Lonestar Resources US, Inc. (NASDAQ:LONE) Q2 2019 Earnings Conference Call August 6, 2019 10:00 AM ET
Frank Bracken – Chief Executive Officer
John Pinkerton – Chairman
Conference Call Participants
Neal Dingmann – SunTrust
Jeffrey Campbell – Tuohy Brothers
Dun McIntosh – Johnson Rice
Jim Musel – Intermarket
John Fichthorn – B. Riley
Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources' Second Quarter 2019 Financial Results Conference Call. At this time all participants are in a listen-only mode. [Operator Instructions]
Please note, this conference is being recorded, today, the 6th day of August 2019. I would now like to turn the conference over to your host, Frank D. Bracken, Chief Executive Officer. Please go ahead, Frank.
Thank you, I'm joined with a full accompaniment, of our management team and our Chairman, John Pinkerton. Before I get started, I have to direct you to the cautionary note regarding forward-looking statements on Page 2 of the presentation.
Now, if you would please turn to Page 3 from my opening remarks. Lonestar reported a 22% increase in net oil and gas production to 13,630 BOE a day for 2Q compared to 11,140 barrels a day a year ago.
Reported volumes exceeded the Company's guidance 12,400 to 12,800 barrels a day and actually also exceeded our preliminary estimated results of 13,500 barrels a day announced on July 8.
Production was comprised of 78% crude oil and crude oil and NGL's on an equivalent basis. As Lonestar brings new wells onstream at rates that continue to exceed third-party type curves, production continues to climb rapidly. For the month of July, net oil and gas production exceeded 16,000 barrels a day.
We also reported a 15% increase in EBITDAX to $33.5 million, which also exceeded our guidance of $30 million to $32 million. Net EBITDAX performance was a function of a winning combination of better than guided production growth combined with excellent wellhead prices.
Lonestar's Eagle Ford Shale assets continued to deliver outstanding wellhead realizations, through the second quarter. Crude oil realization was $63.05, which reflects a $3.24 premium to WTI.
Lonestar's 2019, drilling program is, delivering exceptionally good results. In April, we brought on the Horned Frog northwest wells, which has produced an average 114,000 barrels a day equivalent through their first 90 days exceeding their type curve.
In May, we brought on a four well pad and Karnes County our Georg 3 through 6H wells, which delivered average Max IP's over a 1,000 barrels a day and are outperforming our third-party type curves by 19%.
In June, at Horned Frog South we brought on our two F1 wells pads which delivered average Max-30's of nearly 2,500 barrels equivalent a day, a record for the Company and well ahead of the type curve.
More recently in July after the quarters end we brought on our first three wells in DeWitt County on our Sooner property, which we acquired late last year. And those wells recently tested at rates of nearly 3,500 BOE a day, 53% of which was liquids.
All this good news has caused us to issue 3Q production guidance of 17,000 to 17,500 BOE a day. That equates to sequential growth at 22% and I think considerably outpaced analyst consensus.
Furthermore, we've issued EBITDAX guidance of $36 million to $37.5 million. Lonestar continues to utilize commodity derivatives to create a higher degree of financial certainty in our cash flows and returns while mitigating financial risk.
During the second quarter we added hedges, which bring total swap volumes to a little over 7,300 barrels a day for bal 2019 at a little lower than $55 and added hedges which bring total swap volumes to nearly 7,500 barrels a day for cal 2020 at an average price just under $57. We also started to build our cal 2021 book.
Lonestar also hedged Henry Hub natural gas swaps, covering 15 million a day at an average weighted price of $2.82 for bal 2019 and added 15 million a day for cal 2020 at an average price of $2.59. Who would have thought that ever would look good?
These hedges further insulate us from fluctuations in the commodity price – product commodity market and give us the ability to execute and deliver the results that we're telling you today.
Given our outstanding drilling completion results, deep inventory, strong hedge position, we've materially enhanced our financial outlook. For 2019, we've increased guidance from 13,700 to 14,700 barrels equivalent a day, to 14,800 to 15,000 and our guiding to EBITDAX of $135 million to $140 million for the year.
For 2020, we now believe we can achieve our previously issued production target of 17,000 to 18,000 barrels equivalent a day while drilling 20 to 25 fewer percent wells in 2020 and therefore spend materially less capital.
