Lonestar Resources US Inc. (NASDAQ:LONE) Q2 2018 Results Earnings Conference Call August 6, 2018 10:00 AM ET
Frank Bracken - CEO
John Pinkerton - Chairman
Neil Dingman - SunTrust
Jeffrey Campbell - Tuohy Brothers
Jeff Grampp - Northland Capital Markets
John Aschenbeck - Seaport Global Securities
Ron Mills - Johnson Rice
Charles Robertson - Cowen and Company
Ladies and gentlemen, thank you for standing by, welcome to the Lonestar Resources Second Quarter 2018 Financial Results Conference Call. [Operator Instructions] Please note this conference call is being recorded today, 6, August, 2018.
I would now like to turn the conference call over to your host Frank Bracken, Chief Executive Officer. Frank, please go ahead.
Thank you very much, and thanks for joining us this morning. With me are the entire Lonestar Management team and our Chairman John Pinkerton.
Before I started, I've got to direct you to the cautionary note regarding forward-looking statements, safe harbor, and disclaimer on Slide 2 with the slide deck.
Now please turn to Slide 3 for the fun. On our first quarter call I conveyed you that I thought 2018 would be a transformational year for Lonestar. I think today's results and our forward guidance confirms that Lonestar is lifted from launchpad.
Let’s review our key messages for the day. First, Lonestar reported another record result which featured at 98% increase in net oil and gas production to 11,140 BOE a day which was also up 43% sequentially. Production volumes exceeds the high end of the company's guidance at 10,000 and 10,500 barrels equivalent a day, and with 79% crude oil and NGLs on an equivalent basis. We also logged a 131% increase in adjusted EBITDAX and 25% sequentially and again exceeded guidance.
Lastly, we continue to not only grow reserves and production and EBITDAX but also keep improving our debt metrics with debt-to-EBITDAX dropping to 2.8 times in the second quarter. Our 2018 program continues to exceed all expectations, all nine of the wells we placed onstream are outperforming the third-party type curve and will review this continued outperformance later on our call today.
Benefiting from continued outperformance and production results and good visibility on new well start-ups, Lonestar issued production guidance of 11,750 barrels a day to 12,200 barrels a day for the third quarter of 2018. The midpoint of that guidance represents an 8% sequential increase over 2Q 2018 results and is 57% higher than that production reported for the third quarter of 2017.
It’s also important to note that the forecasted oil mix increases from 57% in the second quarter to 61% in the third as Lonestar begins to bring on the oiliest part of our 2018 drilling program. The company also issued 3Q 2018 EBITDAX guidance of $32 million to $34 million which represents a 13% increase sequentially at the midpoint and a 63% over 3Q 2017 results.
At our recent board meeting, the board meeting considered the continued outperformance in our 2018 wells across the portfolio. The very high IRRs being generated and the fact that we're ahead of schedule on achieving our targeted debt metrics and in response Lonestar elected to extend our 2018 capital program bringing 21 gross wells onstream versus the 19 gross previously planned.
Consequently, Lonestar has increased its drilling and completion budget from a range of $110 million to $115 million to a range of 120 to 130. To account for the continued outperformance of our 2018 program and the addition of two wells which will contribute for a portion of the fourth quarter, Lonestar is again increasing its full year production guidance for 2018 to 10,600 to 11,200 barrels a day which equates to a 68% increase over 2017 results.
Commensurately, we’ve also increased our 2018 EBITDAX guidance from a range of 110 million to 125 million to a range of 115 million to 130 million based on a $60 WTI oil price for the remainder of 2018.
Our momentum at Eagle Ford Shale continues to build and our technical operational and financial efforts are delivering high price realizations, high margins and outstanding returns to our shareholders giving us that confidence we need to augment the 2018 program. Not only can the 2018 program on an expanded basis be executed with a drilling completion and fracture stimulation equipment currently under contract but it keeps our execution team highly focused an extending our program deeper into 2018 will provide a seamless transition into our 2019 program.
As far as 2019 outlook is concerned, let me first say that our program is not yet been approved by our Board but the outlook we’re providing should provide a baseline for 2019 and we reserve the right to expand it if returns are maintained and we continue to achieve targeted progress in our debt metrics.
