Lonestar Resources US Inc.
Q1 2017 Earnings Call Transcript

Published: 15 May 2017

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources First Quarter 2017 Financial Results Conference Call. [Operator Instructions] Please note this conference call is being recorded today, May 15, 2017. I would now like to turn the conference over to your host, Frank D. Bracken III, Chief Executive Officer. Frank, please go ahead.

[Frank Bracken III:]

I have been called the turd before. I am Frank Bracken, CEO of Lonestar Resources. With me today are Lonestar – our Chief Operating Officer, Barry Schneider; our Chief Financial Officer, Doug Banister and conference call regulars Tom Olle and Chase Booth. Before I get started, I want to direct you to the cautionary note regarding forward-looking statements, Safe Harbor and disclaimer on Page 2 of the slides. Now turn to Page 3 for my opening remarks. Lonestar reported a 15% sequential increase in net oil and gas production for the three months ended March 31, 2017. Net oil and gas production averaged 5,266 Boe a day in the quarter compared to 4,560 the three months prior. Production growth was a result of the completion in new Eagle Ford shale wells and the company expects production to grow at an accelerated rate during the remainder of 27 as completion activity accelerates in the second half of the year. Lonestar demonstrated exceptional cost control in the first quarter of 2016 as we suggested we might on our last call. The company sequentially reduced cash operating costs by 35% on a dollar basis and 43% on a Boe basis and I will get into the details in a minute. Lonestar expects continued improvement in unit operating costs and absolute costs are controlled as production has increased. Lonestar has commenced an active drilling program for 2017 after having only completed 5.0 3.8 net wells. In the first half of 2016, Lonestar is going to drill 12 net wells this year. And with the program underway, production has regained upward momentum, up 15% sequentially. Our guidance remains for the year as unchanged with 4Q volumes projected to rise 65% to 85% over 4Q ‘16 volumes. Lastly and we will get in this at the end of the call, we turned down a boomer in Brazos County in our Wildcat area, which is a highly pressured section of the Eagle Ford at depths of 11,000 feet. And while it’s early, this well is almost producing 1,500 Boe a day and this success could have major implications for the company’s value. Please turn to Slide 4 for some financial highlights. Not only we are glad to get production headed in the right direction, but we moved our production mix toward a more profitable one in the first quarter. 1Q ‘17 volumes consisted of 3,250 barrels a day of oil or 62% of our mix, 927 barrels of NGLs or 17% of our mix and 6,528 Mcf of natural gas a day or 21%. The production’s company mix for the first quarter in total of 79% liquid hydrocarbons and while production increased 15% in aggregate, crude oil production increased 32% sequentially, which moved that oil mix higher and improved the profitability of our production in the quarter. Lonestar’s non-tax cash operating costs saw significant sequential improvement in the three months ended March 31, which is achieved through a combination of stringent cost control and expanding volumes. LOE was reduced from $3.5 million to $3 million, a sequential reduction of 15%. And on a unit of production basis, LOE was reduced 25% sequentially from 827 to 624 per Boe. G&A expense was reduced from $2.8 million to $2.5 million, a sequential reduction of 12%. And on a unit of production basis, G&A was reduced 22% sequentially from 672 to 526 per Boe in the current quarter. Interest expense was reduced from $9.9 million to $5 million, a reduction of 49% sequentially and on a unit of production basis, 55% down to $10.62 per Boe. Crude oil hedging continues to be an important element of our strategy. We believe crude oil hedging provides increased visibility to our cash flow streams and associated liquidity in the current environment and augments the company’s borrowing base. And as you can see, Lonestar has crude oil and natural gas hedges for the remainder of this year and a substantial volume in the next year at very attractive prices. As we do it at each of our quarterly calls, we try to provide some topical commentary that’s intended to give you some insights about how we are positioning the company as well as give you some details on results from the wells that we are drilling and completing. But in summary, we are really excited about the performance of these wells. You will see the quality of the performance and excited about the implication it has to create meaningful value for our shareholders. I will now refer you to Slide 5 to update you on progress at our Cyclone property. Since December 2016, Lonestar has expanded our leasehold position to a current 3,064 acres gross, 2,860 net, which can accommodate to total of 35 laterals with an average lateral length exceeding 8,100 feet. The total cost to put disposition together was $3.8 million, so just a little over $100,000 a location. And the company is in the process of drilling four extended reach laterals right now at Cyclone. First, a little step back. Our Cyclone 4 and 5 wells are performing really well and in fact better than booked and materially better than most of the offsets as depicted by the graph in the bottom right quadrant of Slide 5 and we are well on our way to booking more proved reserves at Cyclone and boosting total company production with our 4 new wells that are in process. The Cyclone 4 has reached total depth in excess of 19,000 feet and