Lonestar Resources US Inc.
Q4 2018 Earnings Call Transcript

Published: 9 Mar 2019

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources Fourth Quarter 2018 Financial Results Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions]. Please note that this conference is being recorded today, the 8th day of March 2019. 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. And with me today from Lonestar are Chairman, John Pinkerton, our Chief Operating Officer, Barry Schneider, our VP of Reservoir Engineering, Tom Olle, our VP and General Counsel, Greg Packer and our Manager of Corporate Planning, Chase Booth. Before I get started, I would direct you as we all do to our cautionary note regarding forward-looking statements, safe harbor and disclaimer on Slide 2 of the conference call deck. Please turn to Page 3 for my opening remarks. The fourth quarter of 2018 and the year as a whole represented tremendous growth for Lonestar. For the year, we increased production 72% to 11,155 Boe a day and increased EBITDAX by 101% to $130.3 million. Both of these results were considerably ahead of our original guidance for the year. We increased proved reserves by 23% to 93.4 in Boe, increase per PV-10 73% to $1.1 billion and did so at an all sources finding and development costs of $9.07 of Boe. We made a significant acquisition late in the year with our Sooner acquisition in DeWitt County. And lastly and most importantly perhaps is that we accomplished all this while reducing our fourth quarter debt-to-EBITDAX by 4X to 2.6 times. In the fourth quarter, Lonestar reported another record result which featured an 81% increase in net oil and gas production, 13,152 Boe a day, production again exceeded the high end of the company's guidance and were 80% crude oil and NGLs on an equivalent basis. The company logged a 98% increase in adjusted EBITDAX which was at the high end of our guidance and we generated positive net income. While it's a non-GAAP measure, we also generated cash flow exceeding $92 million which equates to $3.73 of basic share outstanding or $2.30 per fully diluted share outstanding. We accomplished a lot financially as well. We refinanced our senior unsecured notes which would have been due April 2019 with the new offering, those new notes are now due in 2023 significantly extending our runway. We exited the year with nearly $100 million of liquidity and expect to exit 2019 and 2020 with continually improved liquidity. I want to highlight the sale of our Pirate assets located in Wilson County. These assets are distal to our core operating areas and by nature of the asset has LOE that is more than twice the company average. Lastly, the 7 PUDs at Pirate will not compete for capital with projects we have scheduled as part of our two year plan. The message I want to deliver to all of you is that while we believe a bigger Lonestar is a better Lonestar that's something we can achieve with the drill bit and returns will always win out overall considerations. We have a flexible drilling completion program for 2019 with a plan to drill 17 to 20 wells in the calendar year which we estimate will cost between $107 million and $130 million. We have all the key services required to execute this program at lower cost than 2018 and these contracts do not obligate the company to any particular drilling level. To make sure that we can fund this program and maintain our leverage objectives and maintain our return objectives, we've added considerable amounts of hedges to our 2019 and 2020 book as recently as yesterday leading to robust price protection. For 2019, we have about 85% of our crude oil hedged at $54.14 with another $5 plus of basis protection added in with LLS WTI differential swaps. We also have hedged about two-thirds of our natural gas production at an average swap price at 304 that is weighted to higher prices in the winter months. Lastly, we've built up our 2020 crude oil book with hedges executed very recently and currently we have about 53% of our 2020 oil volumes hedged at an average price of 57.34. But in summary, we are a two year plan which focuses on our highest return projects that can yield some very strategic objectives. The most important of which are achieving sustainable levels of operating cash flow that can sell fund appropriate levels of activity to get Lonestar really close to $200 million of annualized EBITDAX next year annual EBITDAX next year which we would hope would imply substantially higher equity values. With that, please turn to Slide 4 to discuss some of the details of our quarterly results. As I previously mentioned fourth quarter production was up 81% with new wells at Astrakhan and Hawkeye being the drivers behind our record production in the fourth quarter. Product prices were robust in the fourth quarter with our oil price differentials exceeding $6 compared to WTI and our nat gas price is trading very close to the Henry Hub. Importantly and things that we can control are the fact that we drove down our unit costs as we grow our business. Year-over-year, we reduced total cash costs by 10% on a Boe