Lonestar Resources US Inc.
Q1 2019 Earnings Call Transcript

Published: 13 May 2019

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources First Quarter 2019 Financial Results Conference Call. At this time, all participants are in a listen-only mode. There will be a question and answer session following our presentation and instructions will be given at that time. Please note that this conference is being recorded today, the13th day of May 2019. I would now like to turn the conference over to your host, Frank D. Bracken, Chief Financial Officer. Frank, please go ahead.

[Frank Bracken:]

Well, I guess I got a demotion. Hi, I am Frank Bracken, I am the Company’s Chief Executive Officer. Before we get started, I want to direct you to the cautionary note regarding forward-looking statements, Safe Harbor and disclaimer on Slide 2 of our conference deck. But now please turn to Slide 3 for my opening remarks. Lonestar reported a 46% increase in net oil and gas production to 11,372 barrels a day for the first quarter, compared to 7,777 BOE per day for the three months ended 2018. The volumes were within Company guidance of 11,200 barrels a day to 12,000 BOE a day and were comprised of 79% crude oil and NGLs on an equivalent basis. During 1Q ‘19, Lonestar experienced an unusually high number of instances in which its producing wells were hit by offset frac operations conducted by third-parties. In total, nine of the Company's pads were affected, and a total of 23 of our wells in the Western and Central regions experienced production curtailments related to these frac hits. These offset frac hits resulted in an aggregated reduction of 330 barrels equivalent a day in our first quarter production, which reduced quarterly revenue by $1.4 million and increased LOE by $0.6 million. Notably, and we’ll get into some details, all the wells have since been returned to production in an aggregate or equal to or above their third-party type curves. Our production continues to receive outstanding premium pricing which is the best in the country when compared to any other Shale province. We continue to receive a $2 premium to WTI for our oil and our natural gas trades on par with Henry Hub. While the year got off to a slow start with respect to our first quarter 2019 production results, our drilling program is now kicking in the high gear with six gross, 5.2 net wells having come on stream in the last 30 days, pushing net oil and gas productions to a record 14,000 barrels a day. I want to again commend our technical teams who continues to deliver fantastic results with our geoengineered completion designs. These wells are really important in several respects. Most importantly, the 2019 wells are longer than the 2018 versions and are coming in at much higher aggregated production rates. Importantly, our 2019 wells are delivering the same or better productivity per foot when compared to our 2018 versions. Notably, we are getting these outstanding results on the new longer wells while producing them on the same chokes as the shorter 2018 wells. The icing on the cake is that our longer 2019 versions are coming in at the same costs as we incurred on our shorter 2018 versions. In my mind, our ability to deliver this kind of well result takes a ton of execution risk out of what we are trying to accomplish. Our capital program is on track. Our wells are getting drilled at our forecasted pace and cost and our frac jobs are being executed ahead of forecasted pace and consequently below budget. Our hedge book continues to be a core part of our business and since the last time we talked, we put on some more 2020 oil swaps at prices averaging $60 and starting to build the 2021 book recently top ticking the market at $56.50 a barrel. On our last call, we outlined a two year plan to achieve cash flow neutrality by the second half of 2019 while continuing to deliver production growth rates through 2020 which approximate 25% compounded. The EBITDAX levels that would be achieved would put the company in an excellent liquidity position and at today’s strip would imply 2020 EBITDAX levels of roughly $200 million, which even at the currently pessimistic market for oil and gas stocks today should significantly rewrite our equity value. The most important components of delivering on these objectives and gaining the confidence of investors and our ability to execute on these goals, it’s a demonstrator of ability to go back to our core areas, La Salle, Karnes and Gonzales Counties and repeat and improve upon our groundbreaking results in 2018. As we review these results today, I think you will agree that we are hitting on all cylinders operationally and our new wells in 2019 have pushed production to 14,000 barrels equivalent a day, are establishing a production trajectory that lend a high degree of credibility to our ability to execute on these two year objectives outlined at the bottom of Page 3. Please now turn to Slide 4 to do some housekeeping on the quarterly results. As we discussed, production was 11,372 barrels a day for the quarter, up 46%. Those consisted of 58% oil, 21% NGLs and 21% gas making the liquid hydrocarbon mix 79% for the quarter. The company’s Eagle Ford Shale assets continued to deliver outstanding wellhead realizations. Crude oil price were $56.90, a premium $2 a barrel to WTI. Lonestar's NGL price was $15.60 a barrel or 28% of WTI. This was largely driven by an accrual reversion and a drop in Propane and other heavy liquids prices which fell relative to last year. Meanwhile, Lonestar's wellhead realization for natural gas was $2.91 an Mcf, a $0.01 discount to the Hub. Operating revenues increased by $4 million to $40.7 million between the two quarters, where a 46% increase in production was partially offset by a 35% decrease in commodity prices. In 1Q19, Lonestar continued to demonstrate progress in scaling its business to make it more competitive, delivering an 11% reduction in per BOE cash operating costs outlined below. Total cash expenses, which includes the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administration, and interest expenses were $23.4 million for the quarter and while cash operating costs rose 30% year-over-year, Lonestar's 46% increase in production yielded an 11% reduction in cash operating expenses per unit, reducing total cash operating expenses to $22.76 per BOE in the first quarter. Now please turn to Slide 5. The oil and gas business is full of risks and uncertainties. In our case, we had some frac hits that were unplanned – sorry, which were planned such as the ones that we incurred at Horned Frog Northwest and those are all we’ve accounted for in our guidance as the fracs on our new wells are completely within our own control. We’ll highlight those results shortly. However, when offset operators’ frac near our pads, we have little to no warning and it’s hard to budget. Slide 5 shows the impact of these frac hits during the 1Q ‘19. The Company experienced unusually high number of instances when this occurred, a total of 23 wells in our Western and Central regions were hit. These offset frac hits resulted in a reduction of 330 barrels a day for the quarter. Notably, as you can see in the chart provided below, these wells have since been returned to production and are producing at or equal their third-party type curves and have fully resumed the productivity that they exhibited prior to those frac hits. We believe that our completion designs and production practices which are not observed by most of our competitors are the secret to our ability to achieve this kind of resiliency in well productivity. We are able to reestablish rates very quickly based on the types of artificial lift we are using which allows us to address [fluid] [ph] loading in these hit wells and promptly return wells to production. Our ability to maintain type curves is really driven by our frac design which allows us to retard the denigration of our near wellbore frac packs as we’ve not had a core – had to perform a [coiled] [ph] tubing clean out for frac sand and an offset well in five years. Please now turn to Slide 6 to discuss our recent well results and upcoming completions. Slide 6 focuses you on our Karnes County asset where we continue to deliver excellent production results. Lonestar drilled our first six wells here on two pads which are labeled A and B with excellent results. The graph in the bottom left quartile of Slide 6 shows you where our third-party EURs per foot rank compared to all the wells drilled on the offset acreage. This reflects top-decile performance. If you focus on the wells fracked with 2000 pounds of proppant or more, all of our wells are in the top half of all wells and are in – our two of the top five results. In this case, this ranking is acceptable to us and that all the other offsets completed with 2000 pounds of sand were completed by EOG Resources perhaps the