Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources’ Third Quarter 2019 Financial Results Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Please note, this conference call is being recorded today, the 12th day of November 2019.I would now like to turn the conference call over to your host, Frank D. Bracken, Chief Executive Officer. Please go ahead, Frank.

Frank D. Bracken: Thank you. I have most of the team here with me, so if you ask me a question I can answer, I have help. Before I began, I need to direct you to the cautionary note regarding forward-looking statements, Safe Harbor and disclaimer on Slide 2 of the deck.Now, please turn to Slide 3 for my opening remarks. Lonestar reported a 33% sequential increase in oil and gas production to a company-record 18,097 BOE a day in 3Q 2019, which compares quite favorably to the second quarter number with a 13 handle on it. Reported production volumes of materially exceeded the company’s guidance of 17,000 BOE a day to 17,500 BOE a day. Production was compromised of – comprised of 67% crude oil and NGLs on an equivalent basis and timely execution of a large number of high-rate wells coming out of our 2019 capital program has driven these results.We also reported a 12% increase in EBITDAX to $37.1 million that EBITDAX performance was overwhelmingly driven by the fact that 3Q production volumes materially see the guidance in spite of some really soggy NGL prices. While our oil differentials have been under a bit of pressure, the oil and gas realizations in the Eagle Ford are still the best in the country.Lonestar’s 2019 drilling program continues to deliver stunning results. I think these results are remarkable in two respects: first, 30-day rates on our oil new wells have been terrific, ranging from over 1,000 barrels a day in Karnes County to nearly 2,500 barrels equivalent a day at Horned Frog South and Sooner and then on a more sustained basis, our 2019 wells are demonstrating continued sustained outperformance versus the third-party type curves, which are the basis of our forecast.The new news, if you will, is that our first three wells and the wells in Dewitt County on our Sooner property, which we acquired late last year, registered Max-30 day rates averaging nearly 2,500 BOE a day and we’re 53% liquids despite a number of constraints, which we’ll elaborate on later in the call. More recently, we brought our first wells on Marquis line – Marquis online. These wells have an average lateral length of about 9,000 feet and tested at average rates of nearly 1,200 BOE a day.We’ve been very efficient in terms of getting wells on stream, having placed 17 wells online thus far, so the vast majority of our capital spending is behind us. Our strong third quarter performance coupled with our robust new completions at Marquis, means that Lonestar will exceed the high end of our already increased 2019 production guidance of 15,000 barrels a day. In spite of the fact that our guidance previously assumed that we would get contribution in the fourth quarter from three very oily and 100% owned Cyclone wells.Accordingly, we expect fourth quarter production to average between 17,200 barrels equivalent a day and 17,600 barrels equivalent a day. Our fourth quarter EBITDAX guidance is $32 million to $34 million with capital spending of $15 million to $18 million that compares to discretionary cash flow of $22 million to $24 million.Lonestar continues to use commodity derivatives to create a higher degree of certainty in our cash flows and returns while mitigating financial risks. The current hedge book is as follows, in Cal ‘20, our oil swapped volumes total nearly 7,500 barrels a day at an average price of just under $57 and equate to very high levels of hedge coverage for the year attractive prices. On the gas side of the equation, we currently have 20 million a day hedged at an average price of just under $2.60, which represents over our half of our expected volumes there. for Cal ’21, we’ve already begun layering on volumes and the book stands at 4,000 barrels a day at an average WTI price of just under $54.Please turn to Slide 4, to do some housekeeping on the quarterly results. As I’ve mentioned already, production exceeded 18,000 barrels a day for the three months ended September 31, 2019, representing a 45% increase year-over-year and a 33% increased sequentially. Third quarter volumes consisted of 7,885 barrels of oil, 4,209 barrels of NGLs, and 36 million a day of natural gas.Lonestar’s Eagle Ford shale assets continue to deliver favorable well realizations. Lonestar’s wellhead crude realization in the third quarter was $58.16, which represents a premium of $1.71 versus WTI. Lonestar’s realized NGL price for the quarter was $8.88 or 16% of WTI. This was largely the result of a very sharp drop in ethane, which fell as much as 70% from first quarter pricing and propane and the other heavy liquids, which fell as much as 44% from 2Q pricing. I would note that we’ve seen a pretty good recovery in NGL prices since the quarter-end. Ethane prices are $0.21 a gallon, up 42% from their lows seen in the third quarter while current propane prices are $0.51 a gallon, up 25% from the lows they’ve seen during the same timeframe.Lonestar’s realized wellhead natural gas price was $2.27 that’s reflecting a $0.11 discount to Henry Hub. Wellhead operating revenues increased sequentially by $900,000 to $53.1 million or 2% compared to 2Q 2019, its higher volumes offset a 24% decrease in commodity price realizations. Our hedge position was fairly neutral to revenues in the third quarter, but as in the money hereafter.Lonestar’s ramp-up in production has generated a powerful reduction in its cash unit-cost structure. Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative expenses, and interest expenses were $26.8 million for the third quarter, and while 3Q 2019 cash operating costs rose in dollar amounts 6% to 25.3 – compared to $25.3 million in 2Q 2019, continued strong volume growth yielded a 21% reduction on a per-unit basis from $20.43 per BOE in 2Q 2019 to $16.09 per BOE in 3Q 2019.I’ll now do a deep dive into all the newsworthy wells, which we brought on stream. It’s really these wells are the driver to our rapidly improving operational and financial results. And I’ll do so in chronological order.Please now turn to Slide 5. We’re going to start of LaSalle County on our Horned Frog Northwest property. The majority of this acreage was acquired here, there’s some relinquishments from our major oil company, who did not meet continuous drilling obligations and Lonestar was able to acquire these tracts for around $1,500 an acre.Early in the second quarter, Lonestar began flowback operations on two gross, two net wells, the Horned Frog number 4H and number 5H. They’re shown in red and the pad location is designated with a red star. I’d like to add at the beginning of the year, we did have a small working interest partner in these wells associated with our ownership and attract that allowed us to drill much longer laterals here. In fact, we were able to execute a trade that allowed us to own 100% of these wells. So, we spend about 10% more money here as a result and we’re really happy about it.These wells recorded Max‐30 day production rates of 1,453 barrels equivalent a day. The chart in the bottom right quadrant shows that through 210 days, these wells have produced communicative volumes that exceed the offsetting parent wells we drilled in 2018 on a per foot basis by 10% and our new wells are still producing 1,000 barrels equivalent a day.Furthermore, these wells are materially outperforming their 1.5 MMBOE third-party type curve and the chart in the bottom left quadrant reflects the fact that the current daily oil rates are 88% above the volumes forecasted in that type curve at this point in time. Not surprisingly, we’re planning on drilling more wells in Horned Frog Northwest in 2020.I want to add one piece of commentary here that will carry through all of my remarks and I want to make sure our audience understands the specifics of our well performance in our production mix. In other place, operators are drilling wells in areas with very limited histories and operators and analysts are regularly being surprised by the oil and gas mix coming out of these new wells in these new areas. These supply – these surprises can have a material impact on an underlying value and the quarterly analytical fire drill in analyzing these factors is interesting to me.In distinct contrast, a very different set of dynamics are in place at Lonestar in the Eagle Ford shale, where there are thousands of wells that provide a baseline for well performance in oil and gas mix. Two factors are driving our results. First and foremost, our quarterly production mix will sway across the year based on the order, in which we drill our wells in our oily areas such as Karnes, Cyclone/Hawkeye and Marquis, and our gassy areas such as Horned Frog and Sooner.In 2019, we’re focused on some of our gassier areas, because the returns are very high and we’ve been working on some very strategic deals in the Cyclone/Hawkeye area, which can dramatically increase the company’s value. And as a result, we’ve not been active in that area with the drill bit in 2019 in this very oily area. Equally important, we’ve taken an extra level of initiative in terms of providing you with an understanding of what’s really going on in terms of well level oil and gas mixes in our drilling area – in our drilling program.I call your attention to the product mix table in the bottom left corner of our activity map on Slide 5. First, we show you the NGL and gas mixes, which are booked in our third-party reserve forecast. These mixes are independently generated by a very smart people, group of people at W.D. Von Gonten & Associates, our third-party engineers, and are based on analyses of all offsetting well histories in each specific area. In this set of slides, we also include the actual oil, NGL and gas mixes based on the cumulative production history of each new set of wells. In this case, we’ve produced much more oil than forecasted by our third party with the oil mix almost 50% and the liquids mix at 74%.We’re able to achieve these results by doing petrophysical analysis that allows us to target specific benches within the Eagle Ford with the most movable oil and as well conservatively managing these chokes to make sure that that production is optimized. I’ll point – I’ll make it a point – pointing out, making a comment about each of the product mixes in each of the areas we discussed today.Now, please turn to Slide 6. On our last call, we showed you the parent wells, the 2H and 3H drilled in 2018, responded well after being hit by the child wells, our 2019 