basis. And they're right about $20 of Boe now. Great price realizations and reduced unit costs resulted in continued improvement in our cash margins which are all part of scaling the business and continuing to focus on being the low cost producer in the Eagle Ford. Now I'd like to take a step back from talk a little bigger picture about where Lonestar is positioned in the morning, try to bring some bigger thoughts about how we have the company set up. First let me say that we view the Board views our job as a management team as and our primary thing is to grow net asset value per share every year. Second to the extent, we can conduct our business in a way that reflects this growth in our quarterly financial information and do so in a way that whenever we can deliver better than expected results. And in every quarter or 2018, I think we accomplish this. I'd urge you to keep in mind that we are small, there's a lot of companies to our spending. And we cannot always reflect all the progress we're making on an annual basis in every quarter. But we I think we are making really big strides toward these important goals. Slide 5 shows a continued reserves and growth both proved and probable and they've been very consistent since our effective IPO in 2016. To be precise, our proved reserves have grown 56% compounded and our proved and probable have grown 64% compounded. One last point while our location count only grew 10% last year, lateral lengths at several key properties were significantly extended and were achieved very small dollar output, that doesn't show up in the location count but it does show up in our reserves and our returns. We spent tiny amounts of capital to focus on adding lateral lengths to important parts of our drilling inventory most notably Karnes County, Horned Frog and Cyclone Hawkeye and many of our 2019 and 2020 wells will be 20% to 25% longer as a result of these acquisitions and will materially enhance those returns. Please now turn to Slide 6, Slide 6 translates reserve growth into value growth. One of the things we really focus on with our shareholders at Lonestar is getting the actionable information. So in this case, we've not included the SEC PV-10 information which has an excessive amount of price related noise in it but instead focus on the values that we in focus on internally all of which are derived by applying a flat price deck of $55 per oil and $2.75 per gas. On this basis, which we think is a really rational way to think about value, we increase proved PV-10 70% compounded and proved and probable PV-10 66% compounded. Now please turn to Slide 7. From my perspective, and I think our Board's perspective this is what our business is all about. How investors look at E&P companies and how they value them as probably changed nine times in the 33 years I've been involved in this business. But ultimately the arbiter of shareholder value has been the underlying discounted cash flow of your reserves because that's how assets are bought and sold regardless of conditions in the public market. This slide shows you that at that flat price deck of $55 and $2.75 less debt and working capital adjustments, we have considerably grown our reserve, our underlying reserve value. We've grown since 2016, we've grown our proved reserve value by 30% to $8.54 a share and our proved and probable value by 21% to $12 a share. Both are current, a far cry from our current share price which has a four handle on it. Lastly and very importantly this graph shows that while we've grown value meaningfully, we've also dramatically improved our leverage metrics. I'd like to now spend some time getting into the details of our two-year capital program and I'd like to highlight one. The bigger bang for the buck we're getting in 2019 with lower energy service costs to the fact that we're spending most of our capital in areas where we spent considerable dollars in 2018 building our infrastructure. So we should see some reduction in costs there. And three, the high rates of return we've demonstrated regardless of the hydrocarbon mix of the asset that we're directing capital towards. I’d now like to ask you to turn to Slide 8 to focus you on our Karnes County assets in which we continue to deliver excellent results. Lonestar drilled our first six wells here in 2018. The graph in the bottom right quartile of Slide 8 shows you the third-party EURs of our first two well pads. It also shows you that these wells ranked in the top half of all wells drilled on offset blocks with 2000 pounds or more. In this case, this ranking is acceptable to us and that all the offsets were completed by EOG Resources perhaps the top operator in the play. We've also acquired some acreage immediately south of our original leased block which will allow us to drill our wells that are 20% to 25% longer than those drilled in 2018 and despite the fact that those wells are longer, we expect them to cost us exactly what our shorter 2018 wells cost us yielding 70% internal rates of return according to the third party reserve report. Please now turn to Slide 9. Lonestar has built 