top operator in the play. Late last year, we acquired some acreage immediately south of our original lease block which allowed us to drill wells that are 18% longer than those that we drilled in 2018. Despite the fact that these wells are longer, they cost exactly what our 2018 wells cost us. Our new four well pad came onstream about a week ago using our geoengineered completion package and have now flowing back – flowed back 3% of our frac load. These wells, the Georg 3H through 6H are shown in red on the map and are producing at average rates of just under 1400 BOE a day making them the best wells we drilled in Karnes County and our entire central region for that matter. The graph in the bottom right corner demonstrates that the IP24s on these wells are very much in line with our 2018 wells on a per-foot basis. What this chart doesn’t tell you is that these rates are being achieved on the same chokes is our – is the short wells that made those rates which is really impressive. I also might point out that our B pad, which exhibited lower IPs are actually the higher reserve wells today. So, not to get too carried away with the IP results. Please now turn to Slide 7. Lonestar has built the 7400 acre position in our Horned Frog area and our Horned Frog northwest number 2H and 3H wells drilled in 2018 were breakout wells for us. We paid particular attention to targeting here and those wells shown in black and labeled accordingly have third-party EURs that are a 100% higher than the offset well average equally important is the fact that our oil EURs are 146% higher than the offset well average shown in the bottom left corner of Slide 7. Also noteworthy is these wells are materially outperforming our type curve. We will show you a little detail on that. Recently, we completed two new wells, which have perforated intervals averaging 9700 feet so they are 22% longer than our 2018 versions yet with our current pressure pumping contract and drilling efficiency are expected to cost the same as our 2018 wells. Our new wells are producing on 26/64 choke at nearly 1500 BOE a day each as depicted in the bottom of slide – bottom right-corner of Slide 7, which is considerably higher than our 2018 copies. Incrementally, we think we are delivering slightly better productivity per foot from these wells indicating that we can drill long laterals without diminished productivity on a per-foot basis. I’d also add that these wells are just a little bit oilier than last year’s wells. Now turn to Slide 8. A lot of investor attention is placed on so-called parent child relationships, particularly in the Permian Basin as of late. My own high-level commentary is that, because so many operators in that basin are in the mode of HBP leasehold, a lot of one well pads are being drilled which will generate unbounded recovery of hydrocarbons and perhaps inflate expected well results. As these operators are following up with offsets, a number of challenges are presented and investors have felt the pain when those challenges are not properly addressed. For Lonestar, in the Eagle Ford Shale, we are starting out in a much better place. There are usually hundreds of immediate offsets for us to valuate in similar rock which is instructive in terms of developing best practices on well spacing before we ever spud a well. Incrementally, because we are gathering so much petrophysical data in pilot holes and in our lateral logs, we can model rock properties to optimize our frac designs as it relates to spacing. Since we had plenty of warning, if you will, about our fracs on our new Horned Frog Northwest wells, we can shut our parent wells and in advance of fracking these new wells or in other words, the children wells. You can see that we lost production for up to 30 to 40 days on the parent wells, the number two and number three, then brought them back online after the new fracs were completed. The two came on first due to gas slippers constraints within our system and as you can see, it’s producing at rates that are higher than – before the well was shut in. The 3H whose production history is shown in the bottom of Slide 8 came back online about a week later and is responding well with both current rates for oil and gas production higher than when the well was shut in. I would also note that not only have these parent wells recovered beautifully from the offset frac, but these two wells are crushing the year-end projections which are expressed as dash lines on the graph. Now please turn to Slide 9. Our 2018 wells in Horned Frog, the G1H and H1H were drilled on our original Horned Frog lease block and were the first two wells drilled here with our geoengineered completion techniques. These wells which averaged a little over 11,000 feet in length have generated a 58% improvement in EUR versus our 205 wells, this graph in the bottom right corner of the slide depicts that clearly. Recently, we have completed a pair of 12,000 foot laterals shown in red on the map in the bottom left corner on a combination of legacy acreage and recently acquired acreage. These wells are expected to cost the same as our 2018 models despite being longer and despite our plans of increased proppant loading. We’ve run through that logs on these laterals in these wells – on these wells and while these wells are categorized as probable in our year end 2018 reserve report, there is nothing probable about them based on outstanding geosteering that we’ve done, which has actually allowed us to migrate our target zone into a second benched lower Eagle Ford. These wells have the highest calculate effective porosity that we’ve achieved to-date in the greater Horned Frog area. Based on our EURs in the third-party report, these wells are expected to generate 67% internal rates of return at $55 and 275. We plan on commencing fracture stimulation operations imminently and we expect these wells to be on July 1st and we are looking forward to turning these wells to tanks. I’ll now ask you to turn to Slide 10. We’ve been on center for about six months now. We’ve instituted a lot of positive change, particularly at the field level in terms of operations with negligible capital outlay. But in terms of higher upside project, our chief geo businesses has had the 3D seismic here, reprocessed in depth as remap the structure in the area. Our conclusion is that the prior owner saw a major faults which were shown as hatch brown lines which do not prevail in Eagle Ford for the time and has opened the door for longer laterals for us. Our initial wells are being drilled on existing leasehold, but are now projected to be in excess of 6,000 feet or about 20% longer than what we anticipated when we purchased the property in the fourth quarter. The returns detailed on the bottom left corner demonstrates the significant upside to returns that we can generate with longer laterals at sooner. We are in the second of these three laterals now and expect to have these wells on in the third quarter. These wells are the deepest wells Lonestar has drilled to-date and we are excited about getting them online. Please now turn to Slide 11. The top chart shows you that we ramped completion activity in the second quarter more than tripling the lateral feet brought online compared to the first quarter, which has resulted in net oil and gas production eclipsing 14,000 barrels a day. You can also see the third quarter is going to be a very busy quarter for us as we expect to bring on new wells at Horned Frog sooner and Marquis as shown in purple and both the drilling schedule and activity map below, than in the fourth quarter we will bring new wells online in Cyclone Hawkeye, and Brazos shown in orange. Completion of these wells should not only allow us to deliver on 2019 guidance but give investors a lot of visibility into the expected rates that we guided to for 2020. Now please turn to Slide 12 for my closing remarks. After a slow start, we are out of the gates and reestablished the kind of growth and production that our shareholders have become accustomed to. The key to our two-year plan to generate 25% growth in production while achieving cash flow neutrality is predicated on repeating the outstanding well results that we established in 2018 on our core areas in La Salle, Gonzalez and Karnes Counties. The well results we’ve reported today in Horned Frog and Karnes underpin our ability to deliver the same or better productivity dewed in longer laterals, deliver well costs that are on budget, which results in excellent returns on capital invested. Our 2019 program has a lot of momentum as we bring on another round of completions in the third quarter and in the coming months for that matter, I am confident that our financial results will begin to really establish a bigger, stronger, more profitable Lonestar. That concludes my prepared remarks and I’ll now turn it over to the moderator for any questions.