has been logged in case. The Cyclone 5 has reached a total depth in excess of 19,000 feet. It is undergoing completion operations as we speak. Fracture stimulation operations for the two wells are scheduled to commence on May 29, with flow-back operations anticipated in the late second quarter. Lonestar has an 86.5% working interest in these 10,000 foot laterals. Following completion operations on the 5H, Lonestar will mobilize the rig to drill the 26 and 27 wells further to the north and east, with planned total depth of 18,000 feet in anticipated perforated intervals of 9,000 feet. Lonestar has a 100% working interest in these wells. Fracture stimulation operations on these wells are scheduled for July 17, 2017. I would note none of these four locations had proved reserves booked on them as of December 31, 2016. I will now refer you to Slide 6 to update you on progress at our Burns Ranch property. Lonestar utilized diverters on the 8, 9 and 10, which are all extended reach laterals. These diverters allowed Lonestar to set stage facing a 300 feet increment, compared to the 200 foot spacing used on our previous wells at Burns Ranch, which reduced the number of fracs or stages associated – and associated costs, while achieving designed proppant concentrations of over 2,000 pounds in two of the three wells, which was at that time the highest in the company’s history. I will direct your attention to Figure 2. Lonestar’s – sorry, Figure 1. Lonestar is pleased to report continued excellent out-performance of its three new wells at Burns Ranch. We are highly focused on maintaining lower gas oil ratios in our Gen 5 wells and we believe that the rapid increase in GOR that we experienced in our Gen 3 wells in Figure 2 impaired oil EURs. As a result, we have been much more stringent in our choke management techniques on our Gen 4 and Gen 5 wells. Lonestar is very encouraged with the results of these Gen 5 wells. We have eclipsed 50,000 barrels of recovery on our Gen 5 wells in just 120 days and have done so while maintaining a gas oil ratio of just about 1,000, which is in sharp contrast to our Gen 3 wells which had GORs of roughly 2,500 at the same time. We think this choke management process will have very positive implications for our crude oil recoveries in future events. I will now direct your attention to Figure 3. A quarter ago, our Gen 5 wells were really outperforming our Gen 3 wells and a quarter later, that out-performance is holding well. At 45% drawdown, our Gen 3 wells are recovered just a little over 28,000 barrels of oil. By contrast, our Gen 5 wells have now achieved over 50,000 barrels of oil recovery with the same pressure drawdown, an improvement of 79%. Again, we think this improvement today is really the result of increased effectiveness of the Gen 5 well completions, in terms of contacting additional reservoir rock volume that allows for more complex fracture in the same fracture half length resulting in better fracture and drainage efficiency, so more good news there. Now I will refer you to Slide 7, to update you on some really exciting news on our Wildcat property in Brazos County. Lonestar drilled the B1H well in Brazos County and cased the well to a total depth of 19,800 feet in a target interval of over – of deeper than 11,000 TBD. Lonestar owns a 50% working interest in the Wildcat B1. The well is fracture stimulated with total of 16.5 million pounds of proppant over a perforated interval of 8,166 feet in 41 stages, equating to a proppant concentration of 2,028 pounds per foot. On May 9, Lonestar commenced flowback operations on the well. And I would characterize our flowback operations as preliminary, as we are awaiting the results of our PVT analysis to determine optimum production methodology. Wildcat B1H is currently flowing back on an 1,864 choke and with 1.8% of its load recovered, current well production rates are over 1,100 Boe a day, with flowing tubing pressures of roughly 4,000 pounds. That consist – those well head volumes consist of 648 barrels of oil per day and 2.8 million cubic feet of gas per day with crude oil gravities averaging 48.8 API and BTU content exceeding 1,300 on the gas strength. Now after gas processing, the current wellhead volumes would equate the sales volumes of 1,472 Boe a day, consisting of 648 Boe barrels of oil, which would be 44% of the mix, 510 barrels of natural gas liquids or 35% of the mix and 1,881 Mcf of dry gas or 21%, yielding a mix – a liquid mix for this well currently at 79%. This is a tremendous result for our company. Like to add that we have been very, very quiet about this area, we have had some views on what we thought we could accomplish. I think we did a terrific job of Geosteering this well and probably and even better job of fracture stimulating it. We will be equally vigilant in the ways that we try to maintain high oil yields through our choke managed production process. But this area can have meaningful implications for us. We have got a sizable acreage position in the Wildcat area and have booked no company operated proved reserves to the area. Lonestar has nearly 10,000 gross and 6,400 net acres in the area, which would hold 46 extended reach laterals based on 800 foot spacing. So really opens the door to a very significant potential. We will clearly monitor this well, recalibrate our reserve forecast based on it and make elections for future operations here that I would think in all likelihood would take place next year, but very exciting news for the company and a potential for some significant reserve and value growth in future periods. And with that, I will open floor back up to Carolina for questions.