7400 acre position on our Horned Frog area. We drilled four very important wells here in 2018. The first two of these wells the Horned Frog G #1H were drilled on our original Horned Frog leased block and with the first two wells drilled with our Geo-engineering completion techniques. These wells which averaged a little over 11,000 feet have generated a 58% improvement in EUR over our 2015 iterations out here as the graph in the bottom right depicts and are the best performing wells in the area. We're currently preparing to spud 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 less than our 2018 models despite being longer and plans for increased proppant loading. I might also add that these locations are categorized as probable in our 2018 year reserve report. Based on the EURs and our third-party report, these wells are projected to generate 67% internal rates of return and based on the fact that the G #1H are outperforming this PUD curve. We think there's considerable upside to those returns. Now let’s turn to Slide 10 of our presentation. In 2018, we drilled two wells on our Horned Frog Northwest property which was literally acquired a week before we spud these two wells. After conducting Petro-physical analysis of a pilot hole we drilled, we modified our geo target for this area to one that is different from that which we target in other parts of Horned Frog. The results have been fantastic. Our first two wells which were 7400 foot laterals came on at 1100 Boe a day and have performed brilliantly. The graph in the bottom right shows that not only of these wells generated third-party EURs that are 104% higher than the offset average. But our forecast to recover 146% more oil than the average well in the area and nearly twice as much oil per foot as our Horned Frog G #1H. As part of our 2019 program, we've already drilled and completed two new wells at Horned Frog Northwest. These wells averaged 9,000 feet in length so they're 22% longer than our 2018 wells, yet our current pressure pumping contract will allow us to actually generate identical well costs compared to the shorter laterals we drilled in 2018 and generate IRRs in excess of 100% according to our third-party report. Now please turn to Slide 11, over the last three years we've drilled seven different well sets across our Cyclone Hawkeye property and when compared to other offset operators, we continue to generate excellence in our results. In 2018, we made considerable progress in improving the EUR per foot in this area as our Hawkeye wells with our best yet outpacing the third party forecast of 66 Boe a day up considerably from prior iterations. We have three wells in our Cyclone Hawkeye budget that are part of our 20 well plan and we should be able to reduce our well costs out here as well. Our third-party reserve report pegs IRRs in Cyclone Hawkeye at 55% which is plenty attractive at $55 oil. The one thing, I would note particularly to certain of you who put research on our company is that our projects at Horned Frog and Sooner which are in the condensate window and generate a higher gas mix, actually generate higher rates of return than our super oily cyclone asset. So for us it's much more about returns than it is necessarily what's coming out of the ground. Speaking of Sooner, please turn to Slide 12. We owned Sooner for about 90 days now and have instituted a lot of positive change. After getting to know the wells and the compression system, we've increased production from existing wells by about 10% with negligible capital outlay and in terms of higher upside project, our geophysicists had the 3D survey out here reprocessed and remapped these structures on depth. Our conclusion is that the prior owner saw faults that weren't there. These faults are actually in our minds terminate in the Austin Chalk which opens up the door for longer lateral shown in the dashed lines. Our initial wells which will be on existing leasehold but they're now projected to be about 20% longer than we purchased the assets and book reserves. The returns in the bottom left corner demonstrate the significant upside to returns that we can generate as we drill longer laterals at Sooner. We do have three wells planned for Sooner in 2019, those wells will spud in the month of March. Turning to Page 13, just to wrap up. 2018 was a big year for us continue to build scale with the drill bit, the plan is to continue to do that in 2019 and 2020. And I think very importantly the returns that we are that we are forecast to generate are going to deliver production growth and cash that I think is exceptional. Very few companies of any size, class particularly small cap companies are on track to be free cash neutral or better while generating 20% percent growth in EBITDAX and production. So the future is bright. We've got to be patient as we weather these energy, these markets for energy equities. But we're very optimistic about the extent to which we can control our own destiny here at Lonestar. Before turning over to questions. I'm going to turn the call over to our Chairman, John Pinkerton.