The visibility provided by continuous drilling operations gives us the confidence to issue this outlook which is based on a capital spending of $120 million to $130 million, sees increasing to a range of 13,000 to 14,000 barrels of oil equivalent a day, and sees adjusted EBITDAX increasing to a range of $140 million to $160 million. Importantly, this program can be executed with a single rig and can be essentially funded by internally generated cash flow.
Before I dig into the well results, I’d like to quickly review our financial highlights. So please turn to Slide 4 to commence this review. In terms of daily production, the second quarter was materially impacted by five gross 4.4 net wells at Horned Frog in the La Salle County, and Georg in Karnes County. Collectively, these wells produced over 4,300 barrels a day in the quarter and very late in the quarter we tied in our Horned Frog Northwest wells.
The outperformance of the Horned Frog wells was the predominant reason for their crude oil mix dropping below 60% and as we move into the more oily portion of our drilling program that number will cross back into the 60s in the third quarter.
In terms of wellhead revenue, it was 163% via combination of 98% increase in volumes and a 33% improvement in our commodity pricing. Our pricing continues to be the best in the business. Our 2Q oil price differential was $0.47 over WTI and our gas price realization was $0.11 above Henry Hub.
Lastly, our total cash expenses will reduce by 25% to $20 a barrel and cash margins rose 214% to $27.19 per BOE in 2Q 20118. I would note that we expect wholesale improvement in LOE, G&A and interest expense on a per BOE basis as we ramp up volumes with no appreciable increase in these costs.
Now please turn to Slide 5, we believe our drilling program is generating high IRRs while increasing production and EBITDAX and will contribute to an improved valuation for Lonestar shares. But to maximize the value of the equity, we also believe that we need to continue to make material improvements in our leverage ratios. This slide gives you a clear view into the rapid progress we're making in this regard.
The top graph shows how increasing production coupled with improved prices is driving rapid growth in our annualized EBITDAX and to be clear we’re calculating this figure by taking current quarter EBITDAX and market multiplying it by four to reflect our EBITDAX on a run rate basis.
Like to make two points, one we're ramping EBITDAX in an incredible rate particularly to disregard the effects of hedging which are transitory and on this basis, we’ve increased annualized EBITDAX from 14 million in 1Q 2016 to 117 million in 2Q 2018. Moreover at the midpoint of our 2Q EBITDAX guidance of 32 million to 34 million, annualized EBITDAX will increase to 132 million. This would equate to annualized EBITDAX of 164 million on an unhedged basis.
And as the graph further depicts, our production momentum is expected to move that run rate considerably higher in the second half of the year. The bottom graph shows our debt to EBITDAX ratio over the same period. In the past four quarters, we've produced debt to EBITDAX from 5.4 times to 2.8 times and we expect that number to sellout about 2.5 times by the end of the year and then drop in the low 2s in 2019 and we think this should have a positive impact on the valuation of Lonestar shares.
And now I ask you to turn to Slide 6 to commence the review of our 2018 drilling program which will began in Gonzales County. Recently these acquisitions which are shown in blue on the map have expanded our leasehold position in the Cyclone Hawkeye area to over 10,000 of acres of essentially continuously sold which we've assembled at roughly $1,000 an acre or about 2% of our completed well costs.
Our first 2018 producers were in Gonzales County on our recently acquired Hawkeye acreage and to remind you if you're new to Lonestar. Lonestar acquired a set of assets off the courthouse steps that we now refer to as Hawkeye, that’s East of our cyclone position. We take $3.4 million to acquire 6,257 gross and 1,655 net acres and that acquisition included 2.5 million of PDP PV-10, most of which is associated with wells Lonestar operates at Cyclone. That means that we spent $900,000 for the acreage which equates to $543 an acre.
In January 2018, Lonestar kicked off its program drilling two extended reachable well laterals at Hawkeye with an 87.5% working interest which is now been onstream for more than six months. We now have half a year of production history on Hawkeye and they’re impressive. The Hawkeye wells continue to break away from forecast outperforming third-party projections by 23%.
Online through 180 days, the Hawkeye 1 has produced a cumulative of 130,000 BOE with an average of 724 BOE a day over that six-month period. Meanwhile Hawkeye 2 which is a bit shorter has produced a cumulative of over 111,000 BOE or 617 BOE per day. And as you can see, having recovered 72 barrels of oil per thousand lateral feet, our Hawkeye wells are the best wells in the area yet.
I would also point that Lonestar recently acquired 976 gross and 976 net acres which is contiguous to our Hawkeye leasehold shown in blue on that map. This leasehold can accommodate seven additional locations and I think that the additional acreage deals in the area.