[Operator:]

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] We will now take our first question and it is coming from the line of Irene Haas with Wunderlich. Please proceed.

[Irene Haas:]

Yes. Congratulations on that well in the Brazos County area, it’s really very nice and a very nice surprise. Are you drilling any wells close by, is there a Wildcat A that you are working on?

[Frank Bracken III:]

All we did is, while we were there, we set conductor our water board depth for an A1. But our decision really was these were early on at least going to higher cost wells with clearly more risk to them. So we really wanted to be a little bit careful about the way we spend capital out here. That’s the reason that we only owned 50% of this. It’s very much our style just as it was in the Cyclone. It’s to layoff risk in the first well, watch the results and then respond. And so right this year, we are only going to drill this one well, clearly got a lot of locations out here to drill.

[Irene Haas:]

And, if I may, a follow-up question is who is the other 50% working partner and how much you have spend in drilling thus far?

[Frank Bracken III:]

Juno Energy is our 50% partner. They are Leucadia backed company and you all are aware of some of the things we have done with them. We did an acreage trade with them as part of our overall transactions. That’s a private company. And then, it’s a little early to get rid and cleaned up. I think this well will end up costing the $7.5 million, but I would caution, that’s a single pad well. Should we go into the development mode out here, I think we can through shared facility, pads, mobilization, zipper fracs, etcetera, we can work these costs down.

[Irene Haas:]

Great. Thank you.

[Operator:]

Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed.

[Jeff Grampp:]

Good morning, Frank. Just staying on the Wildcat area and I guess based on your experience in that area and I will turn to Eagle Ford and should we expect that early accurate to maybe climb higher or do you think that’s a peak rate to be thinking about moving forward?

[Frank Bracken III:]

Well, I guess I am pretty happy with the rates we have achieved here. And so we will open the chokes on this. We are on an 18. We could have really gotten fancy and open this thing up BOG style and gone nuts in terms of the rate we reported. But I think our view out here is this is a 48, 49 API crude oil condensate, call it what you want. As we have learned in so many of our other areas, preservation of your crude oil and early production of its really important to your ultimate EURs and your returns. So I would tell you that where the likelihood is, is that first we got to get our PDT announced us back. That will tell us a lot about how to produce it, but maybe – I think maybe our internal goal would to see, see how long we can produce this well at this rate. We always – look, we got a bold result on a Wildcat kind of well. But we are pretty conservative when it comes to production practices out here and everywhere. So my guess is we will optimize it for crude oil recovery and flat at this rate for quite a while wouldn’t hurt any of our feelings.

[Jeff Grampp:]

Okay. Yes and certainly don’t want to take anything away from the radar, I guess just trying to, I guess get a handle on how to think about it given it’s still in the earlier stages of flow back. And at Burns Ranch, can you kind of maybe walk me through all the technical indicators certainly seem very positive and indicate that we should expect some outperformance from the well, but just kind of the choom on the oil plot seems to be fairly in line with the old generation well. So, can you maybe walk us through that kind of differential there and maybe when we could expect to see some outperformance on the chooms?