Lonestar’s 2020 target yields a range of cash flow outcomes that generates $5 million to $20 million of free cash flow. Please now turn to Slide 4, so we do some house keeping on our quarterly results.
Company reported 13,630 barrels of oil equivalent for the quarter, an increase of 20% sequentially. 2Q production volumes that consisted of just under 7,800 barrels of oil, which is 57%, 2,900 barrels of NGLs, which is 21% and 17.6 million a day of gas or 22%.
Company’s Eagle Ford Shale assets continue to develop, deliver outstanding wellhead realizations. The oil price was $63.05, which reflects a $3.23 premium to WTI. The NGL price was soft as it was for everyone. NGL price was $13.44 or 22% of WTI. This was really a function of a significant drop in ethane prices and propane prices, compared to the first quarter, which is a winter heating quarter.
Lastly, our realized gas price at $2.46 was a $0.10 discount to the Henry Hub. This discount was really driven by an increase in gas sales at the end of the quarter, associated with our Horned Frog South F wells when gas prices were at the lowest period in the quarter. I might also add, we are selling into the daily market, which compounded that issue.
So it's really just algebra on when we sold the most gas that caused that discount. Operating revenues increased sequentially by $11.5 million to $52.2 million or a 28% growth. This was really a function of a 20% increase in production, coupled with a 6% increase in commodity price realizations.
Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general and administrative and interest expense, we're just over $25 million for 2Q. While cash operating costs rose 9% on a dollar basis, strong volume growth yielded a 10% reduction on a per unit basis to a little over $20 a BOE. The result of the increased revenue per BOE while we reduce cash operating costs resulted in a 27% increase in our cash margins on a unit basis.
With the ramp we're seeing in third quarter production, we should continue to see improvement in our cost structure on a per unit basis. I'll now do a deep dive into all the new wells we brought on since our last quarterly report. It's really these wells are the driver to our rapidly improving operational and financial results. And I'll do so in the chronological order.
Please now turn to Slide 5. We're going to start out on LaSalle County on our Horned Frog Northwest property. The majority of the acreage we acquired here came from relinquishments from our major oil company, who did not meet continuous development obligations associated with their units and Lonestar was able to lease these tracts at around $1,500 an acre.
Early in the second quarter, Lonestar began flow back operations on two wells, the Horned Frog number four and number five wells. They're shown in red and the pad location is designated with a red star in the map on the top left corner of Slide 5. I would add at the beginning of the year, we did expect to have a small working interest partner in new wells associated with their ownership and a tract that allowed us ultimately to drill really long laterals here.
In fact, we were able to execute a trade that allowed us to own 100% in these wells. So we spend about 10% more money here as a result and we're really happy about it. These wells recorded Max-30 production rates of 1,453 BOE a day and through the first 90 days, these wells have averaged 1,252 BOE a day, which is 2% better than the parent wells we drilled in 2018 on a per foot basis and 5% better than the third-party type curve.
I think it's really impressive that our 90-day production rates which are being choke managed to maximize oil recoveries are not much lower than the Max-30 day rates. The graph in the bottom left – bottom right of the page shows how flat production rates have been. I would also add that current oil rates are 35% higher than are forecasted by the tight curve. Not surprisingly, we plan on drilling more wells in this area in 2020.
Please now turn to Slide 6. On our last call, we showed you the parent wells, the number 2H and 3H drilled in 2018, responded well after being hit by our child wells, our previously discussed 4H and 5H. We now have another 90 days of production in our belts here and it's still a happy family.
We have actual oil production and the Von Gonten type curves in green and actual gas production and Von Gonten projections in red in each of these graphs. The parent wells shown in the graphs on this slide have outperformed their year-end type curves by 10% and are exhibiting nearly identical production trends that they were prior to the offset fracs.
Unlike the Permian or the SCOOP/STACK, where operators are still faced with a difficult task of establishing proper space in each ZIP code that are actually devoid a well history at varied spacing that would have helped them do that. We have reams of data in each of our operating areas that give us a huge head start in getting spacing right. I would also credit our frac design to the positive parent-child relationships that we demonstrated here.
Now please turn to Slide 7. Our 2019 wells in Karnes County follows six wells we placed on-stream in 2018 and the company has continued to improve on prior results. Our 2018 A pad and B pad are designated on the locator map in the top left quadrant and the four 2019 wells are highlighted in red with a red star. By acquiring offset acreage contiguous to our existing leasehold early this year, Lonestar was able to increase lateral lengths on our 2019 completions by 18% compared to 2018 wells.