As part of our expanded 2018 capital program, Lonestar plans to drill two long laterals on this newly acquired acreage which are projected to be 8,700 feet of perforated interval. We expect to place these wells onstream in November of this year.
I'll now ask you to turn to Slide 7. The graph on the top shows you how well all of Lonestar's wells in the Cyclone Hawkeye have performed compared to other operators in the immediate area and punctuates the fact that our wells continue to improve and perform very well compared to those other operators.
I think this is the hallmark of Lonestar's value creation proposition as more often than not, we’re following the process where why we examine local Eagle Ford fabric determine where poorly completed wells that currently devalued the local acreage, acquire that acreage cheaply, apply our geo-engineer completion techniques to improve well results thus rerating the value of the acreage.
The graph at the bottom of Slide7, I think it's equally impressive. In green, we show you the predrilled projections of our independent petroleum and engineers W.D. Von Gonten. Based on their type curve projections, these wells are generating 80% internal rate of return.
In red, we've layered on the actual performance of the Hawkeye wells, and while it’s still too early for us to make definitive projections on these wells, I think it's safe to assume that we’ve delivered tremendous IRRs on these wells.
I’ll now ask you to turn to Slide 8. We now have two pads on stream in our Horned Frog area coming out of our 2018 program. The G and the H with the start of the South and our first two wells on our Northwest property shown in blue on leasehold we acquired this year. Lonestar earns a 100% working interest in the Horned Frog G1H and H1H wells, which were placed onstream in March. These were the first two wells in this area which utilized our current generation of geo-engineered completion design utilizing diverters.
These wells have been producing in excess of four months now and the result have continued outperform projections. After registering Max 30 IP's averaging 2,155 barrels a day, these wells continue to exhibit robust deliverability on a constant choke. The G1H well has produced nearly a 0.25 million BOE for an average of over 2,000 BOE per day over 120 day span.
Over the same period the H1H has produced 222,000 BOE for an average of 1,865 BOE a day. Today these two wells are the highest producing wells in the company's history through 120 days and are outperforming third-party projections by 15%.
The graph on the bottom of Slide 8 shows just how well G and the H wells are performing compared to vintage completions and modern completions grow by set operators. Clearly these wells have been exceptional in comparison to our peers.
Now please turn to Slide 9, the graph at the top of Slide 9 shows we show you the predrilled projections for the G and H wells of our independent petroleum engineers based on the projections of 1.2 million BOE and the forecast at hydrocarbon mix. These wells would generate 46% internal rate of return. On our first quarter call I thought I told you that our intention to rewrite the playbook out here and I think we're in the process of doing so.
In red we’ve layered on the actual performance of the G and the H wells and not only of the equivalent rates significantly outperforming third-party projections they produced nearly twice the oil of prior wells on this lease track. So I think it's safe to assume that again we delivered some excellent IRRs on these wells.
I now ask you to focus on the graph on the bottom half of Slide 9 today, we announced the results of the first two wells at Horned Frog Northwest the 2H and 3H commenced flowback operations in June and based on their study of the area our geoscience group recommended that we drill pilot hole here to assess the full legal perception. They concluded that we should target member of the lower Eagle per day was actually higher in section prolific reservoir encountered in the G and the H wells.
Their petro-physical analysis determine that our new target had more movable oil in it. So our goal was to improve our oil recovery and thereby increase returns in all respects our early results been very encouraging. The graph on the bottom half of the page depicts our internal predrilled type curve for these wells, details we took this lease in calendar 2018 we did not engineering from our third-party engineers.
The 2H and 3H were engineered with our geo-engineered completion techniques utilizing diverters with average proppant concentrations exceeding 2,000 pounds per foot. The two wells are registered Max 30 IP's of almost 1,100 BOE a day on a 2,264 choke and not only are these rates above our projections but they're much oilier. So today the Horned Frog Northwest wells have actually claimed 125% more oil over the same time period then our recently drilled Horned Frog G and H wells.
Lastly, we believe that our Horned Frog assets are still vastly underrepresented in our proved reserve base. Only nine of our 27 drilling locations are classified as proved and developed and those are booked on 8,000 foot laterals. And we're hopeful that the early performance of our G and H wells will result in higher assumed oil and gas recoveries and allow for a rebooking at substantially longer laterals which the acreage will afford us.