[Frank Bracken III:]

Yes, I would tell you that we do a pretty advanced series of RTA work and get together every week and talk about these wells. And what you have got to understand is that, yes, the choom is the same but we have done it with materially less drawdown, right. I mean, so there is more – we are in contact with more reservoir and we have not depleted this well to the same extent to achieve marginally better recoveries to-date. So, it’s really about how much energy we have left in these new wells comparatively and I think its material. So, they have on a production basis now crossed over and I think yes, it’s the next period of time where I think you would start to see the other wells falloff, it’s the next call, the other wells are really flattened out you would like to see this gap away from those wells on that standpoint in time. So, these are hard things to Wildcat results kind of easy to put. It’s the numbers in there really impressive. The results here are a lot more subtle and it’s the abundance of attention to detail on keeping GORs in check here, because that’s going to be really important to long-term oil recoveries and where we are on a relative basis in terms of pressure drawdown. That’s going to determine the ultimate success out here.

[Jeff Grampp:]

Okay. Very helpful, Frank and nice quarter.

[Frank Bracken III:]

Thanks, Jeff.

[Operator:]

Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

[Ron Mills:]

Good morning, Frank.

[Frank Bracken III:]

Good morning.

[Ron Mills:]

I also want to go back to the Wildcat area a little bit. One, relative to WildHorse acquiring Anadarko’s properties, any commentary as that acquisition moves closer to your Brazos County, any similarities or differences that you may think your Brazos County acreage has versus a lot of that, that was in Burleson?

[Frank Bracken III:]

Sure. Clearly, what WildHorse is trying to do is do the things that we do. And I am not saying they are trying to imitate us, but we have taken a kind of a common view out here that Geosteering is really important and fracture intensity and complexity is really important. And so they are getting those results through increased proppant concentration as much as anything. So there is a lot of commonality in that respect. I would tell you that generally speaking, our views are that the Eagle Ford is thicker in Brazos County than it is in Burleson County. And in this neck of the woods, we have got some pretty intense pressures here. So those are items that are actually quite favorable on a comparative basis.

[Ron Mills:]

Great. And then in terms of the product mix, given the depth and just nature, were you surprised about the amount of crude oil production or was that about what you may have expected for that area?

[Frank Bracken III:]

Yes. I’d say it’s a pleasant surprise. Some of the offsetting – the only real analogies, we’ve got to compare a couple of analogies. We have got our interest in the acreage along strike to the west and those two are hopeless wells, which we acquired an interest in assumed operatorship from Juno and then the Apache wells. And our experience in operating our hopeless wells is, is that we actually choked them back once we assumed operatorship and we actually got a better oil cut. So, little bit instructive there. It’s because of the way Apache has reported production, very difficult to really glean what the optimal oil ratios are out here. Our suspicion is that they probably produced these pretty aggressively and blew them down pretty quickly and got below due point. And as a result, in certain or all their wells we have been trained a lot of the condensate in the reservoir. So we are really happy with the economic splits. The goal is not necessarily try to blow you all away with a rate at any given time, it’s to manage the reservoir properly and maximize that oil cut for as long as we can.

[Ron Mills:]

And then just on the product split for production, it looks like the Burns Ranch wells with the oil holding up under that choke management program probably was a driver behind the higher oil split. Can you think forward is should we anticipate a return to closer to 60% oil or is the first quarter run-rate a pretty good split to use going forward as we look to your fourth quarter guidance?

[Frank Bracken III:]

Yes. It will wobble because the addition of the Wildcat well will make it a little more NGL rich. But all four of the Cyclone wells are going to be dominantly oil, call it 90% oil. So I hate to get too precise, but in aggregate, the wells that we will have online over the course of the third quarter in addition to Wildcat will definitely drive the oil cut higher.

[Ron Mills:]

Great. Thanks, Frank.

[Operator:]

Our next question comes from the line of [indiscernible]. Please proceed.

[Unidentified Analyst:]

Hi, Frank. Great report really exciting about the Wildcat. My question is that you have got a company here where certain analysts have double-digit price targets and yet the shares are down 50% from the beginning of the year and 25% in the last few weeks. And I just wanted to get management’s perspective on where the constant pressure is coming from? Does the wrap up of Ecofin, for example, causing pressure or when you look at the valuation of the company at the current levels, what do you think?

