Lonestar Resources US Inc.
Q2 2017 Earnings Call Transcript

Published: 7 Aug 2017

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources Second Quarter 2017 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 this conference call is being recorded today the 7th day o August, 2017. I would now like to turn the conference call over to your host, Frank D. Bracken, Chief Executive Officer. Frank, please go ahead.

[Frank Bracken:]

Thank you Susie, and thank you for joining us today, and with me today are our executive team and our Chairman, John Pinkerton. Before I get started, I have to direct you to the cautionary note regarding forward-looking statements, Safe Harbor, and disclaimer on Page 2 of the conference call slides. Now please turn to Slide 3 for my opening remarks. I'll try to set the stage for our call today by relaying a quick story. Over the weekend, I received a call from one of our more industrious analysts who follow the stock, who called our second quarter sneaky boring, in a way I agree with him. We're paying attention to the details of our business and flat out executing, which sets us up for self funded growth in 2018. My key messages for today are the following; on June 15, we closed a pair major Eagle Ford Shale acquisitions in the quarter that scaled the company significantly in terms of EBITDAX, reserves, and production. After post closing adjustments, Lonestar paid total consideration of $90 million in cash and approximately 2.7 million shares of Lonestar series B preferred stock, which are convertible into 2.7 million Class A common shares. The second quarter felt the full brunt of a number of nonrecurring charges related to the acquisitions, but very little of a positive impact the acquisitions will have on the growth of the company. We look forward to reporting a much more robust third quarter that will incorporate the full brunt of the acquisitions. I'd also add that I'm very pleased with the way our COO, Barry Schneider and his operations teams have attacked the business of taking operatorship of these assets, staffing it with Lonestar field personnel, more efficiently managing costs, and bringing the production up to our standards. I’m confident that on the third quarter call, I'll be able to quantify these improvements that I'm seeing. Equally important what the acquisitions bring to Lonestar in terms of scale and upside, I believe we financed these purchases in a manner that further deleveraged the company and paid a great deal of attention to accreting value to the equity holder. With these acquisitions being integrated operationally, our job is to drill and complete our inventory of extended reach laterals and grow the value of the company by increasing reserves, production, and cash flow. If we execute, we should be able to generate production in excess of 10,000 BOE a day and EBITDAX in excess of $100 million in 2018. At Lonestar we call this the 10 and 100 plan. And if we execute, we should be able to grow our borrowing base from $160 million currently to close to $200 million by the end of 2018, while reducing our leverage ratios from in the 3s now to in the mid-2s in the same time frame. If we accomplish these objectives, I'm confident that Lonestar will be rewarded with a much higher stock price that reflects our higher EBITDAX and lower leverage ratios. Our 10 and 20 plan, if executed, will complete Lonestar’s transformation and position the company to consolidate the Eagle Ford Shale. With this objective in mind, our job as stewards of your equity is to take as much financial and execution risk out of that plan. And I think in the first half of 2017, the team has taken very concrete steps to do just that. We've done three things that make our 10 and 20 plan highly deliverable -- 10 and 100 plan highly deliverable. First, in 2017, we demonstrated continued improvement in production results on all of our core properties that are in excellent returns and these properties will be the focus of our drilling program through 2018. So if we simply drill the same kind of wells we've already drilled on our core properties, we should be able to generate more than 10,000 barrels a day of production volumes needed to generate $100 million of EBITDAX in 2018. Later on the call, I’ll detail the continued strong performance of our 2017 program at Burns Ranch, Cyclone, and Wildcat. In this case, sneaky boring will be a win. Secondly, we wanted to ensure that we don't lose our drilling inventory to lease expiration and the 2017 program has been designed as many - has been designed to HBP of many of our core development properties as possible. So it will retain all the reserves and their value, and have more discretion over when to convert them to cash flow. I'm pleased to report that by the end of the third quarter we'll have essentially HBP to all the properties that will comprise the overwhelming majority of our 2018 program. So Burns Ranch, Cyclone, and all the acquired properties will be effectively 100% HBPed and we’ll need to drill two wells at Horned Frog next year to bring that property to 100% HBP with two years still remaining on the primary term. We're convinced that we can deliver the volumes that are needed to get to $100 million of EBITDAX next year. The other major variable in that equation