[John Pinkerton:]

Thanks Frank. I want to congratulate the entire Lonestar team for a truly terrific year. In my book they hit it out of the park essentially all the operating and financial results are materially exceeded our expectations. I won't rehash all the results and improvements that Frank discussed. I want to focus on two key attributes that in my mind are driving Lonestar to accomplish what only a few independents will be able to do over the next two years. And that's to grow production EBITDA in excess of 20% but while doing it within internally generated cash flow. In an environment of modestly and modest prices, commodity prices achieving this goal is going to be very difficult. In addition to asset quality improvements, technical improvements and the other things that Frank talked about, I believe Lonestar has two things that it does extraordinarily well that's really going to help. First is technical excellence and the second is an extraordinarily attention to detail, unlike a lot of Chairmen, I actually office and Lonestar’s office and get to see the day-to-day activity, one of the things I learned at Range Resources is that to be truly successful in shale plays, you must have a really technically competent team and logistically you have to have a heightened sense of detail because of all the activities that are required. Frank and his team have clearly shown these qualities since I've been here for the last three years. They're always looking for ways to improve and I see it a bunch of improvements that they achieved in 2018. For example, to generate high returns on drilling, longer laterals are essential, we've all figured that out. Lonestar materially increase the average lateral length of its inventory in 2018 which is really going to help looking forward to 2019 and 2020. This is really hard tedious work by the Land Group, while drilling longer laterals is really important to stay in zone wider drilling, despite drilling longer laterals, Joe Young who heads our Drilling department was able to achieve extraordinarily high percentages in zone results in 2018 and again exceeded what we were able to do in 2016 and 2017. From a Geoscience perspective, we added some really high quality people to what I thought was an extraordinary strong team to begin with. Due to this team's quality and creativity, we've been able to design wells with extraordinary detail, our completions are all geo-engineered based on pre-drill analysis of this Geoscience team. On the completion side of our business, Lonestar’s design, executing completions that are truly state-of-the-art. Bill Kreimeier who heads up our Completion team is really a secret weapon in my opinion. And when he combines the Geoengineering completions with the use of voters and other technologies, we are executing better completions at lower cost. And I think we have some of the best completions in the entire industry. So what does all this mean? I like to tell people that Lonestar drills Mona Lisa's. We don't paint by numbers. So while we are small, I believe Lonestar drilled some of the highest quality wells in the Eagle Ford play. I'm absolutely convinced of that, why is that important? All the technical accents and attention detail is what's driving Lonestar to grow production in EBITDA as 20% or better in 2019 and 2020 again while doing this all within internal generated cash flow. At the end of the day, I feel really good about Lonestar’s ability to execute in 2019 and 2020. I think the results will be exceptional and at the bottom line, I think we're going to be able to really drive shareholder value and very clearly over the next couple of years and I'm excited to see it all happen. Frank, back to you.

[Frank Bracken:]

Thanks John. I think we'll turn it over to questions. I was remiss in mentioning that Lonestar shares are not owned by the Norwegians, so we won't see selling pressure from them at least. And with that, turn it over to the moderator.

[Operator:]

Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] We will now take our first question from the line of Neal Dingmann. Please go ahead.

[Neal Dingmann:]

Good morning guys. Good details. Frank, my question is around the flexibility of your plan. You guys continue to have better wells, your balance sheet looks solid here. I'm just wondering what would cause you, I know you've mentioned this kind of this in the press release with a one to maybe two rig program, is that just strictly oil prices just commodity prices or just maybe if you could talk a little bit about your potential even John, what's involved and maybe the flexibility of the plan?

[Frank Bracken:]

Well, so look we have got 13 years or 14 years of drilling inventory at 20 wells a year, our plans really have very little to do with the presence of high return inventory. They have much more to do with bigger objectives. And first and foremost the objective that causes me to wake up when I wake up every morning come to work is driving the equity value of the underlying share. We think that's best done by scaling with the drill bit but being very responsible about limiting risk with hedges and limiting risk in terms of -- on terms of our leverage ratios and available liquidity. So it's really those financial disciplines that are governing the extent to which we want to grow and organically.

[Neal Dingmann:]

Okay. And then a related follow-up, just my second like just did you talk on hedges, your thoughts on is it more or just to protect the balance sheet or when you guys look at this you seem to be maybe a little bit more hedged than some others particularly given your strong balance sheet. So I just wonder how you look at that? Thank you.

[Frank Bracken:]

Yes, hedging has been a religion at Lonestar since I arrived. In my mind, we try to control every single element, we can control and make sure that we're never materially damaged by those that we can't. The next 12 months have always tended to be very hedged because look I think it's really straightforward, if we can generate something that resembles $200 million of EBITDA next year in my mind in any rational market that that should generate a billion dollar enterprise value. It backs off with the math and that means a materially higher stock price which I think our shareholders deserve. So part of my job is to make sure that as few things can go wrong with us getting from Point A here to Point B which is that objective and though largely speaking the world could come to an end this year with respect to prices and we are at this point nearly impervious to them. And that's important in terms of making sure we execute.

[Neal Dingmann:]

Thanks Frank. Hopefully and investors will be better aware of that soon. Thank you.

[Operator:]

The next question comes from John Aschenbeck. Please go ahead.

[John Aschenbeck:]

Good morning, Frank and thanks for taking my questions.

[Frank Bracken:]

Thanks John.