[Frank Bracken III:]

Well, let’s kind of work – let’s work backwards from that. One, clearly we and the analytical community see kind of almost disgusting relative value here compared to a lot of our peers. I think that – and let me be clear, while I don’t speak for Ecofin, they are absolutely committed. They have the same views on value. And I have absolutely no doubt that they are holders not sellers in any speculation that they have been selling their position is completely unfounded. In my mind, this is about just delivering. And we still have a very thin stock. It has not taken a lot of volume to move the stock from side to where it is. I think I did the calculation. It was less than 5% of the shares outstanding traded to get there. And I think if you look at lot of other kind of smaller cap names out there, they have all taken up beating. So our misery is in good company. I think from our perspective, we can really own do two things. We can inform you in a non-promotional fashion, whenever we have information to do so and do so thoroughly and then we can go out and make sure that we are communicating with the combination of our existing shareholders and perspective shareholders. And over time, we will win this battle.

[Unidentified Analyst:]

Great. Thank you very much.

[Operator:]

Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed.

[Mike Kelly:]

Hi Frank, good morning.

[Frank Bracken III:]

Good morning Mike.

[Mike Kelly:]

Wanted to me ask you on production, I think you guys have previously talked about Q4 growth rate, Q4 ‘17 65% to 85% growth year-over-year, so I wanted to get your thoughts and if it’s still a good range and if so, what are the factors that would cause you to come in at the top end of that range versus then bottom end? Thank you.

[Frank Bracken III:]

Yes. So we absolutely, we continue to be fairly unequivocal in our guidance towards that range. It’s really about – it’s really kind of worry about two things, timing I would say this. I would tell you there was definitely some hedging in our thought process about this well, this Wildcat well. So that’s kind of checked the box in a positive fashion and it came on a little later than expected. But it kind of came on okay. And then it’s about getting things on in time. We have got dates on the schedule for each of the next two Cyclone wells. You hope that they hold and don’t slip much, but we have got slots. And then it’s what we will do in the fourth quarter to get wells on in time. So from my perspective, we are going to bring four wells on to Cyclone, two on at Horned Frog and two on at Burns Ranch, at least that’s the schedule. And predictability should be high, right. I think we have discussed our Cyclone and Burns Ranch results. We have a very good feel for how to optimize production at Horned Frog based on the wells we drilled there. This Wildcat well was probably the big unknown, right, what the rate was going to be on it. So I think there is good certainty associated with what the widgets will produce. It’s just a matter of executing in terms of timing and putting them on stream and in an expedient manner.

[Mike Kelly:]

Okay, great color. Thanks…

[Frank Bracken III:]

That’s really the swing Mike is when do you get those wells on is the variability in that 65% to 85% guidance.

[Mike Kelly:]

Understood. I appreciate it. I was hoping you can just kind of frame the implications from what I think kind of the two biggest outside since released the Wildcat well, Brazos and then the fifth generation wells in Burns Ranch and just in Brazos, just talk about what do you think maybe the potential project IRR there is relative to – I think you guys have previously represented the average for your whole opportunity set around 44%, now you can talk about you would see on the Brazos. And then in similar fashion, these Gen 5 wells, maybe talk about the potential IRR step up in Gen 5 versus previous Gen 3 and Gen 4, I understand that its early time data there, but I think maybe framing in that fashion will be helpful? Thanks.

[Frank Bracken III:]

Sure. So everything we have presented to the public today would show you that in aggregate the returns in the Eastern Eagle Ford are inferior to those that we have booked in the Central and the West. However, I note that that’s based on our year end reserve engineering. It’s based on what we have gotten our proved reserve base, which essentially has no representation from Wildcat in it. So they are clearly the Wildcat area is deeper, more pressured, has the potential for bigger recoveries. We will see. But I can tell you this. We are – these I think these wells in the probable category of kind of got a total of in excess of 800,000 Boe assigned to them. We got to watch these wells longer, but is that easy to imagine with what we have seen so far, absolutely. And we have got 46 of them and you can do to the math. It’s pretty beefy compared to our current proved reserves booking, so little early to say. I think these are clearly well better than what’s represented on the page in terms of returns and that’s how we do our business. We will watch these wells and get better forecast of the flow streams before we publicly change that kind of thing. But look, we are really excited. We thought we could – this is a tough area. There is not a lot of well data and we came in, ran out thru-bit lateral logs, got a much better feel for how to stimulate these things and put these outstanding fracs on them. So we think there is lot of upside here and who knows, these could very well compete for capital in the future, which is frankly a very pleasant surprise to us. As it relates to Burns, these wells are doing terrific. And 120 days does not make a well, but we are achieving these rates with really good production discipline. So we are excited about where those returns are going to shake out. Well, I will tell you well north of 50% today at current strip.