is price. And we needed to take most of the price risk out of our 10 and 100 plan. Towards that objective, we bulked up our crude oil hedge book in the last few weeks to make our cash flows and our returns much more predictable. We've now had roughly two thirds of the oil volumes we expect to produce through year-end 2018 at prices in excess of $50 a barrel, so the risk that prices fall will have a highly muted impact on our objectives of using the drill-bit to increase our production, our cash flows, our borrowing base, and reduce our leverage ratios into the 2s. Please turn to Slide 4 for some financial highlights. We've included some trend line graphs that are shown on Page 5 as well. Lonestar reported a 7% sequential increase in net oil and gas production during the three months ended June 30. Net oil and gas production averaged 5,635 BOE a day compared to 5,266 for the prior quarter. Production growth was a result of the addition of Wildcat B1H well, in which Lonestar earns a 50% percent interest in May and the inclusion of the recent acquisitions for 15 of the 91 days in the quarter. Q2 ‘17 production volumes consisted of 3,564 barrels a day of oil or 63% of our mix, 1,004 barrels of NGL or 18% of our mix, and 6,402 MCF of natural gas or 19% of our mix. While 2Q production volumes increased 7%, crude oil production increased 10% sequentially, which further enhances the profitability of those barrels. With the full impact of the acquisitions and more production from Cyclone expected in the third quarter, we’d expect that mix to be almost 70% crude oil and the total liquids mix to exceed 85% in the third quarter. During the quarter ended June 30, we placed one well onstream or a half a well net, being Wildcat. Thus far in the third quarter, we've already placed two gross, two net wells on at Cyclone, and we anticipate placing two additional wells on at Cyclone later in the third quarter. Adjusted EBITDAX for the quarter increased 10% to $12.7 million. Lonestar’s operating cost structure for the three month ended June 30 was pretty noisy, with LOE increased by Battlecat and Marquis acquisitions and several nonrecurring charges, so e many of which were related to the acquisitions which should be behind us. LOE rose to $3.5 million or 6.87 per BOE. This increase was partially attributable to the inclusion of the Battlecat and Marquis assets which currently bear higher operating costs. As Lonestar integrates the newly acquired properties, we expect to reduce operating costs to superior levels. G&A had a lot of noise in it to. Had $600,000 of non-recurring expenses related to legal expenses incurred for the establishment of corporate governance charters, policies and procedures related to moving our domicile from Australia to Delaware and listing on the NASDAQ. And we have some employee relocation expenses as well related to our acquisitions. Adjusted for these items, G&A would have been 2.5 million or 4.85 a BOE, some improvement with much more expected to come in the third quarter. Interest expense increased to $6 million. However included in that interest expense was a charge of $1.1 million related to early payment premium associated with the extinguishment of the company second lien debt. We eliminated 12% debt and funded with the revolver, which currently bears a 4 percentage coupon. Excluding the non-recurring $1 million charge, interest expense would have been 9.56 a BOE in the quarter. So all-in cash cost running right around $21 in the quarter, definitely should see some improvement on that as we get the full benefit of the acquisitions in the third quarter. Real production growth is on the way, Lonestar estimates that net oil and gas production for the third quarter will average between 7,600 and 8,100 BOE a day, which would represent a sequential increase of 35% to 44% over our 2Q ’17 production and we'll keep getting oiler as the table suggest. I'm sure I'll get a lot of questions on production rates for the fourth quarter, so I'd just like to address that now. The fourth quarter is going to be highly dependent upon a number of things. For instance, we moved back our Horned Frog wells which are gassier and have very, very high levels of early BOE reproduction in favor of a pair of Burns Ranch wells, which are oilier and will have lower production rates. So things like that can affect our quarters fairly dramatically still, but it will also be highly dependent on the stickiness of frac cost and frac dates. And the well - and which wells will finish up our 2017 program with. We’re working on several acreage deals right now that will influence those model inputs if you will. Moreover, we do expect to see some cost relief in pressure pumping late in the year. And if we can defer fracking on a pad for 30 days and save $1 million, we’ll lean towards doing that. So 4Q production could range from 8,000 BOE a day to 9,500 BOE based on these considerations, which with the decisions associated with will make in real time. It's really for those reasons I'd like to focus our shareholders on the bigger picture and that's on our 10 and 100 objective for 2018 because it's so highly attainable and attainable at $85 million to perhaps maximum $90 million of capital expenditures which can be funded with cash flow or very, very close to