And these wells continue to exhibit modestly better productivity on a per foot basis through 60 days, which should improve economics. Our 2019 wells have outperformed their type curve by 19% thus far. And I would add that all of our remaining locations will benefit from our lease acquisitions and therefore should all exceed 7,000 feet in perforated interval.
We own an 80% working interest in these wells and we're drilling these wells for under 6.5 million a copy and recovering over a little over 600,000 BOE, about 90% of which is oil. So undoubtedly, we plan to follow up on our success here with more activity in 2020.
Please now turn to Slide 8. Lonestar’s newest wells on its 4,975 acre Horned Frog South property represent continued progress in the advancement of our geo-engineered completion practices. Our new wells are longest yet at 12,300 feet are shown in red on the map in the top left corner and we're drilled on a combination of legacy acreage and recently acquired acreage. Based on some outstanding petrophysical and geophysical analysis done by our technical team, we've actually geo-steered these wells in a fashion that migrated our target into a second bench of the lower Eagle Ford mid-lateral.
Consequently, our three bit lateral logs for these two wells have demonstrated the highest effective porosity that we've achieved today in the greater Horned Frog area. The production results reflect these technical advancements. On a per foot basis through the first 30 days, our 2019 wells have recorded production rates are 20% higher than our initial pad at Horned Frog, completed in 2015 and 8% higher than our more recent Horned Frog wells completed in 2018.
The graph in the bottom right quadrant of Slide 8 shows that our 2019 Horned Frog wells recorded Max-30 IP rates that eclipsed 200 barrels equivalent per foot, and more importantly, are registering oil production rates that are 18% – 17% better, excuse me, than our 2018 completions on a per foot basis.
Lastly, today, the graph in the bottom left quadrant on the slide demonstrates that our 2019 Horned Frog South completions are materially outperforming the projections of our third-party engineers, 25% today to be exact. A tremendous result for a couple of probable wells, which are offset by some wells seen on that, on that map that are not even remotely economic. Again, great results. We plan on repeating them in 2020.
I also want to take a minute to take a step back and reflect on the tremendous impact that our technical evaluation – innovations have had in our Horned Frog South area. Please turn the slide now to discuss. When we acquired the most significant block of acreage in Horned Frog South, the farm-in with ConocoPhillips, our third-party engineers studied all the immediate offsets and arrived at an EUR of 1.5 million BOE, shown as the dash black line on the chart.
We drilled our first two wells to HBP this acreage and satisfied terms of the farm-in in 2015. These wells were completed prior to our Schlumberger joint venture and do not reflect the benefits of our geo-engineer drilling and completion process. However, our 2015 wells whose production history is shown in blue on the graph significantly outperformed the type curve and are booked as PDPs with 2 million BOE of reserves. Accordingly, our third-party engineers revise their type curve up to 2 million BOE, which is shown as the solid black line.
Last year until 2018, we drilled the G and the H wells, which were our first effort with a full benefit of our current drilling and completion process. Those results are shown in green. The benefit of our completion techniques are clear as our 2018 wells that have outpaced the type curve from the get-go. And at year end 2018, Von Gonten revised their EURs to 2.3 million BOE a day – to 2.3 million BOE.
Well, it's early. We're extremely encouraged that we move the needle again with our 2019 iterations. These wells achieve better porosities, had higher profit and fluid loadings with advanced diverter applications and we're steered into a second target that we thought had a good chance of being oilier. While it’s earlier, our own internal projections are that our 2019 wells are on track for EURs at 2.7 million BOE. So in a very short period of time, massive improvement and what we come to expect from reserves when we drill wells in Horned Frog South.
Now please turn to Slide 10. We've owned Sooner for about eight months now. We've instituted a lot of positive change. In terms of the higher upside projects, our Chief Geophysicist had the 3D seismic reprocessed in depth and has remapped the structure in the area. Our conclusion was that the prior owners saw major faults shown as the brown hash lines that either do not prevail in Eagle ford time in actuality or do not have sufficient throw toward our targeting efforts, which opens the door for longer laterals here. With this knowledge, we've also laid some additional land shown in blue, which sets us up for longer laterals in the future. Those efforts are ongoing and very, very inexpensive on a per acre basis.