[Operator:]

[Operator Instructions] We will now take our first question. Our first question comes from the line of Ron Mills of Johnson Rice. Please go ahead with your question.

[Ron Mills:]

Good morning, Frank. A quick question just on and one of the last slides you talked about completion cadence in the lateral feet, the timings…

[Frank Bracken:]

Yes.

[Ron Mills:]

Of that, is there been any change in the original plan? Is this the way the schedule was always designed? And can you maybe provide just a little bit more color in terms of – we think about the timing inter-quarter, you talked about the visibility into 2020, kind of how that – how this pace of completions really increases the confidence in your 2020 numbers?

[Frank Bracken:]

Well, yes, I think it’s – so, the cadence is same – is the same in terms of kind of the general rate at which we’ll complete wells. We have wiggled some things around, for instance, we moved the Marquis wells in front of the Cyclone wells, one, because that leasehold was ready to drill, two, because we are working on a number of things in Cyclone Hawkeye that should optimize the wells we actually put on the schedule. And so we wanted to buy ourselves some time there. But in aggregate, I think with the position we are in and as I said, at 14,000 barrels a day, with really only a fraction of the lateral feet brought online, we’ve got a lot of dialability. I think, we are really almost in a position of luxury and that we can play with when we bring wells online to optimize CapEx-to-cash flow ratios, things like that. So, we are not for long periods of time, but for short periods of time, bringing – establishing a little bit of a duck inventory, if you will. And the good news on that is it allows us to line out our frac spread and just move from pad-to-pad-to-pad and develop really efficient operations. But I think the reality is, is most of you guys do responsible math yourself included. And you know, the bottom-line is, by the third quarter, the rates that we ought to establish are rates that are giving you lot of comfort that 2020 is almost in the bag. So, we are in a pretty good spot here. We are out ahead on the drilling schedule. We are taking a paced approach to the way we complete the wells so as to not put too much pressure on the CapEx line. And we are in a good spot. I think the results are showing that they are – they can be repeated and as long as we do that, [indiscernible] was going to work out really well for production growth rates as we go through the year and exit into 2020.