[John Aschenbeck:]

So for my first one, I was hoping to get some more color on what you're doing operationally that's leading to your anticipated cost reductions just especially when I look at the new guidance, the 2019 guidance that you rolled out last week and I compare that to the prior outlook you gave, you’re completing more wells this year than your prior guidance but for the less CapEx and I imagine a lot of that savings goes above and beyond service cost savings and I think you guys have kind of hinted that you're doing some things differently operationally on the call and so I was just curious what specifically could be driving those changes? Thanks.

[Frank Bracken:]

Yes, so that's a great question. There's two things, one I would tell you that that is almost in their entirety. The infrastructure costs associated with Cyclone Hawkeye with our Karnes County project and Horned Frog are in our view, a rearview mirror. So, we're able to make very proximate hookups to our company owned infrastructure which helps us out in a number of respects. But I think but honestly the biggest driver and you've seen repeatedly, we drilled longer laterals in 2019 on many of our properties than we did in 2018. And yet for the same number of wells, the CapEx is coming down. I think overwhelmingly, it's the culture of going out and making sure we get the best bid for every service. We hire third-parties who can execute and we hold every one of them accountable with respect to cost. And it's really just that discipline that that allows us to take advantage of softness in the market and lock it in.

[John Aschenbeck:]

Okay, got it. Great, that's helpful. So my next one, Frank. I just love to get your thoughts regarding the let's call it apparent dislocation and value between your current share price and the value of your underlying reserves which I agree is considerable. And I know you have to be thinking about the drivers of that dislocation of value especially considering if you just look at what you guys have done execution wise this year, it's been spot on. So I'm just curious what you think could be the primary drivers there that are currently causing that value dislocation and then potentially what you think you guys could do to fill the gap again especially because the execution has been there this year? Thanks.

[Frank Bracken:]

Well, thanks. So look I mean I look I think we had a great year. I don't know of any companies who have done in the last three years what we've done in terms of writing our ship financially, managing that process, managing risk and continuing to drive reserve value to some extent on a shoestring. I view most of the value displacement as being something that is largely derived by broad market conditions, the entire sector has been under pressure. The industry has, the industry took a whole lot of capital in 2014 and 2015 and hasn't earned a return on it. I don't think that's the case with us. But the baby gets thrown out with the bathwater all the time. But look being small is absolutely and having a small market cap are absolutely things that are going to cause incremental compression on companies our size, these would be the bigger guys. Institutions are focused on liquidity and guys who can pay dividends and things like that right now. And so I think we just have to be focused on the things we know that over decades have proven to be, have proven to be really successful in creating value and ultimately that value gets recognized whether it's through monetizations of particular assets, whether it's through a change in market philosophy within the group or whether it's through some sort of corporate transaction, so that we can only do what we can do. I do think it was very important for us to, the Pirate transaction was a no brainer for us. We're not doing it for press. We're doing it because that's part of our returns discipline. And I think that that you can, that was a good chance you'll see us do more. We have a well to drill in Brazos, we've articulated a desire to sell that asset due to the fact that it's distal to our operations and we think that it's probably worth more to somebody else than it is to us. So around the periphery, we can do those kind of things and then help ourselves out with leverage in equity value.

[John Pinkerton:]

Yes, John. This is John Pinkerton. Just to add on to what Frank said is that. Yes, I agree with everything he said. I think Frank and I always say we need to get bigger. But the thing that I think is really important and that's all this in my years it rains many, many times is that size is important but getting there in a way that accretive for your shareholders on a per share basis is to me is what's really important. And Frank and the team I think while we want to grow have been incredibly focused on doing things that add per share value and I think over time as people see the company continue to perform over and over again, people get comfortable with that and get confidence in that. And as the country continues to grow whether I mean that whether it's through the drill bit or through adding additional assets, it will be kind of a self-fulfilling prophecy. I think clearly energy is out of favor right now. But at some point of time, it'll be less out of favor and then people look around and look for investments and I think well our job is to consistently execute each and every quarter. And so that when people come into the market, analysts and other investors say hey I think this Lonestar is something you really ought to take a look at. So I think having a little longer-term view, I've been around for a long time and really try to impart that on these guys and trying to focus on the things that they can really control. And I think they've done a marvelous job of that. We'll let the chips fall where they may in terms of all the other stuff but I'm convinced over time that the market will realize and veterans are smart and they'll buy the stock and stock price will go up.

[John Aschenbeck:]

Okay, great John and Frank, I appreciate you sharing your opinions and I appreciate the time. Thanks.