I’ll now ask you to turn to Slide 10. In May 2018 we replaced our first three producers onstream in Karnes County on leasehold which we acquired as part of our Battlecat acquisition. Lonestar completed the Georg 18, 19 and 20 with average perforations just under 6,008 at the end using our geo-engineered completion design with diverters.
Today we’re extremely pleased with our results. The wells produced Max 30 IP rates of about 950 BOE a day. And as the chart on Slide 11 shows are outperforming the third-party projections to-date. Lonestar owns an 80% working interest and 61% net revenue interest in these wells.
Today these wells have outperformed the projections of our independent petroleum engineer and even at the type curve our acreage acquired in the Battlecat acquisition are generating outstanding IRRs at 94% and the outperformance of those wells not only for higher returns but for our future program.
I now like to focus you on the lower graph on Slide 11. The graph shows our Georg pad in blue versus the offsets drilled by in Karnes and EOG resources through our mind is the preeminent Eagle Ford Shale operator. While these results are quite early, our three well-pad is off to a great start in comparison to those offset wells.
In terms of additional plans for this region and I'd like to turn to Slide 12 to just provide that detail. We plan to bring six more wells on in the central region during the third quarter of 2018 in Karnes County the Georg 24, 25 and 26 have had fracture stimulation operations completed on them and we expect flowback operations to begin this month. We have an 80% working and 61% net revenue interest in these wells.
And in Gonzales County the Culpepper 3-2, 3-3 and 4-4 which were drilled on leasehold also acquired in the Battlecat transaction have been drilled and fracture stimulation on those wells is set to begin in the month - during the month of August and flowback operations are forecasted again mid-September again Lonestar owns 80% working interest and a 60% net revenue interest in these wells.
I like to now turn to Slide 13 to wrap up my plan remarks. Our second quarter production of 1,100 and 140 BOE a day exceeded guidance and set a record for Lonestar having place nine gross 8.2 wells onstream in the first half of the year. We’ve made considerable progress improving our leverage ratios having reduced debt from 5.4 times to 2.8 times in the second quarter of 2018. Our drilling program is exceeding all expectations generating very high rates of return and roughly 12 months payouts.
We’re on track to bring on additional eight gross 6.8 wells net in the third quarter and production as forecast to continue to rise with 3Q production now guided to average just about 12,000 BOE a day and we taken up for your guidance 2018 again. 2018 program is really outperforming, our margins are expanding, our new well returns are extremely high and we’re ahead of schedule on the debt metrics. So that bigger program should not only provide for a bigger 2018 but for a very seamless, continuous program into 2019 that I think increases execution certainly in our ability to continue to deliver the kind of results that you're getting accustomed to seeing at Lonestar.
This concludes my prepared remarks. And now I’ll turn over the call to our Chairman of our board John Pinkerton for some closing thoughts before opening it up for questions.
First I’d like to congratulate the entire Lonestar team for really delivering some outstanding second quarter results they’re really terrific. My takeaways from the second quarter really four times one our technical team continues to really show me that they’re extraordinarily a high quality team. And they continue to innovate not only on the G and G side but the drilling side and important also in the way we complete our wells I think we do things that nobody else is doing in the Eagle Ford. And this team obviously gives us a tremendous competitive advantage as we continue expand our asset base, our leasehold and what have you.
Second I think one of the other concurrent design despite our relatively small size we’re really delivering, really good margins on a per unit of production basis. The good news is I think as we continue to expand the asset base and grow it these margins will continue to expand and obviously having the LLS or component really helps us as well. So we’ll take it.
Third our board approved the expanded budget for really two very simple reasons. One, the team was outperforming the expectations of the previous budget fairly handily and I think a lot of that goes to having a consistent use on the server side and been able to have a capital budget where they can plan and think ahead of time and not have to do well by well. So having a program drilling I think has really helped us and I think it’s one of the reasons why we’ve outpaced the guidance fairly handedly.
So the Board is excited about that, the second thing clearly is that we’re making tremendous headway on the leverage ratios as well. Frank mentioned the EBITDAX to debt, but when you look at things like proved to reserves in particular the PDP to debt ratios and things like that. We’re making really, really good headway and obviously at year-end when alerts those ratios come into clear definition with the year end reserves I think we’re going to be very, very pleased.