wells, the 4H and 5H wells. We now have another 90 days of production under our belts and it’s still a happy family. We have actual oil production and the Von Gonten type curves in green and the actual gas production in the Von Gonten gas projections in red. The parent wells shown in the graphs on this slide have outperformed their type curves by 14% and are exhibiting the same production trend that they were prior to the offset frac kits.Most notably, oil production, oil recoveries are exceeding their type curve by 44% currently. Then, unlike the Permian or the SCOOP/STACK, where operators are still faced with a difficult task of establishing proper spacing in ZIP code that are devoid a well history at varied spacing. We have reams of data in each of our areas that give us a huge head start in getting that spacing right. On top of proper well spacing, I’d credit our proprietary frac design with these positive parent child results.Please now turn to Slide 7. On our last call, sorry – on the last call, we talked about our 2019 wells in Karnes County, which follows six wells we placed on-stream in 2018 and the company has continued to deliver consistent results here. Our 2018 pads are designated on the locator map in the top left quadrant and the four new wells in red are highlighted with the star. Those are our 2019 completions. By acquiring offsetting acreage contiguous to our existing leasehold early this year, Lonestar was able to increase lateral lengths on our 2018 completions by 18% compared to our 2018 wells and these – but these wells continue to exhibit identical productivity on a per foot basis through 150 days of production, which will yield to improve well economics.Our 2019 wells are performing in line with third-party type curves and our 2018 completions. And in fact, the excess over the type curve has been attributable to extra gas recoveries if you will. I would also note that our remaining locations will benefit from our lease acquisitions and therefore, should all exceed 7,000 feet and Lonestar has an 80% working interest in a 61% NRI in this property. We’re drilling the wells for under 6.5 million a copy recovering 600,000 BOE and plan to follow-up our success here with more activity in 2020.Now, let’s turn to Slide 8. Lonestar’s newest wells on its nearly 5,000 acre Horned Frog South property represent continued progress in the advancement of our geo-engineered completion practices. Our new wells are longest yet at 12,300 feet are shown in red on the map in the top left corner on a combination of legacy acreage and acreage added in 2019. based on some outstanding petrophysical and geophysical analysis done by our team, we actually geo-steered these wells in a fashion that migrated our target from one bench in the Lower Eagleford to another mid-lateral. Consequently, our logs for these two wells have demonstrated the highest effective porosities that we’ve achieved in the greater Horned Frog area and the production results are terrific.On a per foot basis through the first 120 days, our 2019 wells have recorded production rates that are 16% higher than the third-party type curve and that produced 42% more oil than forecasted by the type curve. please note that the actual production mix is almost three times oilier than the type curve, the projected type curve mix. The graph in the bottom right quadrant of Slide 8 shows that our 2019 Horned Frog wells have recorded cumulative production that exceeds prior well sets.Lastly, today, the graph in the bottom left quadrant of the slide demonstrates that our 2019 completions are well ahead of forecast and declining more slowly than forecast. A tremendous result for a couple of probable locations, which were offset by some wells that are not even remotely economic. Lonestar owns 100% working interest and 78% net revenue interest in these wells.Now, please turn to Slide 9. Lonestar acquired in late 2018, we’ve instituted a lot of positive change on our Sooner project. in terms of higher upside projects, our Chief Geophysicist had the 3D seismic reprocessed in depth and has remapped the structure in the area. Our conclusion was that the prior owner saw major faults shown as hash brown lines that do not either prevail an Eagle Ford time or do not have significant throw, which has opened the door for longer laterals. With this knowledge, we’ve leased some additional acreage shown in blue, which sets us up for additional length in the future.In late July, Lonestar began flowback operation on three gross, three net wells on the Sooner property. Their wells are called the Buchhorn 4, 5 and 6. These wells are the first wells drilled here and we’re drilled the total met depth – measured depths succeeding 20,000 feet. The wells were stimulated with average profit concentrations of approximately 22,000 pounds, over 21 stages using diverters and the max 30-day rates on these wells have averaged nearly 2,500 BOE per day.I would also point out that these wells are constrained by several factors. One, we electively reduced the chokes in the third quarter in response to low gas prices; two, the pressures have remained too high to run tubing. So, these wells are registering these flow rates upcasing; and three, we’re also waiting on some line pressure relief with the commissioning of a new 24-inch line in the area.All said, these wells are performing very well in comparison to