it. And it doesn't take any improvement and well results to get there either, we just need to execute. I now refer you to Slide 6 to update you on our hedging strategy. Since its inception, Lonestar is implemented a strategy using commodity derivatives to reduce financial risk and create higher degrees of certainty to our cash flows and our returns. The slide demonstrates how willing we were to hedge into a backwardated crude oil environment in 2015 and 2016, and ultimately those hedges prove crucial to Lonestar’ cash flows in those years and actually gave us the capital to pursue farm-ins and drilling commitments that add Cornerstone assets at Horned Frog, Burns Ranch and Cyclone. At companies of any size, but most particularly Lonestar, we believe this discipline is a crucial part of our ongoing risk mitigation strategy. During the month of July, we used the periods of strengthen in the WTI market to bolster our hedge books to level that we think really batten down the hatch and provide the company with robust price protections at levels that ensure our cash flows and provide attractive returns to our 2018 drilling program. Our current hedge book is shown in detail on the right of Slide 6 and I think more importantly the graph on the left shows you the incrementals of the hedge book that we added in the month of July and how our hedge book stacks up compared to analysts’ projections for our crude oil production in 2017 and 2018. As we do each quarter, we're going to focus on continued improvement in operating well results. And again sneaky boring, no surprises in gas oil ratios. In the properties that we've drilled in to-date in 2017, we’ll actually see the bulk of our drilling dollars in the next six quarters. And in this respect, I think there's very little execution risk to the program in terms of well results I'll now refer you to Slide 7 to update you on progress at our Burns Ranch property. These wells, the 8, 9, and 10 will continue to perform very, very well. I'll remind you that this is the third consecutive quarter that we've gone through this analysis. Lonestar implemented a number of technical improvements to these wells, which included employing Azimuthal gamma ray to stay in our petro-physically determined geo target through multiple dip changes, increasing profit concentrations to 200 pounds a foot, which included the use of diverters, and very importantly more conservatively choke managing production to maintain lower gas oil ratios in our Generation 5 wells. Lonestar is very encouraged with the results. We believe that our advancements in simulation design has resulted in the increased effectiveness of the Gen 5 well stimulations in contacting additional reservoir rock volume that allows for more complex fracture volume in the same fracture half-length, which results in better fracture and drainage efficiency. The proof lies in the fact that at 57% pressure drawdown, our Gen 3 wells had recovered 40,000 barrels of oil. By contrast, our Gen 5 wells have recovered over 70,000 barrels in a half a year with 57% drawdown that's an improvement of 75%. You’ve all heard an awful lot about bubble point in the last week and while I can't comment on how this is really impacting other operators, I can tell you that for a considerable period of time it's been a real consideration at Lonestar and it is a real consideration in these unconventional reservoirs. And it's something that we've been laser focused on at Lonestar during the flow back of every single well we produce. We believe that the rapid increase in GOR that we experienced in our Gen 3 wells did impair our oil EUR's by prematurely reducing flowing pressures below bubble point. As a result, we have been more stringent in our choke management techniques on our Gen 4 and Gen 5 wells as part of our oil maximization strategy. At 70,000 barrels of oil recovery, our Gen 3 wells exhibited GOR's of 2,700 scf per barrel, while our newer Gen 5 wells, which have been more stringently choke-managed, have recovered 70,000 barrels of oil while registering a GOR of less than half that. Lonestar is drilling again at Burns Ranch. The B1H and B2H on have been permitted with the Railroad Commission at projected depths of roughly 18,000 feet respectively. Projected perforated intervals for these wells will be approximately 9,000 feet. Lonestar expects to own a 92% and 69% NRI in these wells. And upon completion of these wells, Lonestar will have completed five producing wells on this leasehold during 2017, and consequently, Lonestar will have increased the acreage that is HBPed for 2,673 net acres to 3,817 net acres or 95% of our leasehold at a minimum. I’ll now refer you to Slide 8 to update you on progress on our Cyclone property. During the second quarter, Lonestar drilled and completed the 4H and 5H. We had a 100% working interest in these wells. These wells were fracture-stimulated in engineered completions with average proppant concentration of 1,820 pounds per foot over 30 stages per well and utilized diverters. The 4H and 5H were placed into flowback on July 1 and therefore did not contribute to the second quarter results. 