In late July, Lonestar began flowback operations on three gross – three net wells on its Sooner property. Those wells are known as the Buchhorn 4, 5 and 6. Yes, that's how you spell Buchhorn. These wells are the first wells Lonestar drilled on its Sooner property and were drilled to total measure depths in excess of 20,000 feet. Lonestar fracture stimulated these wells with an average proppant concentration exceeding 2,000 pounds per foot over 21 stages using diverters. Recent production on these rates – on these three new wells have averaged nearly 3,500 BOE a day, and we've been encouraged by the oil productivity as well as the BTU content of the gas, which will yield lots of NGLs.
We're very encouraged by the productivity generation generated by our techniques here. We've invested in Geoscience here that's allowing us to extend laterals. The chart in the bottom left quadrant shows you how we've been able to extend our laterals already at negligible costs, which will have very positive implications for future economics.
Last thing I'd point out that 3,500 barrels a day, while it's only a test, compares very favorably to the 30-day rates exhibited by other wells along strike here. So, very early, but we're looking pretty good here.
Now turn to Slide 11. We update this every quarter. The chart in the bottom left quadrant shows you that we've accomplished a lot of our planned drilling for the year. By midyear, we placed 11 wells, 11 of our 20 planned wells on stream and had concluded drilling operations on the three Sooner wells, which commenced flowback here recently. We've also completed drilling on the Brazos County well as well as two wells in Marquis, meaning that we've already drilled 17 of our 20 planned wells for the year.
The frac schedule is coming along too, with 14 of our wells already having been fracked by July, three more fracked in this – in the third quarter, two at Marquis and one at Brazos County. So we're making great progress on executing the plan in a very timely fashion.
I now ask you to turn to Slide 12 for my closing remarks. Our outstanding well results are driven by operational and financial execution. July production exceeded 16,000 barrels equivalent and our third quarter production guidance is 17,000 to 17,500 barrels a day, which represents a sequential growth actually of 25% to 28%. This will lead to further growth in EBITDAX.
Our performance to-date has also resulted in an increase in our 2019 production and so we’ve guided that up, taking the low end of that range above the high end of our prior guidance. Ramped up volumes should also result in significant improvements in LOE per BOE and G&A per BOE knocking roughly $1 a barrel off of each of those for the third quarter. Perhaps the more impactful result from our 2019 drilling program comes in the form of the considerable flexibility those results bring to our outlook for 2020.
At the beginning of the year, we issued a 2020 production target of 17,000 to 18,300 BOE a day. And our thinking was it would take 20 wells in 2019 and another 20 wells in 2020 to generate those results based largely off our third-party forecast. The good news is that we’re materially had above even our own expectations and while this budget hasn’t been approved by the board, our forecasting indicates that based on current levels of productivity and declines associated with new wells, we can achieve our 2020 production target with considerably less capital, which would result in free cash flow.
I would note that we did tick down our 2020 EBITDAX target by $5 million on each end of the range to reflect a reduction in our Henry Hub gas price forecast from $2.75 to $2.50, which is generally reflective of the strip for that period. I would also point out that we’re highly hedged for 2020, which provides a lot of security to the targets I just outlined.
I’m sure, I’m going to get the question Frank, what are you going to do with that free cash flow? And when are you going to do it? I’ll go ahead and answer that question. My answer is that depends, but I want to be clear. I think the board values liquidity over everything else and we want to make sure we’re squared away there first. So chronologically, a potential sale of our Brazos County asset comes first, we’ve hired, we’ve engaged in advisor, we’re building data room now and I’m fairly comfortable that we can get a fairly large multiple of what that asset contributes to our borrowing base, meaning that a sale would be highly accretive to that borrowing base in our liquidity.
We’ll bring our Brazos well online in late September and we’ll immediately commence a sales process. Assuming that we get that asset sold, and our borrowing base continues to grow as it has, we’ll be in a position to consider a much broader array of options as we actually began to generate free cash flow. But in summary, and this is just a CEO talking, not the board quite yet, I think the pecking order is generally one debt reduction to enhance liquidity; two, share purchases at the stock is cheap and if it’s preventing us from expanding the company; three, leasehold acquisitions, as we’ve been able to do this year and four, additional drilling.
I think the best news of all is that I think in terms of our daily business Lonestar is performing like few others and next quarter we’ll really move Lonestar up in terms of production and down in terms of cost structure. We have peripheral assets for which we think there’s a healthy appetite that can help us manage our portfolio and improve our liquidity. And so in short, we have a lot of choices in 2020 and we think any of them and all of them can improve our stock price.