[Operator:]

The next question comes from Jeffrey Campbell. Please go ahead.

[Jeffrey Campbell:]

I try to ask a couple of fairly quick ones here. The first one is I was just wondering do you have any tests of your Marquee acres in the Q over the next two years?

[Frank Bracken:]

Yes we do.

[Jeffrey Campbell:]

Okay, that’s interesting. Is that 2019 event or is it a 2020 event?

[Frank Bracken:]

It’s a 2019 event, could be a 2019 or 2020 event but we’ve got, that’s been a great success for us. We are not only really good at drilling wells but our operations group has done an outstanding job of assimilating producing assets. In our minds, we bought Marquee for the PDP value alone. And since acquiring it, we've generated in 18 months we've generated nearly $25 million of cash on a 50-field $5 million purchase price. So we've returned half the cash in 18 months that we invested, yet still have nearly identical PDP value. So that's been done through operating excellence, through production enhancements and during that time we've taken, we've undertaken a very detailed field study of the area. Clearly, we have lots of places to drill and they all beg for capital but we've really tried to get a very thorough understanding of the rocks and the potential and the best way to go about rerating the recoveries out there and that work is complete and you should expect sometime in the second half of the year to drill our first well pair at Marquee.

[Jeffrey Campbell:]

That's really helpful color. I appreciate that. Another question was just to ask about future M&A and just kind of wondering how you think you will likely finance, I mean the current revolver looks like that it's more than enough to buttress working capital?

[Frank Bracken:]

Yes. I think look I think we had a great year with our little organic leasing program and added conservative oil reserve and really ensured that our 2019 and 2020 returns could mirror those that we generate in 2018 despite a downdraft in pricing. But I think as it relates to M&A, look the one thing that is that John and I talk about with nearly nauseating regularity is that that whatever we do, we cannot take a step backwards in terms of the balance sheet improvement that we continue to strive for. So there may be something that we can find opportunistically but you got to know we're not going to go put the company back at risk in any way regardless of that asset quality.

[Jeffrey Campbell:]

Okay, great. Thank you. Frank can I ask one last one and certainly not trying to be pejorative, I'm just wondering what you're thinking. You mentioned that you're adding a dedicated frac crew on the different source that's going to save costs in 2019. I just wondered what gives you the confidence that the quality of your completions are going to remain unaffected by this change?

[Frank Bracken:]

Well, I would tell you two things, one they were our JV partner in our Geo-engineered completion alliance, so we have considerable experience with them. But two we've already completed 55 stages with that crew and that equipment and then in their first attempt, they probably generated the best stage efficiency we've seen from any operator in three years. So and we would only expect that to improve as that crew which we handpicked gets in sync with the way we do our jobs.

[Jeffrey Campbell:]

Okay. That's great stuff. Thanks, I appreciate it. Congratulations.

[Frank Bracken:]

You bet.

[Operator:]

The next question comes from Jeff Grampp from Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

Good morning, Frank. On the with the Pirate sell that guys recently completed, I was curious outside of the East Texas asset that you touched on earlier. Any other areas that you would kind of put in that bucket as far as candidates for high grading or would you say those two assets comprise kind of the largest set of the both opportunities for you?

[Frank Bracken:]

Look I think from our perspective, there's two questions you ask yourself. There you ask yourself, how does any asset compete for capital with your best projects. And if it doesn't and the number of remaining drilling locations is relatively inconsequential to your core inventory then that asset can be one that you can consider for sale and there are other assets that we fit that mold. But what we did in this case and try to do when we're going through this process is we try to find somebody who strategically can see more value in the assets than we can see. That's where you get guys to pay down to the discount rates that that make these kind of things no brainer. So I would tell you in several of our properties where I would call them well past 30% drilled were we entertain discussions with regularity. This is just the first one we've been able to get across the finish line.

[Jeff Grampp:]

Okay, great to hear. And my follow-up I was curious as you guys approach the first Sooner completions here, how you guys are thinking about, I guess completion practices relative to the Horned Frog area given that those are obviously quite a bit of ways from each other but in the same kind of hydrocarbon window. Are you guys looking at different completions or how are you kind of thinking about comparing and contrasting that?