the third-party type curve. We do think we can improve upon our first efforts here and plan to drill two or three more wells in Sooner in 2020.Now, please turn to Slide 10. If you recall, we acquired the Marquis asset in July 2017 for $50 million cash. Today, we’ve really just focused on cost reduction and product production optimization and in doing so; have cash flow of $33 million from this asset in just over two years. It’s taken two years to get our first wells drilled here and we’re off to a great start.In early October, Lonestar began flowback operations on two gross, two net wells, known as the FMC EB #A1H and FMC EB #B2H. These wells were drilled to an average measure – total measured depth of 19,563 feet. We stimulated them with an average profit concentration of 1,470 pounds and across average perforated intervals of a little over 9,000 feet using some – using diverters and some new processes that we think have been quite additive.Test rates on these wells averaged over 1,000 barrels a day of oil, 90 barrels of NGLs and about 0.5 million cubic feet a day or 1,179 barrels equivalent a day on a three stream basis on a 23/64" choke. Lonestar owns 100% of these wells as well and we’re really pleased with the early results.In the bottom right quadrant of Slide 10, we’ve shown the recent production rates compared to the wells on trend and our wells look really good. thus far, they’ve been oilier than projected at 86% oil and 92% liquids. We have 61 locations at Marquis, many of which are quite long. And after we evaluate these first producers for a sufficient length of time to get a good handle on performance. This is an area that may be opened up for a considerable upside to the company.Now, please turn to Slide 11. for a consistency sake, we’ve included our drilling completion schedule. At the time, we published these slides, 19 of our 20 wells were drilled as of this morning, well, TD, our 20th and last well, the Cyclone 37H. getting wells drilled and completed on time ahead of schedule, concentrated a lot of our expenditures in the late third and early fourth – in the late second and early third quarter, resulting in a surge in 3Q 2019 CapEx. The good news is that the fourth quarter will be by far the lowest capEx quarter in the year.Now, please turn to Slide 12 for my closing remarks. The third quarter represents an extended streak of outstanding results with daily production setting a new record of over 18,000 BOE a day. Again, exceeding guidance and assuring that full-year results for 2019 will exceed our already increased guidance of 14,800 barrels a day to 15,000 BOE per day for the year representing an increase of 35% over 2018 production.The underlying drivers to these results are that our 2018 and 2019 completions or continue to outperform their projections and in the third quarter, we delivered new high rate completions sooner than expected. While our production growth is impressive, growth is not as important as what that growth allows us to achieve in terms of other more strategic objectives.first, in the gas condensate window, our technological advancements at Horned frog and sooner are delivering meaningful outperformance over the type curve with the most notable outperformance coming from oil.Second, in the crude oil window, our 2019 wells at Georg and Karnes County are performing well and our key completions are exceeding our expectations with oil rates of over 1,000 barrels a day and equivalent rates of over 1,100 BOE a day. These areas as well as Cyclone/Hawkeye, which are home to over 100 drilling locations, continued to deliver oil cuts exceeding 90%.Lastly, our production growth has yielded a 30% improvement in the company’s overall cash cost structure. Total cash costs have fallen from $22.76 per BOE in the first quarter to $16.09 per BOE in the third quarter, giving Lonestar a more durable and competitive cost structure.We’ve been very efficient in terms of getting our wells on stream this year, having placed 17 wells online so far. So, the vast majority of our capital spending is behind us. Our strong third quarter coupled with our new robust completions at Marquis means that will exceed guidance yet again, and we’ll exceed that guidance in spite of the fact that our prior guidance assumed that we would get contribution in the fourth quarter from three very oily cyclone wells that we own 100% interest in.Accordingly, we expect fourth quarter production to average between 17,200 barrels a day and 17,600 barrels a day. Our 4Q EBITDAX guidance is $32 million to $34 million. And with capital spending at $15 million to $18 million that compares favorably to discretionary cash flow of $22 million to $24 million.Most importantly, the underlying outperformance of our 2018 and 2019 completions means that we can achieve our 2020 production target of 17,000 to 18,300 BOE a day with fewer wells and less capital spending.Today, we believe that 2020 target can be achieved by drilling between 13 and 19 gross wells and 12 to 16 net wells at a reduced cost of between $90 million and $115 million. Both cash are yield free cash generation, which makes the most sense in the current environment. I think we’ve positioned the company very well to compete effectively in the current environment and continue to build shareholder value.This completes my prepared remarks and now, I’ll open it up for questions.

