Lonestar Resources US Inc.
Q4 2017 Earnings Call Transcript

Published: 29 Mar 2018

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources Year Ended 2017 Financial Results Conference Call. [Operator Instructions] Please note this conference call is being recorded today, the 29th day of March 2018. I would now turn the conference call over to your host, Frank Bracken, Chief Executive Officer. Frank, please go ahead.

[Frank Bracken:]

Thank you, Daisy and good morning. With me today from Lonestar are our 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 newly appointed Chief Accounting Officer, Jason Werth; and our Manager at Corporate Planning, Chase Booth. Before I get started, I've got to direct you to the cautionary note regarding forward-looking statements, safe harbor, and disclaimer on Slide 2 of the conference call deck. Now on to Slide 3 for opening remarks. The last several months have been transformational for Lonestar and while not without significant challenges, Lonestar is on the launch pad. We're going to cover the following themes on today's call. First, 2017 was a year of significant accomplishment for the company. We assimilated two major Eagle Ford Shale acquisitions and now drilled our first wells on those properties in Karnes County. We recorded 70% increase in proved reserves to $76.2 million Boe and also increased through PV-10 by 70% to just under $650 million. The reserve growth yielded all-sources reserve replacement of almost 1500% at Finding & Onstream Cost of a very low $6.07 per Boe. Our fourth quarter while muted by a combination of delays and fractures stimulating newly drilled wells, and the impact of fractured from all set operators increased 59% year-over-year and adjusted EBITDAX rose 64%. In the fourth quarter, we also refinanced our 8 ¾ senior unsecured notes which review April 2019 with a new $250 million note which matures in 2023. This refinancing also automatically extends the maturity of our senior secured facility our revolver from October 2018 to June 2020. This financial accomplishments dramatically extend Lonestar's runway, and our liquidity available on our revolver which stood at $100 million at year-end. I cannot overemphasize the degrees of operational freedom that these financial transactions are going to afford us going forward. We take meaningful concrete steps to remove the uncertainties that the tight markets for energy service create companies like Lonestar and in fact companies much larger than ours. We've been frustrated by the fact that we delivered excellent results at the Wellhead on a consistent basis only to have them not reflected in our quarterly results in a timely fashion. I am pleased today to announce that not only do we have rigs under contract required to drill our entire 2018 program, but yesterday we executed an agreement with a leading pressure pumping provider that give Lonestar a dedicated frac spread and attractive pricing. For the first time, I feel like we have complete control in terms of delivering production from new wells in a timely fashion. We've now placed four extended reach laterals onstream at Hawkeye and Horned Frog that's for this year, and their productivity is meaningfully above expectations. The company has already brought on 4 gross/3.8 net wells. In January, our first two wells on our Hawkeye property in Gonzales County tested at average of 1,115 Boe a day and last week, we placed our second two wells online at our Horned Frog property in La Salle County and those wells are showing very promising results. Yesterday they registered average test rates of 1,941 barrels a day. Additionally, we've already completed our first 3 wells in Karnes County, and they are scheduled to commence fracture stimulation with our newly‐dedicated frac spread in early April which is very close. These wells are ramping up our production rapidly. Lonestar's guiding to production rates in the first quarter of 7550 to 7650 Boe per day. Off note is that Lonestar estimates that March production marginally benefited from the addition of the company's Horned Frog wells and estimates March production rose to 8350 to 8450 barrels a day on average. More importantly I think production is at first quarter exit rates of between 9500 and 10,000 Boe a day. And I’d like to add I think that exit rate is probably a very good representation of our expectations for April as a whole. So it's not a stock rate, it's one that we can sustain. Before I get into relative performance of Lonestar's 2017 capital program compared to an array - sorry, before I dig into our well results, I’d like to step back and discuss our 2017 accomplishments because I think there's significant in terms of building mass for Lonestar and I think we did say we’re at very attractive cost. So I’d like to turn you to Slide 4 now to complete this review. The slide shows the relative performance of Lonestar's 2017 program compared to an array of high quality oil and gas companies all of which are in fact much larger than Lonestar. The top graph shows all-sources reserve replacement for Lonestar and 18 public companies and is derived directly from SEC filings. Our reserve replacement came in at nearly 1500% which places