Fourth I think as we look ahead here I think and another thing that I think it’s really exciting is that there is no doubt that are well inventory today is larger and has better returns than what we started the year with. Frank and the team have done a tremendous job in terms of adding acreage like the Horned Frog Northwest and some other areas. Extending laterals from 5,000 to 6,000 feet to 8,000 to 11,000 feet obviously has a big impact on returns.
And also I think going back to the technical team, what they're doing on the G and G side and drilling completion side is really interesting. And I'm really excited to see what they continue to do. The one real competitive advantage of being small is that we drill Mona Lisa’s we don't paint by numbers every well is Mona Lisa and they are just doing a tremendous job in driving returns up and expand our EBITDA and cash flow for the good of all the shareholders.
Lastly again I want to thank all the shareholders for being on the call, and Frank and I'll take questions and we’ll wrap this up. Back to you Frank.
Thanks John. Operator, we're ready for questions when you are.
[Operator Instructions] We will now take our first question from Neil Dingman with SunTrust. Your line is open. Please go ahead.
Frank, first question looking at Slide 6 or 8, just to show some of the Cyclone and the Hawkeye and then going on to Slide 8 we shown that Horned Frog. Guess my question is, number one on those newer areas on both up and down Hawkeye and then the new area there on the Horned Frog. Could you talk about sort of how you see - will it be similar pad size, pad design on that as you've done in the rest of area maybe just not even maybe just in the new areas Frank, maybe just talk about pad size and design going forward know each other areas if you could?
Every now and then the topography that mother-nature delivers that might dictate something unusual. But our pads, our battery designs are all incredibly standardized which are meant to provide for consistency of execution and cost certainty.
So the pads design and surface facility design that we’re utilizing across the company. There is oil one and there is gas one and we’re using them everywhere. Those have been very consistent. Our pads seem to be a little big because of the kind of the nature of the frac jobs we do. But yes, things are consistent in that regard.
And then just lastly one follow-up. Just on the cost it seems like, not only that you guys seen the outperformance I'm looking on Slide 7 or couple of those wells like on Slide 8. But could you talk about the associated cost I know you certainly haven't had a change in the year. Your well CapEx either on the Hawkeye 7.2 or if you look on obviously Slide 9, where you are looking at Horned Frog there at somewhere between 7 to 7.9. If you could just talk about although you’re doing a lot of that great steerable and doing a lot of the other technology, could you talk about so what you’re seeing with costs associated with that?
Yes, I guess aside from steel costs which have started to rise, our cost have been fixed by design. I mean we have rigs under contract, we have a frac spread on the contract for the years. So, those were agreed to as essentially 1/1/18. So, we are highly insulated from that. I expect to see - in most circumstances day rates on rigs pop a little bit next year. But when you put that incremental cost in the grand scheme of what a well cost it's kind of - comes rounding error.
So we have not see much in the way of inflation across the year, and we're actually hopeful that as activity wanes in the fourth quarter as we expected to that we might be able to pick up some bargains for 2019.
Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open. Please go ahead.
That was a nice acquisition in Hawkeye at low cost which you guys seem to have an act for. Any color on how that acquisition came about. And on such favorable term, was this an example of the slowest price acreage that you talked about in your prepared remarks and I’m also wondering, can you talk about future acquisitions, are you starting to kind of be seen as an attractive operator of choice whenever this guy can match up with you?
It's a terrific question. What we're seeing quite honestly as our footprint expands in given areas, I think most notably recently in our Cyclone, Hawkeye area and our Horned Frog area is that we're becoming an operator of choice in many circumstances. Our well results are demonstrably better so that we can sit down with lease owners and tell us, show them how we're going to deliver them greater royalty checks.
The fact that our acreage position is essentially HBP allows us to pivot very quickly in the case of the Horned Frog acreage. It was actually a bid twice ours for the leasehold bonus but we were literally able to move a rig and then the week after we signed the lease and that gave us a one year head-start on our competition in terms of our promise to be able to deliver royalty checks to the land owner.
And they - whether they fully understand the financial concept of net present value, they know what to check in our mailbox to them. And then we're also - a decent piece of the acreage we acquired in Cyclone, in Hawkeye the landowner called us and said they wanted to lease to it. So, a variety of factors that are going into this kind of acceleration of these little one off deals but I guess I would say net-net as we build mass and reputation in these areas, these kind of deals actually get easier have gotten easier for us over the past couple years.