4H was completed with a perforated interval of 8,706 feet and tested 741 BOE a day on a 22/64' choke. The Cyclone 5H was completed with a perforated interval of nearly 9,300 feet and tested 771 BOE per day on the same choke. On average, these two new producers have recovered 7% of their frac load, to date. It is notable that both of these wells were classified at probable in the Company's third-party reserve report as of December 31, 2016 which has positive implications for our proved reserves at year-end 2017. In addition to these completions, Lonestar has drilled the 26H and 27H to about 18,000 feet respectively. The 26H should be stimulated in 29 stages, with an 8,600 foot perforated interval and the 27H should be stimulated with 28 stages over a perforated interval of 8,500 feet. Fracture stimulation operations are scheduled to commence on these wells in August. Lonestar has a 100% working interest and 79% NRI in these wells. Lonestar continues to have real success in leasing additional tracts which are contiguous to our Cyclone leasehold. At December 31, our acreage totaled 2,656 net acres, which accommodated 26 gross and 24 net laterals. By June 30, we’d increased our leasehold to 3,512 net acres, which accommodates 38 gross, 36 net laterals, in several cases we’ve elongated some of those laterals across the lease position with these lease acquisitions. Lonestar estimates that when production is established on the Cyclone 26 and 27 wells, approximately 86% of our leasehold in Cyclone will be HBPed. We've built real critical mass here in Cyclone and I'm very confident they will continue to grow this position and our drilling inventory in the area where we've demonstrated real success. Just look at the picture on the bottom right, those are our 9 and 10 wells after a year of production and how they stack up against the offsets. And again the only well that has outperformed us is an EOG well and like we like to say around here, second and third to EOG isn’t always so bad. And I think vastly superior results to the other offsets. I’ll now refer you to Slide 9 to update you on our record setting well in Brazos County. Lonestar owns a 50% interest in the Wildcat B1H, which was placed onstream in May of 2017. This well was drilled in an, where a very capable operator drilled more than 20 wells with increasing levels of profit concentration. But generally, very well stimulated by industry standards. With the benefit of evaluating those offset wells, Lonestar has set an objective of improving on those results by keeping our lateral in a petro-physically derived geo-target pumping about 2,100 pounds of proppant, but importantly in non-geometric engineered completions, which were designed with the benefit of lateral logs. We previously reported to you that the Lonestar B1H reported a 30-day maximum of 2,123 BOE a day. And today’s I'm pleased to report that this well is still performing extremely well. The B1H has produced at a 60-day rate which has averaged 1,867 BOE a day, consisting of 817 barrels a day of oil and 610 barrels of NGLs for a liquids yield of 77%. These rates have been achieved on a 20/64‐inch choke, as Lonestar remains conservative in its choke management procedures with the goal of maximizing crude oil recoveries. The Wildcat B1H was classified at probable in the Company's third-party reserve report at year end and so there's positive implications for our proved reserve base here as well. The results of the block at B1H were extremely as Lonestar has a sizable position in the Wildcat area in the deep Eagle Ford section in Brazos County, and notably, has not booked any Proved reserves to the area. Lonestar estimates that it’s on its leasehold, the Wildcat area holds 38 potential extended-reach locations based on 800 foot spacing. He finished the interpretation of our 3-D seismic data across the leasehold and we are now conducting some rock properties analysis with a goal of concluding our resource assessment in September, at which time we’ll develop a capital plan for the asset with our partner. I'd like to wrap up by saying that the second quarter is a springboard for Lonestar and while the 2Q results minimally reflect the positive impact of our Eagle Ford shale acquisitions, the third quarter results will much more fully reflect their impact as well as nearly completed wells. Moreover, as we assimilate our acquisitions, we're increasingly confident in our ability to enhance the value of these assets by better managing the current producing assets by applying Lonestar’s technical abilities to drilling new wells on the property. We're also encouraged by the apparent coming slowdown in drilling completion activity disclosed by a number of industry participants, which should result in a more pliable energy service cost and better availability at a time when Lonestar expects to scale up our drilling and completion program. In summary, we've accomplished a lot in the first half of ’17 as we significantly grew Lonestar through acquisitions, had exceptional drilling results and greatly strengthened up financial position while locking in cash flow and returns by building a very big hedge book. As a result, we're very well positioned to meet our 10 and 100 plan which puts leverage ratios in the mid 2s by year-end 2018 and which should result in a vastly improved valuation for our equity. This concludes our prepared remarks and I'll now turn the call back over to the moderator for questions.