Lonestar in lofty company and essentially our reserve replacement averages were twice the peer group average. The bottom graph shows All‐Sources Finding & Onstream costs for the same 19 companies. Again, Lonestar's Finding & Onstream costs of $6.07 per barrel are a great result and I would note that most of the companies, who bettered our [S&D] cost are much gassier than Lonestar. Our results are not anomalous. Over the past five years, Lonestar has delivered all-sources reserve replacement of 778% while accomplishing that at of All-Sources Finding & Onstream cost of $8.94 per Boe. Now please turn to Slide 5. The top graph shows that at NYMEX prices that was used for our year-end reserve report, we increased Strip PV‐10 by 70% to almost $650 million. I would remind you that we posted a very similar result in terms of increased proved reserves. In the bottom graph which attracted net debt and preferred value from that Strip PV‐10 and divided by the shares outstanding. The key messages are that one, we increased Strip PV‐10 per share by 33% to almost $11 a share. And two, that value dwarfs our current stock price. We believe that production growth and execution in 2018 to materially close that gap. I'll now ask you to turn to Slide 6. Before discuss our 2018 drilling results in detail, I want to review our phenomenon that's occurring across the end of the industry that hit Lonestar in a big way in the fourth quarter. Frac Hits and Parent-Child well relationships are very hot topics in the unconventional oil and gas business today. Here are fracs, in the fourth quarter, 16 of our producing wells were impacted by offset frac operations. In the footnote, we detail the Lonestar properties which were affected and the operator whose wells were "culprits". I think our lease waters were probably violated to the point that I empathize with the Ukraine right now. We got it from all sides. The graph on Slide 6 shows the production trends of these 16 wells in the months prior being impacted by offset fracs. In aggregate at its worse, the Frac Hits reduced oil production from these volumes by 60% or 800 barrels a day and reduced gas production from these well by 75% or 1500 Mcf a day. In total 4Q production was reduced by 173 Boe a day net to Lonestar. More importantly I think is the fact that oil production has actually rebounded above the trend line indicating a small net benefit and increment like gas production has been - has finally rebounded above the trend line albeit over a much longer time period in terms of recovery. To a large extent, we believe that our ability to restore production is largely due to proactive measures we take in our profit programs to protect against fracs, and having the proper artificial lift in the well bores that can handle increased fluids introduced by offset fracs. Let's now take a look at the results of our 2018 program. Please turn to Slide 7. Our first 2018 producers were in Gonzales County on our newly acquired Hawkeye area. If you are new to Lonestar, Lonestar closed a significant acquisition adjacent to our Cyclone property where we made great drilling results with the low cost scrappy effort to build an asset base. Lonestar acquired set of assets out of receivership that we now refer to as Hawkeye. That name just made sense and then it was next to be other high school. We paid $3.4 million on the courthouse steps to acquire 6257 gross and 1655 net acres which is a contiguous to our Cyclone position. The acquisition included 2.5 million of PDP PV-10 most of which is associated with wells that Lonestar already operates in Cyclone. That means we spent $900,000 on 1655 acres which equates to $543 an acre, and we didn't waste any time. We've now completed the Hawkeye Wells with an 87.5% working interest and they've now just been on production for 60 days. The top graph shows the results of those Hawkeye well compared to our 6 Cyclone wells we drilled to date. Our Hawkeye wells have registered significant improvement in 30 day rates shown for individual wells in red, and then 30 day rates on a per 1000 foot basis for each pad shown in blue. In short, the Hawkeye Wells that were 16% better than our best welfare which is our most recent at Cyclone and 28% better than our average well period at Cyclone. We've also got 60 day results in the bottom graph. Our Hawkeye well there registered significant improvement on a gross basis shown in red, and then 60 day rates per 1,000 foot also shown for pad shown in blue. To summarize, the Hawkeye wells are 16% better than our best welfare and 43% better than our average at Cyclone. We also share you in orange the well production forecast included in our third-party engineering report for our Hawkeye wells both at 30 and 60 days, and today these wells are outperforming the third-party projections by 17%. I’ll now turn you to Slide 8, to quickly review our Horned Frog wells. And while we have limited production data, the data is very encouraging. In our press release we announced that we placed these wells on in La Salle County. We are on 100% of these wells. These wells were drilled to total measured depths of approximately 22,800 feet and 20,950 feet respectively and were drilled from spud to