This concludes my prepared remarks. I’m going to turn it over briefly to John Pinkerton, our Chairman for a few concluding comments.
Thanks, Frank. First, I want to congratulate the team to a fantastic quarter. Hit the ball out of the park. What frank didn’t talk about was, we’ve added – we’ve got a great technical team, but we’ve added some folks recently that are going to supplement and add to that. And they’re doing a great job. It’s fun to see them integrate into the organization and they’re going to add a lot.
Looking back, I came to Lonestar in early 2016 as Chairman. Lonestar was really in a tough spot. We had way too much debt. Oil prices were in the 40s and our production was around 2,600 barrels a day, clearly not a pretty sight at all. But what I saw over the several months, while I was considering it is that we had an incredibly innovative and high quality technical team and they were doing things in the Eagle Ford that simply nobody else was doing.
I really found that very, very inviting. I thought if we could write this financially by reducing debt and extending the maturities of our debt, we’d have the runway and a chance of building a very successful Eagle Ford focused company. Fortunately, we’re well on our way to doing just that. Production is now over 16,000 barrels a day, or 6 times the amount when I first came here. Well, we still have to improve our debt metrics, we’re clearly out of the danger zone with an annualized debt to EBITDAX running now below 3 times, and should be close to 2 times – closer to 2 times by the end of next year.
So what do we do? And this environment, obviously pretty tough environment for industry. What do we do? With Lonestar that’s pretty easy. We’ll continue to focus drilling really high quality wells in the Eagle Ford, which what I believe is one of the top technical teams in the business. Said another way, we’ll stick to what we’re really good at. We’ll continue to high grade and build and high grade our acreage and our drilling inventory. The good news is, we already have many years of what I call, a quality locations for our technical team to exploit.
Looking a little higher level, strategically, I think we’re in really good position. We have – as I mentioned, I think the key to success is, we have really high quality proven technical team. We’re in a basin that produces 70% plus liquids at above product premium – with above product premium prices. We’re in a basin that’s very large and where many of the large companies have cut back or leaving. Said in another way, we’re not having to compete against the Exxons of the world for acreage and services. Also the Eagle Ford is a basin that continues to evolve dramatically.
Many wells were drilled during the boom with old drill and completion concepts and in bad services. At Lonestar, our technical team is drilling wells that are two or three times better using incredibly state-of-the-art methodology. Said in another way, we just – we’ve developed a better mousetrap and that’s why our wells are just so much better than the offset wells and are exceeding third-party type curves in a material way. So said again, it’s pretty easy to figure out what we should do going forward. That is continued to drill high return Eagle Ford wells build our EBITDAX and cash flow, while we continued to reduce leverage and strengthen our balance sheet.
So, on a relative basis I’m extraordinarily highly confident with our strategy and our ability to execute. Second quarter results were outstanding and record. And I’m quite confident that third quarters results are going to clearly top these and set another record for our company. So I look forward to that.
Lastly, I’m not the smartest guy on the planet, but I don’t have to tell you that how difficult the circumstances are for many companies in our industry currently. Clearly, our industry is changing and evolving in a big way. Many companies are having to completely rethink their strategy.
As I’ve said just a minute ago, we are extremely confident in our strategy and our ability to execute. We have an inventory and a technical team that can generate consistently high returns with the current commodity and price environment. What we’ll do is continue to drive up EBITDAX and cash flow, reduce leverage and increase our shareholder value.
In summary, we know what to do. That is continue to focus intentionally on our technical ability and drill our Eagle Ford portfolio. With Lonestar, we have a simple strategy and a great team to execute it.
Frank, back to you.
Thanks, John. Operator, I guess, we’re ready for questions.
Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] We will now take our first question from Neal Dingmann with SunTrust. Please go ahead.
Good morning, guys. Thanks for the details. Frank, looking into Slide 5, can you talk a bit more on just now what you’ve learned and how you view your spacing around, let’s particularly looking at the Horned Frog and how that plays in? How you assume your upcoming results versus your type curve estimates?