Thank you. [Operator Instructions] We will now take our first question from the line of Dun McIntosh [Johnson Rice & Company]. Please proceed with your question.

Good morning, Frank and congrats on another really strong quarter.

Frank D. Bracken: Thanks, Dun.

production, we talked about the Sooner well has been really strong, but what really surprised me this quarter was how well oil came in and it looks like the Horned Frog is really the driver there. What is it about those oil cuts that’s got them coming into eyes? Is it geology that’s something you all are doing on the engineering front and what are some of the leverage you all pulled there to really bring that oil cut up?

Frank D. Bracken: Yes. I think a lot of it has to do with really careful mapping of the benches that are prevalent in the greater Horned Frog area. A lot of that mapping is done utilizing some very advanced logs that we’re – that we have at our disposal. And at the current oil and gas price ratios, we’re really focused on targeting our wells in the pieces of the lower Eagle Ford that have the most moveable oil that means they’ve got adequate fourth route to allow us to actually not only encounter that, but have the oil moved to through the wellbore to surface.So, it’s really a lot of science, but it’s also a lot of focus on doing the proper analysis to flow these wells back being very mindful of, in this case, DuPont. if you’ll notice on the production plots, we actually are quote “underperforming” on the gas side at Horned Frog Northwest. When we can produce that much extra oil, we’ll happily defer gas production to a later point in time. And that’s telling you how we’re choke managing those wells, but it makes a monstrous difference in the returns that we’re generating here being able to selectively grab that oil and maximize our intersection with what the oil-rich rock.

Okay, great. Thanks. And then on – looking at fourth quarter and kind of early next year, you got into a sequential decline, but the midpoint of that still puts you over the high end of your full-year guidance. You’re bringing on two wells at Marquis. I was wondering if you could give a little color around activity beyond that in the near-term. Kind of where you’re thinking about folks in early and I know you’ve – we talked about you had brought on a – you’re looking to bring in a new rig kind of some of the cost efficiencies you’re looking to achieve there would be great.