TD in an average of 12 days. These wells were fracture stimulated and engineered completions with average proppant concentration of 1650 pounds per foot across an average of 40 stages and utilized diverters. Flowback operations commenced on March 20 and productivity is extremely promising. Bear in remind these wells have only been on nine days at the most. With only six days since first production and 2% of our loan recovered, the Horned Frog G1H tested yesterday at three stream rates of 1944 Boe a day and with just a little over 3% recovered the H1H which has actually produced 8 or 9 days of flowback produced hydrocarbons, that well which is a little shorter have tested yesterday at 3 stream rate of 1938 Boe a day on a limited choke. We put the production histories of our older Horned Frog wells in for your reference and clearly I think comparisons are very premature. However I would note that both charts show you that we brought these wells on very gradually and will continue to manage them from a choke perspective very aggressively. I think it's early but our rates exceeding 1900 Boe a day pushing 2000 Boe a day to day are really encouraging, and I’d also add that we're producing substantially more oil out of these wells than we had in prior well sets at Horned Frog. Not to rest on our oils, Lonestar continues to expand our leasehold position in this area via primary term leasing, the costs that are in line with our historically low cost. Ongoing leasing efforts prevent the company from disclosing commercial terms at this time but we believe that our efforts to date will allow Lonestar to replace 200% of companywide production in 2018. This acreage is a little up dip from our existing Horned Frog position, so we'd expect these wells that we drill in this area to have a higher oil component to the hydrocarbon mix which should make them even more profitable. Wasting no time we've already commenced operations on the Horned Frog North West #2H and 3H in which we hold 100% working interest. This deals really emblematic of our core strategy. In fact we're significantly outbid on a dollar basis in terms of leasehold on this acreage but the fact that we could dedicate equipment to immediately drilling two wells here gave us the win. Most mineral owners are smart enough to understand that the promise of nearly immediately loyalty checks dwarfs the - their lease bonus money particularly at the price per acre we are successful in paying. These kind of mini transactions are our highest return projects and our goal is do three or four of these every year with an objective of replacing 400% to 800% of our annual production for very little dollars out the door. Quickly, I'd like to turn - touch base with on Brazos County on Page 9. Wildcat B1H has produced 320,000 Boe in 10 months and its well on its way to producing 350,000 Boe units first year. These wells continue to perform 62% better than the average offset well, and 15% better than the best offset well and I would note that those offsets were drilled by a quality operator. We believe our results resulted in enhanced geo-steering, more efficient fracs, and more prudent choke management which is yielded much higher condensate recoveries. Generally speaking though, this area is not an area where we have a clean line of sight on meaningful acquisitions and while our results here have augmented returns, we're still going to be in a process of evaluating our options on this asset where we think we've leased at the value in this area with our partner. I’d like to turn to Slide 10 to wrap up my plan remarks. While later that we've liked, we’ve put four extended leach laterals on stream at Hawkeye and Horned Frog and their productivity is meaningfully above expectations. To review, our first two wells at Hawkeye are on at - over 1100 barrels a day and our first two wells at Horned Frog are closing in on 2,000 Boe a day. Additionally, we've already completed our first three wells in Karnes County and they are scheduled to commence fracture stimulation with our newly dedicated frac spread late next week in early April. Our production will exit the first quarter at 9510 to 10,000 barrels a day. I think that sets us up in excellent position to average between 10,000 and 10,700 barrels a day to achieve EBITDAX of $100 million to $110 million which is at $35 flat. And I think really the bottom line is, is that this exit rate is a great representation of things to come here. We finally got in control over the major variables in our Energy Service equation. Our drilling here and completion results have been terrific. We've now got the capability to deliver them in a timely fashion one that makes our analysts and shareholders happy of which we are included in that category. So, feel like we really turned a lot or corner and a lot of respects. Productions where we think it needs to be to set the year up for very strong growth. We've got control over our energy services and we're on our way to driving debt to EBITDAX to three times or below by the end of the year. So really encouraged by where we are right now in the environment that we're in. And with that, I'll conclude my remarks and turn it back to Daisy for questions.