[Operator:]

[Operator Instructions] We will now take our first question from Jeff Grampp with Northland Capital Markets. Please proceed with your question.

[Jeff Grampp:]

I was hoping just - I appreciate all the commentary here to get us started and understanding that there's potentially some flexibility in the back half of the year as far as drilling program and completion timing, but just as it stands today, can you just maybe give us a broad stroke sense of how we should expect the drilling program and completion to progress throughout the year, I know the Cyclone wells this month or whenever they IP here shortly and drilling some Burns Ranch wells, but as far as kind of future development, how are things kind of shaping out within the asset base today?

[Frank Bracken:]

Sure. So let me kind of work backwards. As it relates to the 2018 plan, what I think you should expect are a total of 18 wells, two of which will be incremental Burns Ranch wells, two of which will be Horned Frog wells. We could drill three to five wells in Gonzales and then I would probably say in the neighborhood of nine on acreage that we acquired in the Battlecat acquisition. So those will be between Karnes County and Gonzales County, and I would tell you they're all about the same in terms of productivity. So that's how 2018 will set up and the scale that a two-rig program and a dedicated frac spread which we're talking about now will give us an ability that we really haven't had in the past. That’s really set a schedule and largely stick to it and give you guys a lot more predictability in how things go. This year we've really, we flexed the schedule for a lot of things. We flexed it to take into account the big acquisition we made and the impact that would have on cash flows. We've also flexed it to maximize HPP, and we have some strategic things that we're working on in Horned Frog that have wanted us to slow down that process a bit, and we flex it to take advantage of incremental leasehold opportunities that we have. And so what I would tell you is, today, we'll either drill wells at Cyclone or in the area or we'll drill three wells on the Battlecat assets. I can't tell you where that's going to be at, we just got a lot of balls in the air, we've got some strategic acquisition opportunities, to just caution you, very low dollar ones that could influence that schedule. So, while I know that's not a great answer, what I can tell you is that there will be for your planning purposes fairly low GOR, very oily type of numbers that probably look a lot like Cyclone wells regardless of where we’re drilling.

[Jeff Grampp:]

And while we're on Cyclone here, kind of transitioning to my next question. You guys referenced in the slide deck here that those most recent wells were kind of choked back waiting some infrastructure things, is it fair to expect then that maybe the decline rates off of those test IPs are maybe a little bit more modest or maybe there's a little bit more juice in those once the infrastructure comes in or can you just kind of talk about I guess comparing those versus the 9H and 10H wells that seem to have come through [ph] nicely here?

[Frank Bracken:]

Sure. So there’s a few things that will go on there. So we got into this area with a two, basically a 2-well drilling commitment, and what we didn't want to commit to at the time without having seen the results is all the infrastructure that you've got to build in to put in a full scale development, so we've been running off of self-generated power. We’ve disposed water via truck and we flared gas. With the results that we've seen, we’ve had the confidence to lay a gas backbone, so we'll be selling gas out of here for the first time. We're actually laying a water backbone and having a third-party SWD lay to us, which will result in some phenomenally low water disposal cost for the property. And so, we're really -- and we’ll have power at a much cheaper rate than we would have had, had we installed it for the 9 and the 10. So we're -- and we're going to -- and it's going to make returns much better. I mean, it's a very profitable wait for us. The other thing that we’ll do on these wells is we’ll probably get them on jet pump earlier than we did the 9 and the 10, which should to your point help on rate. We're always inordinately reticent to speculate just how much, but as far as you just qualitatively, we couldn’t -- it took us a while to get the first set of wells on jet pump. We've got everything ready to go once we get our [indiscernible] plant running here in a couple weeks to be prepared for jet pump once those wells get to the -- the 4 and 5 get to the appropriate flowing tubing pressure to engage in that activity. So, yeah, we’d like to think those will be a little flatter than the first set of wells.

[Jeff Grampp:]

And last one for me, just though I'd throw that out, if you’ve got a number. Any initial guess estimates on what you think this Wildcat well’s EUR could come in at? I know we only got 2, 3 months of data here, but just want to see if you guys had any general ranges, given the strong well spend?

[Frank Bracken:]

I can tell you this that we're working really hard on that, because we've got a bunch of locations we want to drill here, and we're running through all the economic scenarios, but I would tell you this that if it holds the curve and the great thing about how we’re doing this well is, we're not getting rate through changing checks. That’s all this trick in the book. I mean, this thing is just, this is just reservoir depletion that we're seeing exhibited in the decline curve. I mean -- and I’d tell you that there's a really good chance this is a 1 million BOE well if it holds this curve.

[Operator:]

Thank you. Our next question is coming from the line of Ron Mills with Johnson Rice. Please proceed with your question.

[Ron Mills:]

A couple of questions. One, just as it relates, big acquisitions that you announced back in May, I know it's still early days, but especially with those Cyclone results that bodes well for Battlecat, can you just talk a little bit though about what you’ve been doing over the first couple of months here in terms of integrating the acquisitions, how that process is going and how that sets you up?