That was a great color, I appreciate that. My follow up just stick with the acquisition and just ask, the additional wells that you have indicated you’re going to drill in the second half of 2018 for the level of CapEx uplift. Are these the same two wells that you've identified to be drilled on the Hawkeye acreage acquisition or are they independent?
Yes. They are those two wells and again when you can just swing a rig and get work done, it's a huge advantage to us and we want to be able to continue to use that quickness to augment our reserves in our location counts.
Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Your line is open. Please go ahead.
I was curious on this preliminary 2019 outlook and certainly don't want to pin you down too much here in August but kind of curious on the one rig cadence. What do you think you need to see and the board to be comfortable with going to a second rig, I guess is it fair to think if second half 2018 looks a lot like first half in terms of execution and EBITDA leverage reduction is a second rig looking like a likely scenario do you think?
Look I think from a big picture standpoint, I'm trying to accomplish a couple things. You know I think most importantly, I think a lot of our competitors are becoming location deprived. And I think that somewhere down the line when someone in the market sees Lonestar as potentially something they want and - that depth of inventory in drilling locations is going to be something that will allow us to trade for a bigger premium.
I think that haves and have not’s are coming apart. And so we have a real goal of building location depth and then so that's going to some extent govern the levels of activity we have going forward.
But I think the biggest thing is look, we're going to adjust - according to the guidance that were given for 2019, we're going to grow production somewhere in the mid-20s and we're going to do it while continuing to reduce debt metrics. We think those are two things that are very important to deliver, to continue to get a competitive advantage in terms of valuation our stock. And you know we in the industry have been in a really deep dark bad place when oil prices sell for $26 and we as a company and a Board are committed that never going back there.
So I would say this - the program that you see I think is one that generates growth that's highly acceptable and differentiated in the market. You can - everybody can do the math and it's already acknowledged that - that in fact if we continue to do what we're doing that that one rig program has the capability to be extended by probably another four slots, which can not only augment growth rates in 2019, but set up 2020 for some really attractive growth too.
And I think right now that's the right thing for us to do. So I don't - I think acceleration beyond that is something that's governed by our fiscal discipline and it's just not something where we're willing to waver on yet.
And kind of building on it - there was an earlier question on well costs and where you're seeing things. Can you talk a little bit about maybe what's built into the 2019 program in regards to any sort of inflation and how you guys are generally thinking about securing services next year, obviously you know this year seems like it's been a lot smoother. So how are you guys going to think about maintaining that momentum next year?
So, you know we've got equipment under contract in option. It will service the 2018 program. I would - I think it’s suffice to say that one I think our counterparties on the other side see the value and continuous operations with somebody they can count on to support continue - that kind of continuous activity which is good for the energy service companies margins. So I don't think we have very much in the way of a reasoned - message or reason to break away.
I think just keep on the foot on the gas at the exact same level with the equipment we have makes a lot of sense. Couple of tidbits we will go as we always do go. We bid all our services late in the year and make sure we're getting the best value for our shareholders, and we do have a second rig under option that we could bring into service in March shed the conditions warrant them. But I would I would tell yes, I think at this juncture with the previous comments being the governing ones that we'd need an acquisition to want to put a second rig to work. But we've got that equipment tied up already and the optionality preserve if we if we need it.
So I'm feeling pretty good about what - if we don't let it go it usually stays with you, is our observation and that was a big component of the reason behind not wanting to let the equipment we have go through 2018.
Our next question comes from the line of John Aschenbeck with Seaport Global Securities. Your line is open. Please go ahead.
So the first one, I was hoping to dig a little deeper into the assumptions underlying 2019 outlook specifically, I'm wondering is that outlook reflects the recent well performance improvements you've seen across all your major operating areas? I guess I'm just trying to get an idea of the conservatism of that outlook and perhaps get a better feel for the upside to those forecasts if you continue to see well performance above type curves?
We're in a bit of a conundrum. Clearly, we've maintained the discipline of using our third party engineer's forecast to assist us in building our financial forecast and we will for the for the time being that's what we're going to continue to do. But we have this situation where the - the well program in 2018 in its entirety is outperforming.
And we're pretty conservative by nature and I don't think it is as much as two to six months of outperformance is something that gives us great optimism. It's not something that we want to systemically introduce into our forecasting practices. So we tend to take the view in '18 that we will regret the well results back to the type curve pretty quickly and use the type curve that the Von Gonten has set forth already to make our forecast for 2019 and 2020.