Yes. We’ve got a decent amount of experience out here. And the offset map is littered with examples of excessively tight spacing. So everything out here is been 700 foot spacing. It clearly is yielding outstanding results. We’ve see zero wellbore interference between well pairs and pad pairs. And the recoveries that we’re getting do not appear to be impaired in any way by offsets. So look, I think we’ve got the – we get the worst case scenario out here. We have talked internally about doing some evaluation and see if maybe there is a slightly tighter spacing that we can achieve out here. But don’t expect us to come do anything crazy like drop wells in between these – or anything like that. Our view is that on average we’ve been drilling about 20 wells a year. You can’t waste any of them. They’ve all got to be perfect. And so our level of experimentation, our tolerance for it’s pretty low. We’re not going to go drill any 23 well pads anytime soon.
Frank, and then my last follow-up. Probably, again, you guys definitely accelerating and definitely seeing the efficiencies as probably just my opinion, maybe the higher than group average debt that probably keeps you down a little bit. With that said, and given how economic these wells are – I know that the investors are pushing to continue to cut back, but is there a thought of, given the high economics of these wells? Is maybe try to push through this accelerates so that you can get up to the other end and pay this debt down quicker?
Yes. So let me – look, we have this debt level because we made a simple moral and ethical choice that we’re going to try to save the company for the original investors. And we’d done so. We do live with an ongoing burden that’s beyond what we as a Board would choose is optimal. But I think the way we look at it is. One, we have been able to pay our assets back across the portfolio. And in the case of Pirate, we sold that and we’re still moving guidance up. So we’re selling assets and beating guidance. That’s trick.
So we have another asset that we want to get sold. We think that’ll make a not inconsequential hole in the debt. We continue to believe that and model that our borrowing base will continue to increase. So yes, look, leverage is critical. But without an equity offering, which would be extraordinarily diluted at this price. We’ve got to kind of go about it in a very measured fashion. Clearly, that is an option for the free cash flow for next year. That’s – I think that fully answers your question.
No, you certainly did. Thanks so much.
Our next question is from the line of Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning, Frank, and congratulations on the strong quarter. My first question is, if your Marquis tests turn out to be successful, could further Marquis drilling continue in 2020? Or is the 2020 plan more or less set in stone, because you’ve been fairly specific about it?
Well, the answer is we'll see. There are clearly lots of locations to drill out in Marquis. I think there's even a fairly lengthy refract – a candidate of refrac opportunities out there, based on the vintage of those wells. So we'll get, that the great part about what we're doing is, we don't have any HBP considerations. Internal rate of return is the only thing that will dominate the capital allocation decision. So, as we get some production history on those and evaluate the options, if they compete for capital with these other areas where we think we've just demonstrated tremendous results, then they'll find their way on the schedule. It will be in this current backdrop, probably at the sacrifice of something else. But, yes, it's an ongoing portfolio and management decision process that we go through.
Okay, great. Thank you. And my other question, I actually want to respond to something you just said a minute or so ago. You made the point of zero interference between well pairs, low appetite for experiments that you thought – had some thought about tighter spacing. And to me this brings up this IR versus NAV argument that a number of other E&Ps have discussed. So with that preamble, simple question. Do you think spacing that promotes general interference between the wells could enhance DSU, NAV?
It could. Look, there's, there's a difference between trying to rubblize rock in a set of wells drilled on an individual pad to maximize long term conductivity. That's its own technical argument. But I mean – I think anybody who looks at the strip and looks at results, I don't know how you would argue that value acceleration in this market is really a good thing, the mean a gas is 215 today, the strips 250. We actually look at it in a very different way. We're looking at these results as one that will – that have the potential to cause meaningful upward revisions to our third-party report. If you're drilling perfect and you space them perfect, it can have really positive implications for your bookings and in your implied NAV.
That's a very fair point at end. So I appreciate your thoughts. Thank you.
Thank you, Jeff.
Our next question is from the line of Dun McIntosh with Johnson Rice. Please go ahead.
Hey, Frank. Good morning.
Good morning, Dun
You all continue to knock it out of the park over the course of the year. And I know you're utilizing a lot of your third-party long Von Gonten type curves. As you kind of get more of an indebt, is there any thought to kind of incorporate that more into you all’s type curves looking ahead and modeling or how do you think about that going forward?
Yes. So that's a fair point. We've always based our budgets on third-party. I mean, I think it's just kind of a good practice. And it's consistent, but I will tell you that some – on a partial basis that high into that guidance, is a little more accepting of our recent results than the type curve. So that range is not nearly so much driven by the number of wells we drill, but by how wells perform. But I would say, it's still a fairly risked, manner of looking at it. We're not going to go jump into the deep end here. We can wade in and perform very really well.