[Frank Bracken:]

Yeah. And that’s a great question. I think if you look at the history of the industry, acquisitions are great for the metrics, but if you don't really mind your Ps and Qs, and establish proper practices very early, they can get -- costs can get away from you and production results can underperform and Barry and his team have just done an extraordinary job of developing a plan to get after the asset. And let me just give you some qualitative items. We actually assumed operations 15 days before we closed the deal and that gave us some time to assess the asset and how it was being operated and I’ll just give you some sound bites. It was previously being operated by a total of I guess 12 contract pumpers, which are quite expensive. We're operating both assets with five Lonestar employees who are fully reportable to our manager of field operations, his move from Fort Worth to Flatonia to make sure that we’ve got the right set of eyes on the ground. So I would tell you that there's at least 50% LOE savings just in that process. We've cut power costs by over 40%. We've changed our chemicals program and probably dropped those costs by 40% to 50% as well. So we'll quantify those cost savings as we get results in our -- and can really do a responsible job of letting you know what we've done, but I think we're doing great work to materially change the economic climate on those properties already. We're also engaged in a dramatically different sort of workover procedure. I'll tell you, I think our workovers are half of what was being done in the past in terms of costs. We're also engaging in asset dumps that one of our field Engineers has had a lot of experience with and right now, I'd tell you they're paying it out in less than a month. So it'll take us 90 days to get all the wells worked over and producing to our standards. But I'm optimistic about the progress we're seeing there, looks really good. So in aggregate, our people have got full operational control and doing an outstanding job of getting this thing under control in terms of costs. And once we get that baton down, then we’ll really start prosecuting some more aggressive treatments to perhaps really change the production profile of the asset. That's before spending any money in terms of drilling. One other thing, I got a great one for you. There's a lot of spare surface equipment, the most recent pad that we’ve set up for operations did not use a single new piece of equipment. We were able to take inventory out of the marquee asset and we're still running the numbers, but my guess is price saved $150,000 on that pad. So we may not -- we might not be in the tank and separator market for quite a while.

[Ron Mills:]

And then on your third quarter guidance, the volumes obviously look good, but the 70% crude and 16% to 17% NGLs, the liquids component is a lot higher than maybe we would have thought. What's driving that and then can you expand a little bit on the, what you said about the fourth quarter and just timing of which wells you complete, how that can impact that product mix. I’m just trying to get a sense for go forward and maybe even for ’18, is this third quarter a better range?

[Frank Bracken:]

Right. Well, first, I'd tell you that the third quarter mix getting oilier is really a function of two things and two things only. It's a function of the acquisitions and those acquisitions are quite oily in nature as we previously disclosed and they’re a function of the fact that we're bringing on four Cyclone wells, a pair of which will contribute for every day of the quarter and the other pair of which hopefully will contribute to some small fraction in the quarter and those Cyclone wells are very, very oily compared to other wells that we've got in our -- compared to Horned Frog for example. So -- or even Burns Ranch or Bell Ranch. So that’s what's driving the third quarter oil mix. I would also tell you that the other thing driving kind of a change in mix short term is the fact that we did have Horned Frog wells on the schedule and in fact we’ve deferred those and we will in fact drill two Burns Ranch wells as an alternative and I guess, that's a double edge sword. It's -- the Horned Frog wells produce very, very, very high rates on a BOE basis. But the gas mix is real high, right. The flip side of that is that we'll probably have lesser volumes, but in the fourth quarter, based on which wells we bring on, but they are frankly, from a cash -- from an EBITDAX standpoint, they're probably -- they’re materially more profitable early on. So Ron, I don't think there's any reason to think that the guidance we're giving you for the third quarter isn't something that should hold up or perhaps improve a couple of ticks in the fourth quarter.

[Ron Mills:]

And then just, can you educate me on one thing, like with Wildcat in particular, the IP30 versus the IP60, the 60 day rate, the oil volumes ticked up a little bit, just curious in terms, is there some production management or what’s going on in terms of driving that oil growth as a percentage of total?

[Frank Bracken:]

Well, we’re trying to do what the offset operator didn't do and that’s, be really cautious about managing these rates on these wells. It's pretty good, from our perspective, it's very simple. Oil sales for $50 a BOE and gas sales for $18 a BOE and when it comes to earning returns on these things, we want to make sure we get as many oil barrels as possible. So we're managing with [indiscernible] if you want to think about it in super layman’s terms, it’s the reverse of bubble point. But we're trying to maximize all rigs. I mean it's just, we can produce this thing at much, much higher rates, but we think it’d be -- and make super fancy press releases that we think a record setting well for the county is good enough for us. We don't need to do better than that. We need to make sure that we're just minding the details and the details are maximizing well oil rates for as long as we possibly can.