[Operator:]

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

[Jeff Grampp:]

I want to start first on Slide 3 of your deck, you referenced some optionality to expand the 2018 capital program. Can you maybe give a little bit more color on what kind of thought process is? And then what you guys maybe need to see, what kept sensually accelerating the program at all?

[Frank Bracken:]

So I think first and foremost that, we're focused on creating a level of base production that will allow the company to be for all intents and purposes cash flow self-sufficient. So that's going to remain the primary objective. Clearly that program requires a kick start which causes us a little cash flow outspend. But, I think that's the primary objective. But what we didn't want to do is, we're seeing lots of opportunities. We unlike many of our peers, public private etcetera in the Eagle Ford have dedicated equipment and that's already - a lot of our competitors can't find rigs, they can't find frac dates and control of that equipment creates real opportunity, just as it did it in Horned Frog Northwest. So what we've done is, is we contracted all of our drilling rig needs for our existing program. We've contracted all of our pressure pumping needs. And we for all intents and purposes, we’ll run that frac crew end to end until our program's done. What we've done contractually is create optionality on the backend of our program so that if we find new opportunities, if we make acquisitions we can extend those services on the same terms and conditions through the end of the year pass when our core program that we've outlined you will be completed. So the good news is it doesn't create any financial obligation on us. We can terminate both of these contracts on 30 to 35 days notice. But we've got them under-wraps so that if we find things we need to tack on we can do so. So it's not a signal that we're going to ramp up activity beyond what we prescribed to you. It's really that we've gone up, we'll maintain optionality through the end of the year to continue to try to grab new assets with the drill bit.

[Jeff Grampp:]

And for a follow up, historically you guys have been really active on the leasing front and drill to earn type of deals, and we’re just kind of curious given your commentary on Horned Frog, is that potentially imply that especially given the couple of results here that your activity levels there could be quite higher as we move throughout the year?

[Frank Bracken:]

I think the likely scenario is that you'll see - you've seen the first two wells, you'll see the second two wells which are - I guess we've set conductor on surface on both of those wells at this point. You see those wells come on. But those are the only - those the only wells scheduled for the year. We clearly have the capacity to drill more wells here, but in fact we'll have held all of this acreage by production in Cal '18.

[Operator:]

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

[Ron Mills:]

Quick question on Horned Frog, the wells that you completed I know you talked about 16 million could be pounds of proppant and the use of diverters. Can you talk about how those wells performed? I know its early days, but relative to two year your prior Horned Frog wells, are you seeing productivity uplifts any other changes that you've seen from the addition of the incremental proppant and diverters and how that applies going forward?

[Frank Bracken:]

In fact we deployed relatively similar levels of proppant in the A and B wells. So it won’t be that it will be more the utilization of the diverters and the engineered completions to better target that proppant. I would tell you that it is way too early based on the way that we’re going to choke manage these wells to actually ascertain incremental productivity, but I would tell you that we’re encouraged. We're managing the flow rates out of these wells dramatically and the primary objective in doing so is to maximize the oil recoveries which I would tell you are - just by comparison that the oil recoveries on the G and H probably averaging about 430 barrels a day right now. By comparison I think peak day on the A and B we're around 240. So these do thus far exhibit a better hydrocarbon mix but I'd just tell you it's real early and you’re going need to see - I think you’re going to need to see 60 and 90 days to draw conclusions about relative productivity on a per foot basis. We’re kind of cheating right now. We've got these things, kind of harness back and we’re really happy to just watch them behave and do some analysis on them. As they're frankly, these rates substantially above our forecasted model volumes. So it's great before us.