Frank D. Bracken: Sure, sure. So, we actually – we waited on a – we waited on a new rig that is what really caused the delay if you will in the Cyclone wells. But the rig has worked away. It’s what we call a unicorn. It can do everything we needed to do and should allow us to improve our rates of penetration in days drilled over the course of its contract. And we’re able to put it under contract for a lower day rate, that rig – that contract comes up in February and with based on where day rates are today, our anticipation is we can get another rig of similar kind or extend this one at even lower rates. So, continue to hopefully wind down the drill costs associated with the program.We have a lot of moving pieces to our 2020 budget. most of the flex if you will is really going to be related to going to be related to the – what we do in Cyclone/Hawkeye. We’ve been working very, very hard on, what I would call a potentially very significant deal that that would be a farm-in type arrangement. So, no cash out of hand, no incremental capital required, but something that allows us to leg into a lot more drilling locations in an area that we’ve demonstrated expertise.So, we’re going to – we’ve got to let the dust settle on that before we get much more specific about the actual order of drilling operations for 2020 and the mix. It depends on if we’re drilling more wells in cyclone, Hawkeye and Karnes and we are in horned frog and sooner. the results are going to be – are going to look different than they would, if the reverse were true. So, our preference is to not get very specific, but know that we’ve run a lot of different permutations of the budget and still feel inordinately competent with the production estimates that we’ve got out there. I mean, it really doesn’t take a ton of imagination to get there and feel pretty good about what it’s going cost to deliver those results.

All right. Thank you. That’s it for me and congrats on the quarter.

Frank D. Bracken: Thanks.

Our next question comes from the line of Neal Dingmann of SunTrust Bank. Please proceed with your question.

Good morning, Frank and team. Frank, just maybe an add-on to part of that last question more, given that the notable continued improvement in well returns you see in – you’ve continued to certainly highlight here and on the release, but you continue to leverage that you still have, how do you all think about when you look at 2020 or maybe, even beyond that 2021, I’m just wondering sort of that Balancing Act of growth or free cash flow. How do you – I’m just wondering, how do you sort of think about it any different today given the improvement in the wells than it was at the beginning of the year?

Frank D. Bracken: Sure, sure. Look, we’re really happy with the returns that the 2019 program has generated and we’ll review those with the board on Thursday. I would note that they’re achieved despite the fact that we had a lot of pretty gassy liquids-rich wells brought on in the late second and third quarter, which actually – we had peak production at pretty poor NGL prices. So, those returns have been good despite that. look, I think, I think first and foremost, we’ve got to manage the business around liquidity. We want to make sure that we’ve got ample liquidity to run the business and the fortunate thing is that spending less capital next year allows us to expose the shareholders to really good returns and over time, dramatically improving EBITDA and improving debt metrics.So, at the moment, the, the notion that we’d want to consider ramping up beyond a capital program that would yield higher production than that, which is guided, is just something I doubt the board would even remotely consider at this time. So, first and foremost, manage to liquidity and borrowing base availability.

It makes sense. And then you just taught well cost, I guess where I’m going with this is, as I mentioned and you walked through that in the improvement in the results, I’m just wondering, with that, again, as you see sort of the 2020 plan, are you all still sort of walking up more high density completions in all, I guess if you could just talk about how you’re sort of balancing that and do you think you’re at a point now where you actually continue, I mean we’re certainly seeing service costs come down. So, I’m just wondering beyond that, just maybe, talk about that mix. I have to see that sort of making that mix.