Okay, great. Thanks. And then at sooner, it looks like some pretty strong preliminary results. Can 53% liquids and I think it was 15% oil, going in, we're kind of looking for a little gassier. Is that a function of landing or what do you think is driving that strong liquids cut?
That's good question. I say, it's very early days. We did a lot of petro-physics out here to pick our target. We don't believe that the target we – that the target was drilled out here previously was done so on a consistent basis. S0 maybe we've improve that result. We're also pretty stringent, choke managers and we're mindful of the rate at which we drawdown these wells. We're always mindful of dew point and we want to make sure that, that we maximize our condensate yields in heavy liquids in doing so. So little early days, but – and look, there's room to improve here. We learned a lot in these three wells and would hope that the next set of wells we drill out here takes the best practices that I think we've established over the course of iterating the three wells, and hopefully improves upon them further.
All right. Great. Thanks. That's it from me.
[Operator Instructions] Our next question is from the line of Jim Musel with Intermarket. Please go ahead.
So the second half CapEx is that – it looks like just giving your cadence in the first half it’s going to decline. Is that correct?
Yes, probably should a little bit.
Got it. What are you seeing with the oil service costs? I mean, clearly that they’ve been dropping. Is that still is your CapEx budget conservative? Meaning there’s room for that to decline as well?
Well, so let me answer a couple of things. I would point out the fact that we’ve been opportunistic. at sooner, we drilled an extra thousand feet at Horned Frog South. We drilled a little extra. And at Horned Frog North West, we drilled a little extra. So, those wells will have ended up costing more than we thought, but not by any cost overrun, just by being opportunistic and taking advantage of longer laterals and better economics associated with those. I think it’s being born out in the well results in states. So that’s the first point I’d make.
The second point I’d make is, is that by and large, we’re – we can have a mindset that we want to go into the year with revenue certainty and cost certainty. So, we hedge heavily on the commodity side and we tend to enter into longer-term contracts for – with respect to price on the expense side. So, what you will have seen with us is that our stage costs other than the efficiencies we can garner during the job to reduce costs. Our stage costs are fixed for the year. Our rig rates have essentially been fixed for the year. We are however, very optimistic that on the drilling side, that we’re – we will get, we will put better equipment to work under contract at the same or lower prices, implying better rates of penetration, faster drilling times and lower costs.
And then secondarily, I think the profit market has continued to soften and the pressure pumping market has become more challenged as the rig count has dropped. So, I think there’s betting man’s odds that our stage costs can come down. So, the good news is, as those are things that would positively impact our 2020 program.
Yes, exactly. And then you’ve mentioned as one-year priorities reduced leverage, would part of that be with the Brazos County sale and the free cash flow for next year that you could go in and purchase your bonds?
So first, I think the Brazos County sale will undoubtedly go immediately towards the repayment of the revolver. First and foremost, revolver liquidity is optimal, that should come right about a time when we’re re-determining as well. So, we’ll have a very fresh outlook on liquidity going into next year on that facility. Bond repurchase is something that we’ll evaluate and I guess, I could have put it on the – on my little list of priorities there, but I’d tell you it’s probably five. I don’t get paid in bonds. I get paid in stock. And I have about a million reasons to want to see the stock go up. So that would be the leaning, the leaning toward equity repurchase versus debt repurchase.
Got it. Thank you, Frank.
Jeff, you’re talking about bought back bonds at $0.48 a few years ago. So, I’m kind of cheap.
Our next question is from the line of John Fichthorn with B. Riley. Please go ahead.
Yes. Hey, Frank. Nice job on the quarter. It’s really there were a lot of very positive things that it was good to see and especially, I really liked the way you guys are talking about free cash flow and putting that line in the sand. So as a shareholder, I appreciate it. I know there’s a couple of different ways you can delever and one is to keep growing EBITDAX relative to your debt and the other is to actually generate free cash. And this shareholder is firmly in favor of the latter at this point. And so I just want to say congratulations on that. I also, in response to the last question, I have kind of two follow-ups. One is, what – you guys had mentioned free cash flow neutrality in the back half of that year – of this year, is that still where you are or have you backed away from that a little bit and kind of swap that out for next year’s free cash flow projection?