[Ron Mills:]

And then can you talk a little bit about the Karnes County, I know you've drilled three wells. It sounds like the dedicated cruise is going to come in there here in the next week or so. Any kind of guidelines or guidepost that we should expect whether like how you're completing them versus offset wells in the area and you know how those offset wells perform so what we should try to look for?

[Frank Bracken:]

I guess - this Karnes County acreage is a gift to our completions manager ordinarily in this neck of the woods Cyclone and Hawkeye he is dealing with little to no upper Eagle Ford of any reservoir quality and he is also dealing with substantial Austin Chalk depletion which he's got to - he got to model when he execute its fracs. Here there's a 60 to 65 foot thick upper Eagle Ford section with relatively good hydrocarbon pore thickness and very little in the way of chalk depletion above him. So he is kind of in heaven. The best offset wells are immediately off our West lease line. They've been drilled and they were drilled and completed by EOG. They in our minds proved 330 foot spacing beyond a shadow of a doubt. They employ EOG techniques slick water and relatively high proppant concentrations of 100 mesh and kind of the John daily production technique, they grip and then rip him. They open up really fast and get really high rates. Those rates are range between 1,000 and 2,000 barrels a day on IP. We're doing it our way. Bill is designing fracs based on the logs that we have to TD to position the purse in the best spot. And to really try to get some frac height if you probably minimize half length but actually get some contribution from the upper Eagle Ford which I think will be very achievable. So, we certainly don't have the kind of flow rates that I have mentioned that EOG was producing and as we always do early on, we’ll be a little measured in the way we produce this but these are the highest IRR wells in the company right now, so we're looking forward to getting them on stream.

[Ron Mills:]

And then one last one. You mentioned Brazos County the recent Magnolia entry into the area via the inner west acquisition. How proximal is that to your acreage position, how and any thoughts on that in terms of potential impact on your as of what you do with Brazos?

[Frank Bracken:]

Well, they've got acreage that really completely covers Brazos County that's held by Chalk Wells, many of which are kind of getting on their last legs. But they've got a decent slug of acreage in our depth. They haven't drilled any wells at those depths but they do have a decent amount of acreage at those depths. So I take that as - generally as - look at all the activity that's occurred in the last 24 months in Brazos and Burleson County. I take that as a validation that lots of people with lots of money have seen as a very viable place to deploy capital. And I think that that's something we've got to take into consideration.

[Operator:]

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

[John Aschenbeck:]

My first one relates to 2018 production profile, just - I apologize if I missed this but I'm just looking at your Q1 guidance and you Q1 exit rate. And then just comparing that to your full year guidance it implies you should continue to realize some nice growth throughout the rest of the year? Obviously a big step up in Q1 but then again you know the rest of the year Q2, Q3, Q4. So I was just trying to get a feel for that production profile and I was wondering if we should expect that growth to be fairly linear throughout the year?

[Frank Bracken:]

I think that generally speaking the analysts are all right in the right zip code for the second quarter. I think that what you will see is a little bit of an acceleration in activity in on-stream time in the third quarter. We do have - we will rig up our second rigs here next week and it will go back to Cyclone to drill a couple of 10,000 foot laterals. So the middle of the year will be pretty loaded. So we would expect to see higher rates of production clearly in the second half than we do in the first half. We've got an updated completion schedule on Page 16 in the Appendix that gives you our current best lead on completion dates. So you can see that while achieving upwards of 10,000 Boe a day currently, the second half of the year we'll see substantially more completions in the first half of the year and you guys are pretty good at doing the algebra on, on what that will do to production.

[John Aschenbeck:]

And so then my follow up here is just, was hoping to extend a little bit more here on the Eastern Eagle Ford. If you did indeed pursue some type of monetization of these assets, I was - I want to get your thoughts on what you would be inclined to deal with the proceeds. Would you look to potentially add a third rig and accelerate? Would you pay down debt perhaps combination of a two?