Frank D. Bracken: Yes. Service costs of debt, I mean, are steel is cheaper. So, anything that’s made with it’s going to be less expensive. We negotiated a reduction in our pressure pumping rates that are now – that are – that will be effective on the 2020 program. And then we’re actually effective at Marquis and saved us about $300,000 a well and we’ve got better drilling equipment available to us at lesser dollars as well. So, I think across the board, well costs will be coming down. We did make some fairly considerable investments in CDPs at areas, where we’re handling for us big volumes of gas that we’re very happy to handle, but exceeded type curve forecast for sure.I think the bulk of those were behind us. So – and then lastly, a lot of the actual pad locations that we are contemplating for 2020 are required substantially less kind of scratch in infrastructure than those that we drilled in 2019. So, all those factors should land to lower well costs as it relates to incremental prop and I think we’ve kind of generally speaking, found optimize sweet spots in each of our areas. And so my – could we talk more potentially, but I think, the 2019 program really demonstrates some fantastic results that were – that we’d be happy to repeat that at lower well costs.

Very good. Thanks. Congrats on the results.

Frank D. Bracken: Yes.

And our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Please proceed with your question.

Good morning, Frank, and congratulations on the strong quarter.

Frank D. Bracken: Thanks, Jeffrey.

Regarding the cyclone area expansion that you’ve been discussing, can you characterize when you’ll know if this is a go or a no-go and it sounds like that if it comes through, you’re going to get the business drilling sooner than later.

Frank D. Bracken: So let me answer, there are two separate questions or a question in that set position. I think we’ll – my anticipation is that that we’ll be at a decision point within the next 30 days quite handling and trust me the moment we can share that with all of you we’ll do so. And I think, and then as it relates to when we drill the wells that’ll depend on a whole barrage of things. So, I can’t give you any specificity there. I can’t tell you that, that regardless of whether we consummate a transaction or not. Hawkeye will absolutely be back on the calendar in 2020 and prominently so, and simple reason returns are fantastic there. So, it’ll – it was absent in the 2019 program. Clearly, we’ll bring these three cyclone wells on in early 2020 and will bring at least three Hawkeye wells on. I feel pretty certain about that. How the rest of it shakes out or really be a function of getting to finality with the things we’re working on right now.

Okay. Well, that’s pretty helpful color. In fact, the Marquis results were strong and that was something we were anticipating. Knowing it’s – it is early, do you have any sense for the returns on these first two tests might rank order in the Lonestar portfolio.

Frank D. Bracken: I’ll make – I kind of make two comments to you; one, these are wells that, that we think will go on a jet pump really effectively. We’re not there yet. The rates and the pressures are still quite robust. But we’re – these wells are acting like something that once we get them on jet pump, they’ll give us some terrific rate for a sustained period of time and I can tell you the type curve has got a lot of steepness to it though the reason the type curve has a lot of steepness to it is because that’s the way of the offsetting wells drill by other operators have performed. And it’s guesswork at this point in time. So, I’d be as happy as we are about the wells, I’d be with 23 or four days of production, I’d be reticent to go there yet, but I can tell you that after we put the press release out yesterday, I had had inquiry from a competitor wanting to do a data trade. So, you’re not the only one whose curiosity has been aroused.

That’s great. And for our last question, I just want to mention that the press release referenced to issues with line pressures. I mean, it’s the first time I’ve heard about that in Eagle Ford in recent memory. So, I was just wondering it’s just indicative of a lot of industry activity or was it something else?

Frank D. Bracken: Yes. I mean, generally speaking it’s the – you’re exactly right, generally speaking, we’re – we’ll get low line pressures and guys are even starting to take some of the really big horsepower out of service based on lower volumes. This is just a little localized hotbed, where there’s been a lot of recent drilling activity and some kind of long-term plans to accommodate it. I mean, DeWitt County is a busy area for several of the really big voice. So, we’re doing great. You can see in the rates, but we think we’ll actually get some relief once that that all settles out. So yes, it’s just a little local hotbed that we’re in…

Okay. Well, thanks again, and congratulations on the quarter.

Frank D. Bracken: Thanks, Jeff.

[Operator Instructions] Our next question comes from the line of Jeff Grampp of Northland. Please proceed with your question.

Good morning, Frank.

Frank D. Bracken: Good morning, Jeff.