[Ron Mills:]

Okay. And on the pullback side you talked about flowing them back using more of a choke management process and despite that, your - kind of the productivity per foot is still at or above the older wells. Can you talk a little bit more about what you are doing? What you are seeing in terms of the early data in terms of the rate of decline versus the older wells?

[Frank Bracken:]

Yes, I mean, and I would say, really, really early days, but we base all of our flowback methodology on some analysis that we do that allows us to calculate sand [base] [ph] pressure, changes in sand [base] [ph] pressure and whether we are in fact still flowing back and contacting new reservoir or whether we are – and when we transition into bounded flow, which means we are starting to deplete the area that we stimulated. And so, those technical considerations combined with where we are relative to dew point or bubble point are really what drive our process in a vacuum. We are just trying to optimize recovery, make sure that we don’t flow sand back by flowing wells back too hard. And so that really drives the process in most cases. So, but I can tell you that, in aggregate, we are – we feel like our – the pressures that we got are showing that we made improvements in recoveries while not necessarily manifested in the daily flow rate, because of our willingness and at Horned Frog Northwest in this case to just leave these wells where they are because they are performing so well. In the case of Karnes, we’ve got some limitations within our [Amie] [ph] plant and even in the line that we deliver gas to that has caused us to take a little more measured stance in terms of opening these wells up. So there is sometimes some nuance. But we are trying to manage these sort of to maximizing EUR. The fact that the headline rates come out so nice is gravy.

[Ron Mills:]

And then, lastly, can you talk anything about efficiencies? Whether it’s frac efficiency, stages per day or anything on the drilling side, because you are drilling these wells quite a bit longer and still maintaining last year’s cost structure. So, just a little bit of color on those efficiency rates?

[Frank Bracken:]

Right. So the rig costs are same essentially as last year and our drilling days are, I’d say in aggregate been dead on with AFE. So that’s – and that’s the smaller dollar side of the equation these days. Where things have improved is, on the stimulation side. Based on our experience last year with a different vendor, well actually every vendor, we tend to – our stages are massive. They are 3.5 hour stages probably on average. We have budgeted four stages a day. Based on some really good work that our completions manager does in terms of properly preparing the frac crew, and frankly credit to Schlumberger. They have broadened the spread and really delivered fantastic results and we are getting five stages a day done consistently. What that means is, is that, we’ve got – we get off the job sooner. We have fewer rentals that we incur on a daily basis. So, costs are coming in better than we expected on the completion side. And that also means that we get the wells on sooner. So, lot of really positive execution facts on the biggest – the single biggest ticket in terms of cost on the well.

[Ron Mills:]

Great. Thank you.

[Operator:]

Thank you. Our next question comes from the line of Neal Dingmann of SunTrust. Please go ahead with your question.

[Neal Dingmann:]

Good morning, Frank. Frank, on the prepared remarks, or I guess on the press release I should say, you definitely referenced several times about being able to kind of - to dovetail to Ron’s question about taking these wells and doing a little bit longer, I think you mentioned, on a couple of these that you are 50% longer than the first pair. And another one I think, you are the longest, yet I am just wondering, when you look at some of the efficiencies maybe that Ron was alluding to, does that entail if the lease permits taking these things continue maybe if you could just talk about your preference on, how long laterals and design of these wells?

[Frank Bracken:]

Right. And we’ve gotten a absolute industry-leader in our drilling manager and he is worried about torque and drag calculations and making sure that we can efficiently get the bid to TD, so. We let him do the science and that really drives a lot of our process, but I can tell you this that where we continue to move the envelope out, the wells that we will drill at Five Mile Creek which is in the Marquis area are going to be 13,000 feet and that’s because the leasehold the wells at and it’s also because the calculations say that that we can do that with efficient rates of penetration and cost. So, we do have limitations I think, probably most realistically in terms of how many - how far we can get coil out and effectively drill out plugs without incurring mechanical risk. But, we keep inching it out and I think what we’ve established is, wherever we can go long, we’ll go long. It just makes for a better well returns in this price environment and it does yield some efficiencies across the board in terms of well drilling cost, completion cost, et cetera. So, we are nudging our way out as the year goes on.

[Neal Dingmann:]

Okay. And then, Frank, moving to Slide 5, I think you addressed that well. I am just looks like for the struck down on this corner, I don’t know if there - the concern is about an additional frac hits like this. I mean could you talk about, maybe what impacted first quarter and your thoughts – you’ve obviously looking to Slide 11 got a pretty robust plan for the remainder of the year. Just your thoughts about incurring more of these?