[Mike Kelly:]

Okay, great. And then I always appreciate your insight and the environment on the A&D and M&A environment at Eagle Ford and maybe just give us some overall comments there and talk about the opportunities set for Lonestar that will be great? Thanks.

[Frank Bracken III:]

Sure. So we have our little matrix of chooms and we continue to pursue chooms. I think people scratch their head about our purchase of that incremental interest at Harvey Johnson last quarter. The reason we really bought it was to access the undrilled portion of that acreage at very low cost and we are making some strides to both acreage on there that could set up some really nice extended reach laterals. And I would expect to have additional commentary on the next call. So that backlog is looking pretty good. We continue to find these little chunks to take down 300 acres, 500 acres, 1,000 acres and make millions of barrels of reserves out of them at very low cost, that looks good. The number of assets that are starting to appear in the marketplace and in talking to the ANB shafts are projected to continue to appear in the marketplace is kind of overwhelming. So there is no shortage of stuff. We will just got to figure out how to be – we would just have to figure out how to be very smart about how to pay for it.

[Mike Kelly:]

Got it. Much appreciated. Thank you.

[Operator:]

[Operator Instructions] Our next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

[Ron Mills:]

Thanks. Just a couple of follow-ups, you talked about, at least once in the release, but relative to Burns Ranch and now with Wildcat and the relative bookings in Wildcat’s case, none, would you come up particularly and this follows re-determination or next year’s re-determination, you talked about adding support there, any kind of commentary in terms of what to expect as we think about the revolver?

[Frank Bracken III:]

Well, I mean I think and we are kind of in the throws of that process now. And I think I would tell you the same thing I have told you all along. I think that we are going to be pretty flat in the current period and our modeling at the moment, prices notwithstanding used the strip today would be that we would be in the $130 million to $135 million range in November and continue to grow it thereafter.

[Ron Mills:]

And that commentary was obviously before Wildcat. And as you approach the fall, by then you will have had almost a couple of quarters worth of production history. And so in terms of the commentary, the support for that number seems to only be growing or am I reading too much into that?

[Frank Bracken III:]

I mean, it’s simple. This well is kind of – this well is an outperformer for us. The wells are really the bread and the butter of our ability to continue to grow the borrowing base through additional drilling at Burns and Cyclone and places like that. The well performance is holding up and exceeding expectations. Yes, if there were – I don’t think it’s wrong for you to conclude if there is bias it’s improvement not the opposite, right. I mean, everything is performing at or better than expectation. So that should be a very supportive component continued borrowing base growth.

[Ron Mills:]

Great. And then lastly just because they were both so strong in terms of your particularly LOE, but also G&A I think you talked about is showing continued improvement on the unit cost as you grow volumes, but you came in so much better on the first quarter. Was there anything that was kind of one-time, i.e., not as much work-overs or is that 624 per Boe a good clean number on LOE that should show further improvement from that level?

[Frank Bracken III:]

Yes, Barry and his team – if you think about it, we have actually we just kind of setup shop in a lot of places last year. Cyclone, there were no facilities or anything of the sort. Burns Ranch, we really had to build out the infrastructure there and have done so to handle the kind of full-scale development. And there is cost associated with that and then there is working out the kinks and then focusing on how to improve efficiencies through equipment reconfiguration, adjusting your chemicals programs etcetera. And Barry and his group just did a fantastic job over the course of the third and fourth quarters of achieving those efficiencies. And so the first quarter of ‘17 is the first quarter where those efficiencies have been borne out and that’s why it’s so hard to listen to people get upset about 8.25 in the fourth quarter. We knew where they were going. And they were kind of done deals and that we have really minded our Ps and Qs in terms of how we gather and process gas and operate in each of these areas. And so, yes, I think – we would hope that 6.25 is a new level and clearly, we are going to endeavor as we grow volumes towards reducing that. We have got pump of route setup at Burns, we got pump of route setup at Cyclone. The incremental cost associated with going from 2 wells to 6 wells at Cyclone, aren’t very high. So you think in a lot of these areas as you add wells, you actually gained scale and drop unit costs even further. So that’s something that we wouldn’t point to immediately, but I think it has got real likelihood in the second half of the year as we ramp volumes.