I’m just curious understanding that that 2020 still has some variability as you guys kind of work through some of these land opportunities and whatnot, but is it fair from maybe, a 10,000 foot level to think on the kind of lower end of the range, maybe, that’s a little bit more oil focused activity program in 2020 and that my bias up your oil mix, whereas the higher ends maybe kind of more Sooner-horned frog oriented and therefore, a lower gas mix, am I right to kind of think about it that way or would you have some other, I guess points or caveats, where that might not make so much sense?

Frank D. Bracken: I would – so I would tell you that I don’t, while I would not confirm that assumption, I think it’s – there’s a lot of reasonableness associated with it. But by the same token, what kind of gives us comfort is that we look out at the analyst estimates on production and the EBITDA forecast and we got lots of room to make you happy at this point is really where I would come out on it. So, we’re pretty happy either way, both either end of that spectrum generates free cash. We just have to – we just really got to, we got to work through the details of the budget and get some pretty big issues worked out in terms of where specifically we’re going to drill, because we don’t like to give – we don’t like to give any more specificity until we know which wells precisely we’re going to drill. But I think in general, your basic thought process is sound.

Okay, great. Thank you. And for my follow-up, I was curious if you can kind of give us any kind of update on the potential asset sale of your East Texas assets.

Frank D. Bracken: Yes. So, we completed our Brazos well. The logs were better than the Wildcat well. the wells stimulated better than the Wildcat well, I would tell you. And we’re able to generate really good early rates. We’ve got a mechanical obstruction that we’re waiting on lower pressures to deal with. I would tell you, I think we’re not – we’re producing out of a fraction of the total lateral length right now. We’re going to let those pressures come down, go remediate that well. And then I think at that point in time, would be the appropriate time to launch a formal process. I will tell you that we’ve not been able to stave off all of the – all the inbound inquiry and we have people working in advance with our data on the asset. So, hopefully, it’s just a deferral of that sale and nothing else.

Okay. And if I can sneak one more in here, can you just talk about overall your comfort level with the current liquidity position and any thoughts on buying back your bonds or as liquidity, the kind of a paramount focus as far as the balance...

Frank D. Bracken: Sure. So, what we’ve not been able, what we would have liked to have been able to address on the call is just how the borrowing based review worked out and all that. I can tell you, it just seems like the banks are – have got so many big problems out there that everything is slower than it usually is. We’ve seen this before. City’s engineers have been through it. They actually recommended that the conforming borrowing based number would have been an increase. I think based on the current market conditions, it looks kind of like flat is the new up. If I had to coin a phrase and I think that’s where – then that’s where we’re headed, that process is still ongoing and probably, weeks away from getting settled out. I think more than anything, liquidity is what you’ve got to maintain. You’ve got to maintain optionality to run the business and never get taught – caught too squeaky. So, that is – that’s why you don’t see us even thinking about changing the basic mentality of more limited capital spending in 2020 with a mind toward free cash flow.I think incrementally, we’re going to be looking to – we’re looking – we’re going to be looking to try to improve that, where we may be able to take advantage of a very soggy market for properties. And if we can do that on a very accretive basis with a feathering in of equity, that’s something we’d consider. Because I think, I think, as I look at it and I think as the board looks at it, the returns of what we’re doing are outstanding and they’re – they’ll go toe to toe with anybody in the industry. Our cost structure is now in line with companies many times our size. The only thing holding us back is balance sheet issues. And so we’ve got to be very mindful of those and make sure we do the things we can do to preserve that liquidity.

Got it, understood. I appreciate the comments at the time, Frank.

Frank D. Bracken: Got it, Jeff.

And thank you, Frank. there are no further questions in the queue. I’ll now turn the call back to you. Please continue.

Frank D. Bracken: Well, thanks very much for your time and attention. We’re looking forward to coming back and in a few months and updating you on our progress. Thanks very much.

Ladies and gentlemen, this concludes the Lonestar resources’ third quarter 2019 financial results conference call. Thank you for joining us today. You may now disconnect your line.