[Frank Bracken:]

Yes, this is the Horned Frog is the Mona Lisa. This is a Rembrandt over here, we're dealing with nearly twice the hydrocarbon column that we have in Horned Frog. It's more than twice as hydrocarbon rich in aggregate. So yes, the -- in the end of the day, I think you're thinking about a different style completion. But it's really just another. It's just we have a process we go through to determine how we're going to do them by area. Nothing is out a cookbook. And we feel like we've done enough study of the offsets that we have a very good plan in place for how we'll frac these and there is a reasonably good chance that these would feature the highest intensity fracs in the company's history because the rocks are good.

[Jeff Grampp:]

All right, sure, sure. Looking forward to it and nice quarter, Frank. Thanks for the time.

[Operator:]

[Operator Instructions] The next question comes from Stephen Shipman from Arden Investments Advisors. Please go ahead.

[Stephen Shipman:]

Yes, good morning gentlemen. Thank you for your time. Frank, you touched on the new drilling program of roughly $107 million to $130 million, did I get that correct?

[Frank Bracken:]

Correct.

[Stephen Shipman:]

And what would you say your sustaining spending is going to be for capital then?

[Frank Bracken:]

Is that like keep production flat or is that what you're asking for?

[Stephen Shipman:]

Right, just the maintenance capital expenditure on the existing producers.

[Frank Bracken:]

Yes, I'd say it's probably in the neighborhood of $70 million.

[Stephen Shipman:]

$70 million, okay. And what would you say the average tenure duration of those existing wells are in terms of years of production?

[Frank Bracken:]

Are you asking me how many years those wells have been on stream? Are you asking me what for me the remaining economic life?

[Stephen Shipman:]

Yes sir, the remaining economic life.

[Frank Bracken:]

30 plus years.

[Stephen Shipman:]

Really on all of those? I mean on average obviously.

[Frank Bracken:]

No I mean it. I would tell you on virtually all of them there that long. The stuff we sold would have considerably shorter life in that, it had much higher LOE. So you're going to approach economic limit in their older wells, so that approach economic limit faster but it at LOE between $5 and $6 a barrel, these wells can produce for decades at economic rates.

[Operator:]

And the next question comes from Ron Mills from Johnson Rice. Please go ahead.

[Ron Mills:]

Good morning, Frank. The estimates was asked just as you design your 2019 program, you talked about I mean it appears you’re commodity agnostic, you're really hyper focused on the best individual level results. Just give a little background in terms of how you design this year's program and the timing of when you're going to be at places like Sooner and Horned Frog versus Hawkeye and Cyclone?

[Frank Bracken:]

Sure. So by and large. So look, we're returns driven and we're walking you through what Von Gonten shows is the internal rate of return at the PUD value for that lateral length. But if you should be able to read between the lines that in many of the cases where we're directing capital, the PDP that we've placed on stream within the year are outperforming those curves. So we've got optimism that we generate higher levels of return and so simply put, nowhere have we outkicked our coverage as has been the case in the Horned Frog area. So it begs for capital and I think from an asset basis, the oil weight is important in terms of the overall portfolio over the years that we intend to be busy. But really we're returns driven animals and drilling the highest rate of return wells will allow us to achieve really important financial objectives like the ones I've mentioned early. So when it comes to that, we get relatively blind about what phase the hydrocarbon is coming out of the ground. If we were spending tons of money in new areas that didn't have any production, that'd be a completely different beast. But like we've been here and we've done that and we're hugely confident in the hydrocarbon streams that are going to come out of these areas, there's just too much localized offset information to ever throw us a curve ball. So we’ve a lot of confidence, we've executed last year. So we will pursue this program unapologetically with respect to hydrocarbon mix. When it comes to, where we're going to drill and when we're going to drill, the overriding factor is just logistics being able to move a rig just a few miles down I-35 from Horned Frog Northwest to Horned Frog just makes great economic sense. And you're kind of measuring savings in the six figures. But we pay a lot of attention to that stuff. So that's the predominant indicator. We in the case of Sooner, we had to wait for three days to get in and we had to reprocess it and we had to be patient with those kind of things. But by and large, it's really just rig logistics and minimizing rig moves and making sure we're spending every penny wisely.

[Ron Mills:]

Great. Thank you very much and great quarter.

[Operator:]

We have no further questions in the queue.

[Frank Bracken:]

Well, thank you all for your time and attention and questions. Hopefully, we can weather the lack of interest in the space and we continue to generate results that are positive for the underlying value of the company.

[Operator:]

Ladies and gentlemen, this does conclude the Lonestar Resources fourth quarter 2018 financial results conference call. Thank you for joining us today. You may now disconnect your lines.