[Operator:]

[Operator Instructions] Our next question coming from the line of Mike Kelly with Seaport Global Securities. Please proceed with your question.

[Mike Kelly:]

Frank, I was hoping if you can dig into, hoping to dig into this 10, 100 plan a little bit more and first off, I think it's prudent to protect with these hedges next year, aggressively getting those off. As it pertains to, I think you laid out an 18-well program. I know that’s a lot of flexibility in those. Is that 18 gross or how should we think about the number of net wells there and then the other thing, just running down the list of kind of wells by area, if you can give us sort of ballpark of what well costs are running at each of the various areas, I think that would be helpful too.

[Frank Bracken:]

Sure. So 18 wells, Battlecat, we’ve got a partner, so those are 80% wells. So those 9 and I call it Battlecat, I mean it could be on Battlecat, it could be another acreage that we’re grabbing in Gonzales County, but I would generally assume that we own an 80% in those. Elsewhere, I think you ought to assume pretty close -- 95% average -- working interest on average. I'm not quite sure what that means. So Mike, I think we can execute those 18, we've got, at current service costs, we've got that program costing know between with contingency between $85 million and $90 million.

[Mike Kelly:]

How about in terms of the per well basis, what’s a good ballpark, kind of rule of thumb to get back into the math there, but is there anything more precise you want to give by area?

[Frank Bracken:]

Yeah. I think, it's a little bit of –

[Mike Kelly:]

That's something we can take offline too, if that's getting a little granular.

[Frank Bracken:]

Yeah. You can do the simple math and get that divided, but it's really simple. The 18 wells and the $85 million it takes to do it, it's something that we've designed to do for all intensive purposes within cash flow. I would tell you that I think, I mean and this is, we do better than 10 and we do 100 or more. We grow our borrowing base, we get our debt leverage ratios down to the 2s and I think really importantly, the level of hedges and you'll go play with your model, the level of hedges we have in place, you could run a $40 deck and even if you didn't assume that cost would come down in the business that we still had to spend $85 million for those wells, we'd be talking about probably $5 million or $6 million outspend to get that done and I think that's really the important thing here is that we're drilling in areas that we've already shown the market we can drill in and we've shown ourselves that we can drill in and deliver results. We’ve a good feel for what those well costs are, because we've been active and have just incurred those costs. So we think we can deliver on the capital side. The key is, is just making sure that you do that in a way that rapidly grows EBITDA and rapidly improves your debt metrics. And I think the hedges, and if we could do that in a $40 environment, we have to go in the whole an extra $5 million on the debt facility. I think that would be a giant win for 2018. So that's really one of the core messages that we've got is that we think we've positioned the program to be executable in almost any price environment.

[Mike Kelly:]

You guys have been very opportunistic and have done a number of great bolt-on deals throughout the last couple of years, how should we think about leasehold CapEx in 2018 and maybe how aggressive or how passive you will be on that front?

[Frank Bracken:]

Yeah. I think we will never turn down opportunities as long as we think they're highly accretive to the equity value. But we'll also be really, really mindful of our capital position and it's something I think we've done a pretty good job of in terms of being creative. If you look in the ’14, ’15 downturn, we were really worried that we were going to have, we had to say drilling dollar, we had to manage our drilling dollars very, very carefully, but there are all these farm in opportunities and drilling commitment based opportunities that presented themselves to us. So you didn't want to turn the opportunities down, but you had to find a way to do it that didn't compromise your balance sheet and we entered into our IOG drill code and we use that money to farm it. We'll use that money to build the Horned Frog position and the Cyclone position. So in retrospect, you never would have wanted us to not do those deals, but we also wanted to be really careful about the way we funded those. So I would tell you that we're working on a similar strategy for acquisitions that will be designed to minimize the balance sheet impact of future deals, but we're -- so I don't -- we don't have a budget per se yet, that'll happen at a board meeting or two in future. But honestly, I mean, we’ve spent $1 million to $3 million every year doing those kind of things. So it would be -- it wouldn't be out of the realm of possibilities that we do it again.

[Mike Kelly:]

Final one for me. In Brazos County, obviously Wildcat well extremely encouraging. I know you’re doing the seismic right now, but maybe you could tell us, give us a sense of what the early look from that data is telling you and I guess I'm just really curious on how consistent you think that whole county could be for kind of four different blocks if you look at slide 9, just would love to hear how many potential million barrel plus wells we have in the hopper.