[Ron Mills:]

Great. Thank you for the additional color.

[Operator:]

Our next question comes from the line of Brian [indiscernible]. Please proceed.

[Unidentified Analyst:]

Congratulations, Frank D. Bracken III. So you closed Juno in August and Leucadia in December. Did Juno bring in Leucadia or did Leucadia bring in Juno?

[Frank Bracken III:]

Kind of both. The situation with Leucadia has really been a good one. They funded an asset, an asset team in a higher priced environment and weren’t terribly successful out of the shoots. The asset team then departed. And so Leucadia needed to find a way to responsibly operate and try to increase the value of what they had there and we are really good at those things. Conversely, we needed second lien capacity to go buyback our bonds last year and Leucadia not only stepped up to provide that financing, but also was a meaningful participant in the equity offering. So, we have really scratched each other’s backs and they have both kind of revolved around the issues and opportunities at Juno and Brazos County.

[Unidentified Analyst:]

So, is Brad Juno still there or is he and his G&G gone?

[Frank Bracken III:]

Correct. They are gone.

[Unidentified Analyst:]

Okay. And in terms of Leucadia, you mentioned about the 8.75, if they collapsed again, is there any restriction you have on buying those back and would you defer some more exploration if the bonds created one more time?

[Frank Bracken III:]

Yes. I hate to say I hate to not have another opportunity to buy those cheaper. But with what we are doing in the field and I think improved EBITDA every quarter, the likelihood that those are going down is probably limited.

[Unidentified Analyst:]

I would certainly hope so. And one last question, you have done a lot more exploration, lot more risk dollars than I possibly imagine. I thought I was paying attention. Have you been talking to Citibank about this through this whole process and were they somewhat supportive?

[Frank Bracken III:]

Yes. We have an active dialogue with all our banks. We have a meeting today with our entire bank group. If you notice on the “risky wells,” we are always tend to be 50% in them. We try to be really smart about that. In retrospect, we sure would like to have had 100% of Cyclone 4 and 5 and we sure would like to have had 100% of the Wildcat B1H, but it’s just good discipline. And I would tell you that’s kind of it for the risk, if you will, this year. Everything else will be in our bread and butter. So, we are 50% of probably $7.5 million well, so less than $4 million of risk. Frankly, we thought really had great potential. So, that’s about as risky as we get.

[Unidentified Analyst:]

Aright. Well, congratulations Frank. There is nothing you can do about the stock. You just got to keep working hard is what you are doing. So keep it up.

[Frank Bracken III:]

Thank you, Brian. I appreciate your support.

[Operator:]

And we have now a follow-up question from the line of Irene Haas with Wunderlich. Please proceed.

[Irene Haas:]

Yes, thank you. Quick question on the natural gas liquid realization was pretty strong first quarter, is that the kind of percentage we should model for the rest of the year?

[Frank Bracken III:]

That might have a little bit of positive seasonality in it based on the winner. But I would tell you generally speaking, NGL prices are better than they were last year and they were really beat up last year. So, they might be a little softer. I think you could probably with Chase on trying to maybe get a calibration here in a week or so on where our April numbers were, which would you give some sense as to how the NGL prices are holding up counter seasonally.

[Irene Haas:]

Okay, great. Thanks.

[Operator:]

Thank you, Mr. Bracken. We have no further questions at this time in the queue.

[Frank Bracken III:]

Well, thank you all very much for joining and thanks for your questions. We are going to get back to work and continue to do the things we do well.

[Operator:]

Ladies and gentlemen, this concludes the Lonestar Resources for 2017 financial results conference call. Thank you for joining us today. You may now disconnect your lines.