[Frank Bracken:]

Well I mean, I think the immediate use of proceeds would be to reduce debt. Right? We've done so much in terms of improving the operational performance of the company, getting our debt maturities into a tenure that allows us to focus on just executing as opposed manipulating the balance sheet. So clearly the first thing you do is pay down a revolver right, and get the debt into a really healthy metric if you will. But we see – look I mean there is news every day about another Eagle Ford guy another company selling Eagle Ford assets. We think that our opportunity set is really robust in the Central and the West so I think you would most likely see us try to aggregate more assets. My view on accelerating drilling is that, we’re in a window where buyers and sellers can come to a common view on asset prices and that we need to do as an organization be aggregating as much raw material as we can in this price environment. We got so much what we have HBP that we’re going to let we’re more on an asset gathering mission then a production accelerating mission. I think we prefer to be self-funded still organically grow double-digit production growth and use what capital availability we have prudently to bolt on more assets to the company as I think we've proven we can do quite well.

[Operator:]

Our next question comes from the line of Evan Templeton with Jefferies. Please proceed with your question.

[Evan Templeton:]

Just wondering if you can maybe just run through a little bit what you see in terms of your inventory your number of drilling locations at Hawkeye and Horned Frog as well if you have I’ll add Battlecat?

[Frank Bracken:]

So, and these will be, I might be off by one or two but we’ve got 13 remaining locations of Hawkeye. We got a line of sight on continuing to expand that position in the same way we acquired it so really low cost on the front end. We got oh call another 25 locations at Cyclone. We’ve got between our three positions now at Horned Frog we've got call it pushing 40 locations at Horned Frog 35 to 40 all of which can be drilled in the kind of lengths that we discussed today. And then on the Battlecat acreage I want to say we’ve got another 40 some odd locations that we would drill on 330 foot spacing. So thanks for helping me make a very important point, the places that we are executing now and I think getting really good feedback from our shareholders that these are places they enjoy us spending money. We’ve got deep inventories here so what you see this year is what you’re going to see next year, is what you’re going to see next year is what you’re going to see in 2020 in terms of baseline execution. We clearly want to continue to both things on but this is going to get predictable for you. And I think really de-risk I mean we’re showing the results we’re going to keep doing more of the same we’re getting six and seven and eight yards on first now. We’re going to keep with that game plan

[Operator:]

Our next question is a follow-up question from the line of Ron Mills with Johnson Rice. Please proceed with your question.

[Ron Mills:]

To follow up on that - in that last point in your answer to John's prior question. Can just give us a sense as to what the A and B market or pipeline looks like right now in areas that you know you would be considered kind of offsetting to your activities?

[Frank Bracken:]

So organically in kind of little bite size pieces, there's still - I would call it merchandise out there and a lot of are things we create with our reputation in the field. We create with our ability to replace wells on acreage that we've held with new acreage that we can hold. That organic pipeline looks pretty good. I mean we've got line of sight on additional little 1500, 2000 acre bolt on. So that's - and I want to emphasize that we're developing enough presence in these areas that are our core areas that we literally in some cases have land owners calling us now. They've heard from their neighbors that we’re good guys and boy that checks are fat from the wells we’re drilling. And so our success is reading a little additional success. In the data room driven property market, it's a continuum pioneers and their partners have announced they're going to sell - we'll be in another data room next week on our producing property acquisition with a lot of running room. So there's a lot of that hitting the market. And while we don't, we tend not to quote unquote any of those. We continue to be active participants in the processes. Lastly I think and most importantly, what we're trying to do I think is, is a little harder work but with hard work usually comes disproportionate advantage. We've got a very active effort out where we've identified individual assets within Eagle Ford portfolios that we think are non-core. We go get validation that impact the operator things that are non-core and we go work on unsolicited acquisition offers. So we're busy. I mean, we've got to get a very capable staff that’s focused on it. And each one of those layers is important, you get a turnover a lot of rocks to build the thing like we have and the bottom line is, is that the industry is a net seller of Eagle Ford and they're a net seller and a volume I think that that means that if we are diligent we'll get our fraction of the opportunities.

