right. I thought the press release said that Halcon would run 2 operated rigs in 2019 focused on Monument Draw and West Quito Draw. But I thought I heard John 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 in the CapEx range you may be more likely to land in 2019?
John, you want to clarify?
Yes. Just to clarify on that, we'll average 2 rigs for 2019. 1.25 rigs will be dedicated to Monument Draw and approximately 1.75 rigs will be allocated to West Quito. So Monument Draw 0.75 Sorry?
It was 0.75, not 1.75 in West Quito.
Yes. Sorry, yes, 0.75. Thanks.
Okay. All right. Good. So that's like what it yes, that was like 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. I wanted to just ask as you turn on these wells, both at 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 pretty much the same? Because it sounds like at least the operations are going a little bit smoother and maybe even a little bit cheaper, but I didn't know if there was anything that maybe you guys have been changing in that situation.
John?
Yes. If you look back on our press release, in 20 seventeen-eighteen, we're primarily focused on delineating and de risking our acreage on single well pads. Every one of our wells now is being drilled on a multi well pad. And on the completion side, we take a we're taking a large advantage on completion efficiency. In addition, since we're no longer delineating, most of our wells are in Monument Draw or within are typically infill.
At this point, we can make some tweaks and some changes, evolve our completion design that have also helped not only the efficiency, but also the cost side.
Okay. I appreciate it. And Quentin, you mentioned obviously the infrastructure spend probably a little front end loaded this year. As you think about maybe later in this year or even in 2020 or beyond, 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 the 2 or 3 rig, let's just say a 3 rig plan, it's probably $10,000,000 to $15,000,000 a year.
Okay. That's helpful. Thank you. I'll turn it back.
Our next question comes from Tarek 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?
Yes. It should moderate some from the Q4. It's going to be highly dependent on obviously as soon as we can get this plant up and operational, it will come down. We're already in mid March. So but because of the natural decline of the wells there, we haven't put any new wells online in the Q1.
Just as a result of lower volumes of gas, the treating costs will come down. And we've also recently we put we had a new sour gas line come online with ETC, 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 Q1 than it was in the Q4.
That's helpful.
And then
I guess just thinking about liquidity, kind of any early thoughts around how the ABL borrowing based redetermination process looks this spring?
We really haven't kicked that off yet. It will 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're 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. Just last one for me, just philosophically, as you think about the capital structure, sort of how do you think about the value of having an ABL and the relative use of hedging versus putting in term debt into the top of the structure?
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 with our 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 1st lien basis or ABL basis.
Got it. That's it for me. Thanks for taking my questions.
Our next question comes from Jacob Gomolinski Yackel, 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?
John, do you want to take that?
So as
I mentioned earlier, our individual well costs are trending significantly lower than with the recent performance. And those gains are actually shown on Slide 6 with the recent performance on the 9302H and the 933H, which are being replicated on our current pad that's also located in Monument Draw, the North area. A lot of these gains are associated with a slim hole on casing design, some changes in our mud programs, both in the intermediate hole sections and in the horizontals as well as targeting and the fact that we're drilling infill wells now. We have the shuttle logs that we acquired in 2017 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 have a number here. I think sub $11,900,000 And then in West Quito, we're looking at sub $11,600,000 And I think that includes our first level of artificial lift installations as well.
And that's a 10,000 foot firewall, just to be clear?
Yes, correct.
Okay. That's helpful. And then as you look at infill drilling, it 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 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 look back into 2018 and a lot of our presentations, we acquired a lot of microseismic. 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 microseismic models, we didn't see that interference from that perspective. We haven't seen it on the limited spacing tests 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 risk associated with that. We'll continue to evaluate it.
The other part of it, we've also done some reservoir transient analysis or RTA 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, one two quick really follow ups from Tarek's questions. One is on the H2S costs in Q1.
You mentioned sort of materially lower than the $20 odd 1,000,000 in Q4. Just be curious what when you say materially lower, if 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's anything you could expand. I mean, it looks like under the current program, it could get a little bit potentially a little bit tight on the ABL on the RBL exiting 2019.
What kind of options you're considering from a liquidity
perspective? Yes. On the GTO question, that's true recurring GTO going forward. So that guidance doesn't include any non recurring one time items in the Q1 related to H2S, treating temporary H2S treating solutions. I don't have a good number like I said earlier, it's probably $10,000,000 to $13,000,000 if I were to guess, but that's purely a guess.