And then my second question is really around what you were just talking about, which is the share repurchase and what would it take given how to press your stock is even given the rest of the dynamics of your company and your balance sheet on amount of share repurchase would reduce a tremendous amount of the outstanding shares out, even if it were just $5 million or $10 million. And that would seem like a very accretive maneuver to future equity. And so I’d love to hear your thoughts on that as well.
Sure. So, those are all terrific questions and I appreciate your comments, John. As it relates to the capital program for this year, as I did mention, I think we’ve had some opportunities to spend a little more on wells. They get demands – it’s solely the function of drilling longer laterals everywhere.
I hope, I've demonstrated to all of you that the value in doing that. So, that could bump up the budget. the budget is a little bit in flux. but I would tell you, I think that, I think that there may be a touch of spending this year to set us up for next year. I would tell you this though, lastly, we can make these higher targets without having any production from our Cyclone/Hawkeye wells, of which we plan three.
So, we have that in our quiver as well, just theoretically differing drilling and/or completion of those. So, there’s a lot of flexibility around what we do. A lot of that flexibility is driven by the fact that we’re – frankly, we’re just crushing it in terms of production right now. So, it gives us optionality to do different things with our capital and think about it different ways. So, I’d say cash flow neutrality is probably, more difficult to come by in the second half, not woefully so, but a little more difficult to come by, and – but I think where it gets us for 2020 so far outweighs, any blip on that budget that I think it’s where we and you ultimately want us to go.
As far as share repurchase goes, look, it’s not lost on us, in any way, shape or form. We’re sitting here internally every week and month. And we’re telling ourselves we’re killing it. and it sure doesn’t – today is a nice day, but in aggregate, it’s – the stock has been punished, despite some pretty incredible performance, so that in and of itself tweaks the board sensibility about value creation and I think there’s a very active – there is an active dialogue at the board as to when to initiate it.
And as you rightly pointed out, $5 million or $10 million makes a world of difference at the current stock price. but I think the prudent thing to do is to try to get this Brazos sale behind us in conjunction with a borrowing base increase, which gives us a – well, a very clear-eyed view as to liquidity.
And I think that’s when we’ll get the most bang for our buck. We’ll be able to buy back, I mean, if it’s here, we’ll – I’d be a strong proponent of really getting after it. but it gives us the best balance of using some of our capital, which will become free cash flow, which will end up being free cash flow to accrete to the per share value of the equity and provide support for the stock, but also, not leaving any question that we have enough liquidity to run the business. So, I think it’s only about cadence, not about intent, or what we should end up doing with that free cash flow out when it comes.
Thanks a lot. I just one last quick thought, the free cash flow line for next year, you’re getting, you’re approaching neutrality this year anyway. next year, you’re positive. Is it the intent to continue growing that or kind of demonstrated and if the stock goes up and maybe you kind of reaccelerate the drilling program or is that just a TBD?
Well, look, we view the Eagle Ford as a basin, where we have vastly fewer competitors. I mean, I think the probability to a couple more of our direct competitors undergo significant reorganization in the near future is high. Most of our competitors are doing other things yet everybody seems to need to sell Eagle Ford assets to [indiscernible] me. That’s a good market dynamic and we want to be a participant. So, to do that effectively, we’ve got to have a much better stock price. So that’s – we can get a stock – a better stock price, a couple of ways we can perform, we can buy back shares and we can pray that people stop hating this group to the extent they do.
So, there’s ways to get about it. I just – I think we’re going to want to just be – we’re just going to want to be a little methodical. I think that frankly, with the way the wells are performing, if the next set performs that way, we can continue to grow production at rates, I think the market can find attractive, with the high end being spent cash flow, not the low end. that’s down the road. what I think we’re beginning to get increasingly focused on is these well results if repeated, can result in, a phenomenal combination of sufficient growth and free cash flow, which just creates a lot of optionality for us in ways to win for our shareholders.
Great. Thank you, frank. I appreciate those answers and keep up the good work.
Thanks, Frank. We have no further questions in the queue.
All right. Well everybody, thanks for your time and attention today. analysts, if you have any questions while you’re modeling this out, please call Chase or myself and we look forward to talking to you in three months. Bye.
Ladies and gentlemen, this concludes the Lonestar Resources’ second quarter 2019 financial results conference call. Thank you for joining us today. You may now disconnect your lines.