[Frank Bracken:]

Yes, so, a couple of things. One, since you mentioned it, I think the stock price reaction is 100% related to the fact that we have certain analysts who somehow don’t seem to trust us. We put out guidance. We have a lot of knowledge about what we are doing and when wells come on and at what rate. And we had one analyst out of guidance as of this morning and two that were out of guidance at 60 days after published guidance. So, as they bring those estimates down coming into earnings, that penalizes us for their lack of industriousness. So, I want to make that clear. I think that’s the overwhelming driver to this process. As it relates to everything else, we have never seen that kind of – I guess, the good news is, is that, if this is – there s no way we can have that many wells get hit all at once. I think the math is just too hard. They happened on a lot of our – frankly, they happened on a lot of our smaller lease blocks where really small lease blocks. So, those little blocks have a lot more chance of getting hit by somebody else's well, than some of our real big wise blocks like we have at Karnes and Gonzalez and Cyclone Hawkeye and Horned Frog where we have enough acreage that we buffer ourselves. So, I think the probability of having anything like that happen again is pretty slim. As it relates to our own wells, we know what the schedule looks like. If there are offset wells, we budget that they get shut-in for 30 days and then draw on in an orderly fashion. So, I think we’ve got much better control over what’s going to impact us over the course of the remainder of the year. And don’t have both – even within our own program, don’t have nearly the direct offset vulnerability if you will, compared to what we incurred in the first quarter. I mean, what I kind of elaborate on that, the two Horned Frog Northwest wells that we shut-in were doing pushing 550 barrels a day and almost 3.5 million a day of gas and that’s 100% working interest stuff when we took them offline. So, that’s – those are big wells that we went and offset with child wells. And it gets in a way you kind of take you could be – if you didn’t know what you are doing taken some risk, going and banging those wells direct to offset. But as the slide shows, the recovery and the productivity has been fantastic. So I don’t see nearly that many direct offsets in the remainder of the schedule that we’ve incurred here today. And if – and even if there are some, the productivity associated with those parent wells is de minimus in comparison to the 14,000 barrels we are producing today.

[Neal Dingmann:]

Okay. And then, one last one if I could, Frank. Your stock, it doesn’t seem like you're getting rewarded for the free cash flow positive that I think we get you even as soon as next quarter, you definitely to me demonstrate you’ve been able to do that. If that’s the case, I think you are rewarded for that and you certainly have ample inventory, maybe just in broad terms, Frank, could you discuss thoughts about adding activity or how you look at it from a broader view as far as operating relatively within free cash flow versus growth?

[Frank Bracken:]

Yes, well, I think, more than anything, there is a base of cost associated with doing this business, whether it’s the people we hire here to run the operation. It’s our interest, - it’s our interest expense and the cost of running the field and those are really fixed and to lift production, the levels where your margins expand, and you develop much higher levels of profitability, that’s kind goal one. And I think that, we are well on our way to doing that. I mean, you will see massive expansions in EBITDA and margins, if you will over the course of the next two quarters, but I think, what we're really trying to get to is a place where we are on a sustained basis, cash flow neutral. And I think, frankly, 25% growth is a lot. I don’t feel like, the market will pay us for any more than that. And I don’t – and I think the market will penalize us in this environment if we actually outspend cash flow to exceed that. So, our own views are that, within that construct that our equity is better rewarded by either A, paying down debt in that environment which we would plan on doing in the fourth quarter. But also, begin to review if this kind of nonsense continues, we can make a lot of money for our shareholders buying back some stock. And that’s I am not announcing anything. But I can tell you, that’s something that the Board will consider on an ongoing basis as an alternative place to put the kind of capital you are suggesting might go to the drill bit.

[Neal Dingmann:]

Makes sense. Thanks, Frank.

[Operator:]

Thank you. Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Please go ahead.

[Jeffrey Campbell:]

Hi, Frank.

[Frank Bracken:]

Hi, Jeff.

[Jeffrey Campbell:]

When I look at the guidance comments, this starts similar to Slide 11 in this presentation. When I look at what you put out in the fourth quarter, back in the fourth quarter, you showed a 17 well drilling program and now - and a 20 and now we’ve got a 20. So, I wanted to ask you what informed going with the 20. And also when I look at the completion cadences, it looks like the first quarter was as planned and then, the second quarter now is less than the previous plan in the third quarter is much more than the previous and then the fourth quarter is a little bit lower. So I just wondering, trying to get your thoughts on how the completion cadence was altered and also what encourage you go for 20 wells?

[Frank Bracken:]

Yes, so, I think more than anything, our ability to – through the first five months of the year, drilling complete, the number of wells that we did on time and on budget. So, you always guard towards, can we get our fracs done on time and on budget. Can we get the wells drilled without any mechanical snappers. So the machine is working really well. And I don’t think the delta between the 115 or so we would spend at the lower well cost really makes a whole bunch of difference versus the 130 or so, we’d spend at the higher well count, sorry, not well cost, well count. So we are buzzing along. The other thing that’s a little uncertain on the incremental three is that the Cyclone Hawkeye wells at the moment have a fairly ambiguous working interest. We are talking to our partner who would be Marathon about which wells we drill and so there is some flex there, as well. So, 17 to 20 in gross terms doesn’t necessarily have the same impact on CapEx. So that’s the big picture for the year comment. With some granularity, we have the Horned Frog wells scooted back the two Horned Frog wells that we drilled on the original block, scooted back to July 1. So that’s what caused that surge in third quarter activity. I think the – if I was a betting man, I think, we get them on before that, but we try to, we want to try to be – we want to try to make sure we hit those as we set them forward. But, they don’t just – it’s just wiggle between a quarter on when those wells get done.