Maybe it could be a little higher or a little lower than that. And 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, when it's appropriate. Maybe we do nothing and we continue to work with the banks.
We'll just have to see.
Okay. Totally understood. Thank you very much. Appreciate it.
Our next question comes from James Golter, Goldman Sachs. Please proceed with your question.
Hi. This is actually Jason Gilbert for James. Just a couple of asset level questions for you. With Kiena,
can you talk a little
bit 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 it rock or is it a completion thing or it something else? It also seems a little gassier than maybe we would have thought.
John, 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 work now. It's also south of the Gresham fault. 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 GOR 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 GORs 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 area is a little different from the north part to the south part.
On average, the wells are will perform great, certainly within our in line with our expectations. It's just notably that those two areas are there's a difference in GUR and that's kind of driving that. What's I think encouraging about that area is our initial flowing pressures are well above £3,000 in every well. So in addition, we also had we also took a shuttle log in this on our first pad in this area on the Opryvoo well. The shuttle log indicated similar rock properties to that of Monument Draw.
So when you think about what makes an asset successful, while the rock is important and having pressure is important. So we're early 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.
But as we noted earlier that the GORs 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 there than you expected. I want to say you have 21,000 acres there, if I remember correctly.
What's the extent to which you've derisked that position? And are you getting consistent results across the area?
Yes. Well, I wouldn't say that the area has been more complex than what we understood it to be. It is it does have geographical highs and lows with somewhat many basins. So from a geosteering perspective, it's challenging. There's obviously the closer you get to the Central Basin platform, you see debris flows coming off of the platform.
But those so we've got to be able to geosteer around those carbonate flows. But it's also from a different perspective, it's also a positive because those carbon debris flows actually act as seals. And so we're on the frac side, we think that we're and we've seen it from our microseismic is that we're very compartmentalized with regard to maintaining our frac within intervals. So that's the 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 in fill. I'm looking at the inventory slides 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 really 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's specifically addresses Monument Draw, the inventory summary, shows in the well camp that our spacing assumption is 660 with roughly 7 to 8 wells per DSU. And then in the Third Bone Springs with about that same 8 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 mini basin geologic lows, the debris flows coming in, we see different intervals within each area that are productive.
So in some areas, we may see 3 stacked intervals in the Wolfcamp, Third Bone Springs and others, there's 2. So when you look at the remaining inventory, if you were just to calculate 8 wells per interval, it doesn't add up. And that's the reason we're taking account from an engineering basis and a reservoir basis, what's actually achievable.
Well, I'm guessing you guys already, it sounds like already tested that 6 60 foot that's implied with that third Bone Spring number. But how do you know or maybe this is a question or a silly question but how do you know that there's no interference if you later try to drill the 7 wells in the Upper Wolfcamp as well, the Wolfcamp and the 3rd Bone Spring are not interfering with each other?
Undoubtedly, there's 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 treating costs. You add those back for the EBITDA calculation. I'm curious if that's how that expense is treated to calculate covenant compliance?
Yes. 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 PV-ten, pre tax PV-ten at some sort of strip pricing and if you particularly estimate or give some guidance on what PV-ten could be at strip pricing, just similar?
We typically do not provide that. We have it. I think you can look at what we have in our 10 ks and on an approved basis, it was $150,000,000 using SEC pricing I'm sorry, dollars 850,000,000 dollars 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 year end.
Okay. Do you have any estimate for PD value, either it's SEC maybe SEC pricing? Because I did not find that in the 10 ks.
Oh, you mean PDP?
Yes. Yes, PDP.
Our next question comes from Sam Goebel, private investor. Please proceed with your question.
A couple of simple questions. Can you because we're so long far into the quarter, can you estimate what revenue is going to be reported for this quarter when it's reported? And then most recent daily production?
We will report on our Q1 sometime in early to mid May. We wouldn't comment on where it's taken out at this point. 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 Q2.
It's going to be dependent on how quickly the Valkyrie unit, the H2S unit comes online and we can put turn those wells online, 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 Q2 onward for 2019. The Q1 is going to again be a little bit muddied by 3rd 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.
This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.