[Operator:]

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

[Frank Bracken:]

I'm going to wrap it up. We're going turn the mic over to our Chairman, John Pinkerton.

[John Pinkerton:]

Thanks Frank. And thanks shareholders. To give you my perspective, I got here two plus years ago. They asked me to be Chairman. I studied the company and what really brought me here was the quality of the technical team. These are some seasoned professionals they really know what they're doing. I was really impressed by them. Obviously the company was in bad shape, near bankruptcy. So we really spent the first two years while I was here fixing the balance sheet. We raised equity and we reduced debt, our debt today is even as lower - meaningful lower than when I came here. Importantly during these 10 years, we continue to drill wells and we let our technical team to continue to advance their expertise in learning in the areas of the Eagle Ford where we're really focused on. And all this really means is that, I think that after looking at all this is that the first quarter of '18 is really the turning point for this company. As you see on Page 10, the last 2 quarters our EBITDAX was over $20 million each quarter. You know those numbers should jump up to the next line here pretty soon over the next few quarters. I feel really, really confident with the guidance that Frank and the team have put out into the production and EBITDAX. I think we talk about wells and production rates and all that kind of stuff, but I think at the end of the day it all - what it really means is driving up cash flow and EBITDAX on a per share basis. Now that's really what's going to drive value for our shareholders and that's what I'm really focused on is, is turning all those production drilling all this effort from barrels and MCFs into dollars and really driving it to the bottom line for the benefit of shareholders. And I really see it this being the turning point I think. The first quarter of this year is going to be a Aha moment for the street in terms of the value we’ve created here. So I’m really excited. I’m very proud of the team and the employees that really hung in there during a pretty difficult time. So we want to applaud all the employees at Lonestar for all the excellent work and really hard work. These acquisitions that we took on they did a - Barry and the team really done a tremendous job integrating those. Our reservoir team and our technical team and what Tom Olle has done a spectacular good job in terms of really understanding the reservoir working up our banks and all that kind of stuff. So, really pleased with that. Also pleased with the Frank, our CEO. We're office right next to each other and talk every day. He has done a fantastic job, he is extraordinarily hard worker and somebody that I'm excited about seeing continuing to grow in his role and lead this company. So as Frank mentioned his quote was around the launching pad I totally agree with that. I think we're in great shape. I think our first quarter numbers are going to be fantastic. And then obviously the key is going to be on a very disciplined basis continue to execute our game plan. And what I keep on telling the team is, we need to execute without excuses and you all pay us to know when it snows and when rigs don't show up on time, and frac crews don't show up on time and pipelines crews don't show up on time. It's our job is to take all that into account and put a business plan together which really drives value for the shareholders and that's what we are. We finally ended up doing that. We've got a financial balance sheet now that allows us to do that. So I'm extraordinarily excited about what we’re going to be seeing in the first, second, third and fourth quarter of this year. I think it's really going - it's going to be a really an exciting year for the Lonestar and I think the big winners here are going to be the shareholders. I have invested some money in this company and excited for my kids and grandkids to really benefit from that. But I’m really excited for the company and its employees and also for the shareholders again I want to thank everybody on the call for hanging in there and I can assure you that you’re going to see a stock price materially higher in the future. I know despite the reticence in the market for energy companies, I'm convinced there’re smart investors out there that when your cash flow two bucks a share and your stock is four bucks and you got a big wide inventory and you’re doing the same thing over and over again. As we show that to people, I'm convinced the stock price will go up and our shareholders will be happy. So just excited about that and Frank I will turn over it to you to do any lasting comments so we can shut it down.

[Frank Bracken:]

No, I think - John has got a good perspective from up a little higher and we’re all enthusiastic about what we’re doing here. Corners been turned production wise, it will bring meaningful things to our margins. And most importantly I think if we just execute like John said without excuses, the stock valuation will handle itself and we’re all heads down on executing. So appreciate John's comments and appreciate your time today. And thank you very much.

[Operator:]

Ladies and gentlemen, this concludes the Lonestar Resources year ended 2017 financial results conference call. Thank you for joining us today. You may now disconnect your lines.