[Frank Bracken:]

Well so I think we really are 30 days away from having that all done, but I think we've got it mapped. We know how thick it is. We're doing some incremental work to really have a good feel for how the -- what the lithology is. I would tell you that, at the moment, I think if I had to make a guess that maybe the really high resistivity package that we think hold most of the hydrocarbons might be a little thinner west, but we also think it's a lot cleaner. The Wildcat is crazy, it's like 39% if I'm not mistaken. So you may actually have an overall better reservoir in the west, but notice I used the word may, we're still, our GOs and our petro-physical consultants are still working on the area, but in a month, we think we'll have a really good view as to what that position looks like and how we’ll prosecute it. Remember, we do have a partner who has, who owns a lot of Lonestar shares and has some other acreage that they can pool into this. So this thing can be bigger than what you see on the map.

[Operator:]

Thank you. Our next question coming from the line of Evan Templeton with Jefferies. Please proceed with your question.

[Evan Templeton:]

Just a quick question, wondering maybe you can just talk a little bit about what you're seeing in terms of pressure pumping, it sounds like in the back half of this year, in to ’18, that will be one of the kind of the larger variables in terms of your production profile so, and I think you also mentioned maybe picking up a dedicated spread. So, maybe you could just help out and just give a little color into what you're seeing in the market and what you might be able to do in terms of locking something up for longer term?

[Frank Bracken:]

Sure. So look, it’s tight right now. We have a great relationship with Schlumberger. They bring a lot of technology to bear and it's benefited our well results. But they are tight and we have slots on the schedule, but I would call them slippery. We’ll not lose in slots, which a lot of people are, but they're slippery. It feels like and our costs have risen, but have stabilized here and I think, our two big needle movers or the two things that moved a lot for us are oil field tubulars and pressure pumping and pressure pumping has stabilized and tubulars have actually started to soften up. So I think the rest of this, but when we sit down and talk to all the vendors, it's unanimous, right? I mean through October, everybody’s booked completely solid. And fortunately, we've got some slots in there. I think what you'll probably see is, look, you can tally the number of rigs that are coming off based on the press releases you've seen better than I can, but my sense is you’re going to lose 20 to 50 rigs in the fourth quarter kind of -- just to kind of, to normalize programs, but then you also have the dynamic of people, things costing more than people thought and maybe their EBITDAX not being quite what they thought it was and people run out of budgets late in the fourth quarter. So that's usually a -- it's been historically a good time for us to slip in and get better service costs, but I in fact have a meeting with, let’s just call him, a very important person in Schlumberger today. Barry and I do to talk about exactly those things, but the white board is completely clean for ’18 and the sooner we get our spot on it, the better, but invariably, two things happen when you have a dedicated career. You can derive just, you said, a spread discount, which will save you something, but secondarily, there's a lot of efficiencies that can accrue and it will do two things. It'll one, help us save some nickels, but two, help us do a better job of articulating to you when wells will come on, because we'll have that certainty that we just don't have right now and that's why we've -- that's why we've been a little bit cagey about providing quarterly precision, because some of the things are just out of our hands and the beauty of having a spread beyond the cost savings would be that that factor would be 100% within our control and give us a lot easier path of delivering predictable results to the street.

[Operator:]

Thank you. Our next question coming from the line of Ron Mills from Johnson Rice. Please proceed with your question.

[Ron Mills:]

Frank, just one last thing. I know, Cyclone, you talked about, the acquisitions, you basically increased your well count by about 50%, but can you tie the Cyclone into the Battlecat acreage and whether or not your expectations on some of that Battlecat acreage are similar or if they do differ, how from the Cyclone results when you start to drill a lot more wells on the Battlecat position?

[Frank Bracken:]

Yeah. So I would tell you that the Cyclone is a very challenging area in that, we're dealing with a lot of chopped depletion that overlies us that makes our completions managers’ job harder to do. I mean, he’s got to try to keep far field diversion at a minimum and keep the frac in the Eagle Ford. So those are challenges and we've been up to those challenges, both on a geo side and on a completion side. I mean I think as simple as I could put it, the Battlecat acreage has better hydrocarbon pore thickness, which just means there's more all there to get and generally speaking, has less often chopped depletion. So if you put those together, you should actually get better wells than we have in Cyclone.

[Operator:]

Thank you. Frank, we have no further questions in the queue.

[Frank Bracken:]

Well, thank you all very much for joining. It's a twisty road, but I think we've got a clear path to an exceptional 2018. We look forward to getting back with you in 30 days and sharing some real facts in terms of what we've been able to accomplish on our acquisitions and some more well results that I’m fairly comfortable will look a lot alike with the ones we're delivering today. Thanks and have a good day.

[Operator:]

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