[Jeffrey Campbell:]

Okay. I appreciate that color. People are kind of talking about in a negative way, but I thought it was noteworthy that LONE manage to stay within guidance despite all this offset production losses. I was just wondering, was this just emblematic of your ability to create a good forecast or was there anything with regard to well performance or maybe the decline rate that contributed to staying within the numbers?

[Frank Bracken:]

Yes, well, again, there is kind of two layers to that. When you have three guys that are – when you have only eight analysts, three guys that are outside of guidance, I mean, we are from the day we put out guidance, that makes meeting guidance really tough. So we are fighting against that. But, look, we had a great track record in 2018 of actually exceeding guidance. And look, it’s not really – it’s not our game to sandbag anybody. Our intention is to set out guidance really within the balance of where we think we can deliver with a little bit of jaundice eye towards within the bad things that can happen to you. And I would tell you that I think, while our wells are coming on exceptionally, when we come out the top-end of guidance, it’s really because we’d executed in a timely fashion that we’ve brought wells on sooner than we anticipate. All kinds of things can go wrong and we tend to take a pretty risk view of when wells come on. So, and that’s by the way, that served us well, because, you know, things happen all the time. Weather impacts us in terms of building pads and getting equipment in and things like that. It’s been raining of help in South Texas so far this year. So, we are - I think we are back on track to deliver a result that makes every analyst happy. And we’ve kind of rebuild that momentum that we had. But yes, look, we plan for steps to go wrong and sometimes that happens in spades and sometimes we avoid any of the extraneous things that can go on. So, we just got bit lot of at this quarter. But I think as the current rate suggests, we’ve got that in our rearview mirror quite nicely.

[Jeffrey Campbell:]

Right. And just real quick, because it came up in your conversation today, you mentioned that the larger acreage positions have lower potential for us to hedge, because it’s sort of mote because of the larger position. I was just wondering, do you actually consider things like that when you are choosing locations to develop within any of the larger blocks? Just, do you consider the potential for offset activity when you are making those choices?

[Frank Bracken:]

Yes, we try to think about all those things. And the mote analogy is a good one. I am going to steal that from you.

[Jeffrey Campbell:]

You can have it.

[Frank Bracken:]

Yes, we try to think about all those kind of things. And you know, in certain cases, some of those things are behind us. If you look at Karnes, we are pretty well offset on our Eastern and Western blanks. So we are pretty impervious there. The Horned Frog block, we’ve really got them established book-ins there. So most of what we’ll be doing, we’ll be inboard of that and we’ve got great control over that. Cyclone Hawkeye is a little different, but our acreage position is so vast there and so contiguous that it’s really hard to see who it would be that would come offset ask and get in our hair. So, yes, the three big areas have big motes around them, whether it’s from prior operators already having drilled the near lease offsets or whether it’s us having done that and kind of blocking everybody else out in the tank.

[Jeffrey Campbell:]

Okay, great. Thanks, I appreciate it. Keep this stiff upper lip.

[Frank Bracken:]

Thank you, Jeff.

[Frank Bracken:]

Thank you. Our next question comes from the line of Jeff Grampp of Northland Capital Markets. Please go ahead with your question.

[Jeff Grampp:]

Good morning, Frank.

[Frank Bracken:]

Good morning, Jeff.

[Jeff Grampp:]

Thanks. I had a question for you on the 2019 and then 2020 outlook. It sounds like, from a prior question and to jumping that a bit to accelerate that at any point of time. So I just wanted to confirm, if you think it’s fair to assume in a higher oil price environment, that would just be more, I guess, an event to accelerate the deleveraging path and maybe pay down some debt. And I guess, just trying to more narrow in on, what level of interest you have in flexing the program up or down?

[Frank Bracken:]

Well, the good news is, we always enter into contractual agreements that allow us to flex it down. That’s important to us to be able to always do. The hedge positions that we put in place, try to mitigate the probability of that occurring. But within the confines of the existing asset base, I just don't – we just don't see the utility in wanting to push any harder than 25% compounded growth. And the only reason we are getting that number is because, once we get this thing kick-started back, we see the ability to do it with internally generated funds. And that just speaks to the returns we have. So, I think the market will pay and there is a point in time, we really going to care about where your share price is because it affects a lots of the things you are going to do. In this case, I think the market pays us a lot more for deleveraging or executing small buybacks than they do hit in the gas any harder on the capital budget. I think those are diminishing returns.

[Jeff Grampp:]

Yes, I agree on that and I appreciate that commentary. And for my follow-up, on the Marquis, Sanchez assets that you guys are putting a couple wells on, can you just talk about, I guess, completion plans there and then maybe it’d be helpful to compare, contrast, what you are looking to do versus prior generation wells from the prior operator and when you kind of take a step back, how do you view the competitiveness of this asset or I guess, anticipated competitiveness and longer-term plans for this asset in the portfolio?