By year end we'll have a lot more well history and fresher data that may allow us and Von Gonten to re-evaluate those forecasts and at which point in time we would make that known to you. But my attitude personally and I know John shares this is, we’re delivering really terrific results to our shareholders right now and we've got confidence that even on Von Gonten numbers, the results that we're going to generate are going to be - are going to be stand out.
So why go get crazy and disappoint people. We're just going to keep putting the runs up in environing and win the game over time.
Appreciate the color there. And then a housekeeping item for me. You kind of touched on this in your prepared remarks but looking at the commodity mix, Q3 well as a percentage of totals increasing relative to Q2. Is it fair to say that that improvement continues into Q4 as you complete more oily completions and then how do you see that kind of progressing as you move in 2019?
So, first thing I would tell you as I think that yes it would be logical that as the Horned Frog wells decline and we drill the remainder of our drilling program in Gonzales County in 2018, that big oil mix would improve over the course of that year.
I will tell you that we do have activity plan for Horned Frog in 2019 right now. So you're going to have to bear with us and it's going to wobble around on us over the course of the years. But I would tell you this that I think whether it's about low end or the high end of the range, that oil mix itself ought to be something well north of 60, but probably no higher than 65% in 2019 based on what we have planned drilled right now.
Our next question comes from the line of Ron Mills with Johnson Rice. Your line is open. Please go ahead.
Question follow-up on the acquisition divestiture questions, can you give us a little bit of a cliff what that market looks like in terms of additional add-ons if there are any kind of packages out there in areas you consider attractive. And then that don't forget the deep part as you continue to evaluate options for Wildcat given the increased industry activity in that area.
Right I think the script is all coming together well for us. As you mentioned in Brazos County which is becoming increasingly non-core to us as we as we grow our central and western presence. There are a number of very active operators both public and private there, it will be difficult for us as a company to paint you a picture as to how we could compete with them and dramatically grow that position. Probably more important from our perspective the returns on well economics in the central or West are vastly superior there than the East.
While as I have said on past calls all signs point to us divesting of that asset at appropriate time. And every quarter that goes on the production falls there and production gains elsewhere it becomes less relevant in the grand scheme of things. We will in all likelihood probably drill a well for our partner there on acreage that they own. But they will offer us an opportunity to earn into. I can't speak with precision as to when that well gets drilled that it's – in all likelihood it’s probably a fourth quarter eventually.
And I would tell you that if we got confirmatory results there that it would be safe for you to assume that we would engage in discussions to sell the Brazos asset which could do great things to continue to de-lever the company in an accelerated rate without materially impacting the production and EBITDAX both of the company which is even better.
In the core areas of our focus I would tell you that I globally think that there have been lots of packages that come on the market. Some of them are in areas that make sense to us and we just haven't been to come up with the right number.
And there is some that I think frankly are in areas that if we are to acquire will diminish the average lot quality in the company and that's very contradictory to a primary goal of ourselves. But I think the things that allowed us to be successful last year in making a couple of acquisitions the same market conditions persist today. There are companies with too much leverage and it safe to assume that they’ll need to come to market with assets for sale and we're vigorously pursuing that kind of opportunity.
And at the same time, there are some smaller private equity groups out there similar to the one that we acquired last year. And I would tell you these groups are really impressive in terms of the kind of assets they acquire and their location and the price they are acquiring at.
And then it comes to the hard work of actually executing in the field which is a much more daunting task then I think most of them really fully appreciate. And it's usually at some point in time after an initial capital program has been executed that on occasion their capital provider decides that they don't do any more of that and they want to sell the asset.
And that was the circumstance with the assets we acquired in Karnes in Dallas last year. The well results we’re delivering out of that acquisition have been terrific so far. And we love to do that again in the near future.
So the things that - the opportunities that we need and the conditions that we need to acquire them still appear to be there and with improved capital structure that we've got. With a somewhat improved equity valuation that we're experiencing those type of opportunities are at least things we can seriously consider now.
And then when you think about the well performances at Horned Frog and even at Hawkeye Cyclone. Obviously at Hawkeye Cyclone or Hawkeye you recently added wells artificial lift it looks like at Horned Frog those initial wells the G and H wells are still flowing naturally. Is there when you think about Horned Frog and when you think about the G1H wells, you talk about some of the upside even from the current outperformance and how you may attain it?
Right, in the Horned Frog area we’d probably utilize gas left to assist in lifting fluids there. And we still haven't changed the chokes on those wells, they are just performing beautifully. And we brought them below due point with no change in condensate yield, which an important objective for us. And we're pretty content to let those go on autopilot for the foreseeable future.
In the Karnes and Gonzales areas and for that matter we utilize these techniques in La Salle well. We’ve really optimize our artificial lift program in a way that we think at the barest to minimum it really accelerate present value and seamlessly transitioning from flowing wells to the next phase and does so at great cost.
So we tend to want to keep that pretty proprietary, but as we did shut in first Georg pad to - while we fracture stimulated the second Georg pad, and we took that opportunity during that production downtime to equip all those wells with our artificial lift systems. So yes, it would be - it’s likely that you can see the kind of response that we generate at Hawkeye on the Karnes County wells as well.
And then one last one, just as you look at your particularly in LaSalle County for the Horned Frog area, what does the land look like? You recently added the Horned Frog North West. There seems to be not very much industry activity between your core Horned Frog area in the new Northwest. Is that an area that seems to have a lot of, I guess, a smaller interest that you could continue to pick up?
There is a little bit of that, there's definitely some leasehold that has reverted back to the mineral owner that's there for the taking. And I would tell you that aside from one other publicly traded company as kind of our size, most of that acreage is held by companies that are quite large. And that has exhibited essentially no activity there for four years now.
So it's logical that to us that they clearly don’t be in that core. And we love to consolidate that area. We think there is a pretty good arbitrage between what the properties work on our nickel versus others. So it's a big area that we know extremely well and we’d love to continue to pick up assets there.
Our next question comes from Charles Robertson with Cowen and Company. Your line is open. Please go ahead.
I guess a little more detail on what you sort of do differently in your wells. Obviously the outperformance is there, but you mentioned diverter technology. What are you doing also in spacing relative to your peers if you could discuss?
Yes, I think that - look we’re focusing on the details and those details started picking the right 20 feet of the rock to optimize contact with movable hydrocarbons in a situation that they can be - we can propagate high-quality fracs. So, and producing them correctly in terms of choke management, but we do a lot of study - a lot of study of offset operators in terms of their historical spacing patterns.
That's one of the nice things about the Eagle Ford is quite often you've got how to use and how not to use based on activity that occurred during the blizzard of activity that occurred as the play was being developed.
I think rarely do we see an area where we think that the aggressive down spacing that the industry has taken has made sense. Perhaps it made sense at $105 oil in terms of acceleration of present value, but in terms of making best-in-class wells with high EURs, it support our target returns.
We think the industry is probably over spaced a lot of the leasehold. So that's little thing we’re careful about and we utilize Von Gonten, we do our own work. We premodel our fracs to make sure that we're effectively draining the well spacing properly. And we can always come back and go tighter. We could never go back and wish you didn't lose her.
So we’re tapping each property in a very measured fashion and making sure we get enough history to make sure we're doing in an optimal way. So, it's just not getting ahead of yourself, not getting greedy, and again the depth of our inventory allows us to not get crazy about the way we’re spacing things, the zones we’re targeting et cetera. We’re kind of dealing from a position of strength in that regard. So we tend to be pretty conservative about networking.
Obviously the wells continue to outperform your predictions and your third-party predictions as well. One other question looking to 2019 in the preliminary, looking at your hedges there what are your thoughts of any additional hedges layering on here?
Yes, I think our view is that - we’ve got fairly good price inflation for 2019 and we can see a pretty significant downturn in production prices and it wouldn’t radically affect our plans. We tended to want to be opportunistic, I think you see in the hedge disclosure there is an extra 500 barrels a day that we put on in 2019 and 2020. We kind of tend to pick around peaks in the market that we see. And so you could see us move our hedge book up another 10% of forecasted production in 2019.
And then we’ll be opportunistic in the 20 market as well. I think we’re only about 20% hedged in 2020 right now. And we'll methodically move that up as prices give us a debt that gives us a return you want and that are accretive to the bank debts that are used to calculate our borrowing debts.
And thank you, Frank. We have no further questions in the queue.
Well thank you all for your attention today and your sponsorship of Lonestar and the questions you asked. And if you have any further questions, don't hesitate to call Chase or I, and again thanks for your attention today.
Ladies and gentlemen, this concludes the Lonestar Resources second quarter 2018 financial results conference call. Thank you for joining us today. You may now disconnect your lines.