[Frank Bracken:]

Yes, so, we spent – we’ve owned this asset for 21 months now and have returned in cash flow well more than half of our purchase price. Yet have PDP PD 10 that isn’t too short of our purchase price. So, we’ve done that through production optimization, through lease operating expense reductions, without really having put the bit in the ground. So, that’s been a good first step for us in assimilating that asset. We’ve done an awful lot of work and we’ve had the luxury based on the other areas that we have to drill. Really examining how well spacing and geotargeting influences well results in the Marquis area. And so, these wells are – and the plan to drill – and drill and stimulate them are very well informed. We think we have the spacing right. We think we are picking pretty good rock to get in and we are drilling really, really long laterals. So, all those things should come together. And if we do what the third-party report says, we’ll have good results. If we kind of go re-rate the asset out here, we can generate returns at Marquis that are really competitive with the rest of the program. And you may see, if that all comes to pass, this will be a steady diet for years to come. We got lots of locations out here.

[Jeff Grampp:]

All right. Appreciate those comments.

[Operator:]

Thank you. Our next question comes from the line of John Aschenbeck of Seaport Global. Please proceed with your question.

[John Aschenbeck:]

Good morning, Frank and thanks for taking my questions.

[Frank Bracken:]

Got it.

[John Aschenbeck:]

So for, I just wanted to follow-up on the Eastern Eagle Ford test you have coming up here. I know, you have talked about previously that you could do some pretty interesting things with that test and so possibly pick up some additional acreage as well. I was just curious if that’s still the plan? And then, also curious how you view that assets long-term fit into your portfolio, just because I know mentioned it as possible monetization candidate at one time, just wondering, if that view has changed at all? Thanks.

[Frank Bracken:]

Yes, so, we have – our Wildcat B1H well, I think reset the bar out here. That well is coming up on a 0.5 million BOE of cume production if I am not mistaken. We believe we have the recipe to repeat that. And it’s our geoengineered completion. It’s the targeting – it’s the target we pick. It’s the style of frac we put on it. It’s the way we flow the wells back that all contributed to the success of that B1H well. This is an asset that – this well we think it gives us the best shot to replicate those results. Rocks pretty similar. We can drill 10,000 foot lateral here. And in our minds, this well is the well that really establishes a trend of this kind of productivity. I think, my view on this asset hasn’t change one iota. We think that this money, whether this asset is sold to reduce leverage or redeploy through additional acquisitions in our Central or Western areas. We think it’s good portfolio management to refocus the capital associated with this asset back into the guts of the play. We don’t - we have some running room, but not immense. There are a number of big companies involved here and lots of smaller private equity-backed strategies that we think are better equipped to – from a returns perspective to handle this acreage. This is – at the end of the day, this doesn’t compare to the returns we are able to generate in the Western Central. And so, the best use of what dollars we have is to shuffle portfolio and trim this up and kind of recenter ourselves in the traditional part of the play.

[John Aschenbeck:]

Okay, understood. That was really helpful. And then, for my second one, all the color you provided, does update just on your parent-child learnings with your most recent tests on your Northwest Horned Frog acreage was really helpful. I was curious, apologize if I missed this too, but your upcoming completions on your legacy position, is there anything you are looking to accomplish with those or just learn with those, any color there will be helpful? Thanks.

[Frank Bracken:]

Yes, so, one of the things that our geoscience team has just done a spectacular job out here of really doing some very detailed sub-surface geology and in fact identifying three very different species within the lower Eagle Ford. And depending on where you are regionally, the premium target, the premium species, they change. They migrate with depth in kind of simple terms, they’ve also integrated the 3D seismic into our mapping and steering and what we were actually able to do with these two wells that we’ve got TD is, move from our traditional Horned Frog target that we put the G and the H into and actually about half way through the lateral migrated up into a higher target. And in doing so, kept the wellbore in optimal porosity. And in fact, the two wells – these two wells from start to finish in aggregate have the highest average effective porosity that we’ve ever achieved out here. So, lots of rethinking and rethinking and use of a lot of science to go get the best results possible.

[John Aschenbeck:]

Okay, great. That’s it for me. Thanks for the time.

[Frank Bracken:]

Thanks, John.

[Operator:]

Thank you. Our next question comes from the line of Stephen Levitan of Scott’s Cove Management. Please go ahead with your question.

[Stephen Levitan:]

Good morning, Frank. I have a different topic. Wanted to talk a little bit about the S4 that recently became effective and what that implies in terms of your acquisition strategy? Under what circumstances you would use stock as currency? And just generally, how are you thinking about those things, given where the stock is today?

[Frank Bracken:]

Yes, well, that’s kind of simple. Right, I mean, the stock is no place I like it and I promise you when our windows were moved, you will see me back in the market as I was prior to the blackout period buying the stock. So, the S4 should be thought of as a – as just a logical, intelligent tool that every public company should have in its kit. That allows us to issue stock for assets and frankly, we had to meet some market cap and free float qualifications to do it. And so, when those boxes were checked, we were able to file it. There is nothing coincident in the timing as it relates to what it is we have on our books to do right now. It's just something that we felt like in conjunction with the S3 which again, everybody who can have one or to have, it’s just a tool in our kit that our GC got pushed through the system and you ought to have that flexibility to use that if the right circumstances present themselves.

[Stephen Levitan:]

Okay. Could you talk a little bit more about what the basic acquisition strategy is at this point?

[Frank Bracken:]

Yes, so, globally, we’ve made four acquisitions. Two of them were data room processes, two weren’t. Our track record and the data room is, I think we’ve been successful twice out of 90 somewhat attempts. We didn’t got the good ratio. But in all four cases, they will really have two sellers. Two of them were under financial duress. One of them was a private equity-backed strategy who broke their pick with their first well. And then, most recently, Sabine represented a basin exit. So, that Board had made the decision, they were going to leave the Eagle Ford and I think when people leave for strategic reasons, they become less price-sensitive. So, we tend to want to buy from people who have to be sellers, not thinking about being sellers at the right price, because we never seem to transact there. Look, I think the most important component of what we will do, and look, the kind of the sad part of the equation is, there is some really interesting things out there right now and there are people who have to sell. But the bottom-line is, as we can’t consider making acquisitions that impair our liquidity or denigrate it any way, or diminish balance sheet ratios, we do want to get bigger. But we got to be methodical about that. So, I hope that’s an adequate answer for you.

[Stephen Levitan:]

Yes, thanks.

[Operator:]

Thank you. Our next question comes from the line of Jerome Pallor. He is a private investor. Please go ahead.

[Unidentified Analyst:]

Yes, so, I’d say, my question just got answered with the shelf registration, because, as a private investor with the stock at the multi-year low, this call kind of reassured me in terms of how you see stock issuances. You are issuing up to a 100 million shares at this point would be basically a market – it should be a total recap with huge dilution. It would help clean up the balance sheet to some degree. So, I was also curious what would trigger this and what you are seeing out there. You’ve been extremely successful with tuck-in lease acquisitions and I was thinking more of the same. In terms of Board decisions and when you see the debt situation not improving, it’s still now we are at $450 million on the balance sheet and adjusted EBITDAX $150 million, - $140 million, $150 million for the year. So, it would back to three times leverage, you are hedging now 2021 at $55. Pricing of NGL’s went down quite a bit this quarter, I don’t know if you can hedge that going. Generally speaking, I am trying to see what’s – on the operational front, I always think this company does an amazing job and yet somehow communication with the market has been difficult to try and reflect that in the stock price. And so, I am trying to get a sense of what the Board discussions are in terms of trying to get the stock revaluated. Right now, it’s almost placed for bankruptcy. And so I am trying to get a sense here of what you can do going forward beyond what you have been doing up to this point. And I would note that the equity portion of management’s compensation is pretty low. You keep on saying every quarter, on every call that this stock is undervalued, that you should go out and buy and yet when I see the proxy statements, I see a huge – you – you have base, you have bonus. The equity portion is actually quite small than I was hoping that going forward, you would signal to the market, your commitments just like you’ve done with some of the open share – sorry, open market purchases on your own. And I am trying to get a sense of what’s the urgency here to try and get the stock to reconnect to fundamentals.

[Frank Bracken:]

Right. Well, so, let me try to address that in some layers.

[Unidentified Analyst:]

Thank you.

[Frank Bracken:]

So, first, the 2018 proxy really reflects last year’s equity awards. I can tell you that the most recent compensation as it relates to the current bonus period was more aggressive in terms of RSU grants to try to create that alignment that you are discussing. I can – my first boss and whoever had a paying job was a guy named Peter Lynch and he viewed Insider ownership as follows

[Unidentified Analyst:]

Okay. And so - sorry.

[Frank Bracken:]

Go ahead – no, please go ahead.

[Unidentified Analyst:]

So, can you confirm for the shelf registration that it’s only for acquisition purposes?

[Frank Bracken:]

Correct.

[Unidentified Analyst:]

Okay.

[Frank Bracken:]

It’s shares for asset is what an S4 allows you to do.

[Unidentified Analyst:]

Okay. Thank you very much. Good luck.

[Frank Bracken:]

One last thing I’d like to mention, while we are talking about this is, there is hot – there is always a new hot button in the analytical community and I think they are generally driven by places where they buy side gets burned and last year they were – it was GOR. This year it’s parent child and then there also seems to be a lots of sensitivity about CapEx creep. And things got out of hand in the Permian last year, because, of the just the kind of Wild West mentality and cost inflation that occurred in an overheated basin. That did have a ripple effect in our 2018 results. We have all of our cost really locked down. So, other than being poor at executing in days, spend on an activity, we know what our costs are going to be. But the market seems to run through this higher drill of what was CapEx in the quarter and did it meet my expectations or beat them? That was really well for – with a pioneer who has got lots of rigs running and the timing of one frac invoice from Slumber J doesn’t make any – doesn’t make a hell of being the difference. But, one invoice to us is $10 million, $12 million in many cases. And when you are talking about spending $30 million, whether that hits when the gib is open or close can cause tons of volatility in our quarterly CapEx. So, we are going to try to make sure we show you that our wells are costing what we say – what they say they are. But there is a lot of accounting flex with payables and alike on a quarterly basis for a company our size and to get overreactive about that is a danger in my book.

[Operator:]

And we do have a follow-up question from the line of Ron Mills of Johnson Rice. Please go ahead with your question.

[Ron Mills:]

It was asked. Thank you.

[Operator:]

Thank you. We have no further questions in the queue.

[Frank Bracken:]

Well, guys thanks very much. We are looking forward to coming back in 90 days with more good well results, higher production and higher EBITDA and hopefully a better stock price. Thanks.

[Operator:]

Ladies and gentlemen, this concludes the Lonestar Resource first quarter 2019 financial results conference call. Thank you for joining us today. You may now disconnect your lines.