Lonestar Resources US, Inc. (NASDAQ:LONE) Q3 2018 Earnings Conference Call November 6, 2018 10:00 AM ET
Frank Bracken - CEO & Director
John Pinkerton - Chairman
Neal Dingmann - SunTrust Robinson Humphrey
Ronald Mills - Johnson Rice & Company
Rehan Rashid - B. Riley FBR, Inc.
Ladies and gentlemen, thank you for standing by, and welcome to the Lonestar Resources Third Quarter 2018 Financial Results Conference Call. [Operator Instructions]. Please note that this conference call is being recorded today, the 6th day of November 2018. I would now like to turn the conference over to our host, Frank Bracken, Chief Executive Officer. Please go ahead.
Thank you, and good morning. With me today from Lonestar are Chairman John Pinkerton and our entire management team. Before I get started I want to direct you to the cautionary note regarding forward-looking statements and safe harbor and disclaimer on Slide 2 of the conference deck.
Please now turn to Slide 3 for my opening remarks. Let me open by saying I'm extremely proud of these results which reflect the efforts of every member of the Lonestar team. Let's review our key messages for the day. First, Lonestar reported another record result, which featured a 63% increase in net oil and gas production to 12,471 Boe a day in the third quarter, which was also up 12% sequentially.
Production volumes exceeded the high-end of the company's guidance. That high-end was 12,200 barrels a day and we're 81% crude oil and NGLs on an equivalent basis. Lonestar also logged an 82% increase in adjusted EBITDAX and 27% sequentially and again significantly exceeded guidance.
Lastly, we not only continue to grow our reserves production in EBITDAX, but also make progress on another key objective and that's improving our debt metrics. And in the quarter we dropped our debt to EBITDAX ratio to 2.5x to remind you the ultimate goal is to achieve a 2.0 ratio sometime next year. Our 2018 completions are substantially outperforming our type curves and we'll review how this performance is translating into exceptional internal rates of return later in the call.
Our third quarter results benefited from the addition of eight [indiscernible], 6.8 net wells during the quarter while completions will slow in the fourth quarter essentially to two grows, two net completions with another pair of wells coming on in flow back in the last two weeks of the year.
Accounting for the temporary slowdown in new well completions combined with some production shut-ins associated with the flooding of the Frio river, Lonestar has issued production guidance of 12,600 barrels a day to 12,800 barrels a day for the fourth quarter. The midpoint of guidance represents a 76% increase year-over-year.
It's also important to note that the forecast of the oil mix increases from 58% in the third quarter to as high as 62% in the fourth quarter, as the impact of our oil leader completions is felt in our financials. We're also issuing guidance of EBITDAX of $39 million to $41 million, which represents a 10% sequential improvement at the midpoint and a 100% increase over 4Q '17 results.
We remain very confident in our previously issued 2019 outlook, which is based on capital spending of $120 million to $130 million, and sees production increasing to a range of 13,000 Boe to 14,000 Boe a day, and adjusted EBITDAX increasing from $140 million to $160 million. I would note out that embedded in those numbers is about $30 million of hedge losses for the year.
Importantly, this '19 program can be executed with a single rig and can be funded by internally generated cash flow. As we complete our negotiations around drilling equipment and a new dedicated frac spread, we'll be able to come back to you with a much higher level of precision regarding the specifics of 2019.
Our strategy of acquiring both on leasehold in our core areas accelerated in the third quarter and I think delivered significant value. In 3Q '18 we rendered into agreements to acquire another 3,000 acres through a combination of primary term leasing and acreage swaps at a total net cost of $3 million. This acreage which was strategically acquired in locations that are contiguous to Lonestar's existing leasehold in Karnes and Gonzales Counties increased the length of 42 of our drilling locations by an average of 42%.
Year-to-date we acquired a little over 4,000 acres in our core areas which we estimate at 8.2 million Boe of net reserves and $90 million of PV-10, organically replacing more than 200% of our estimated 2018 annual production.
With that said, I'd like to step back and just talk about where Lonestar is positioned at the moment and try to bring some bigger picture thoughts to bear on how we set this company up. First, let me say that I view our job as a management team as growing net asset value on a per share basis every year. I think the drilling returns that we reviewed to date in combination with the lease acquisitions that we've made year-to-date are very strong indications that indeed we have increased NAV per share this year.
Second, to the extent we can, we need to conduct our business in a way that reflects this growth in quarterly financial information and do so in a way that whenever we can deliver better than expected results. And through three quarters I think you'll agree we've accomplished this as well. I'd urge you to keep in mind that we're still pretty small and there's a lot of clumpiness to our spending and we cannot always reflect all the progress we're making towards really important financial goals.
Let's talk about capital spending. To-date we spent $129 million in total. This includes about $6 million of infrastructure associated with pipeline backbones at Horned Frog, Hawkeye and Karnes that handle oil, gas, and dispose salt water. We spend this money later in the year depend based on our success in these areas year-to-date with a focus on cutting long-term capital and operating costs in anticipation of additional drilling in these areas in 2019 and beyond.
Additionally, as we learn more about artificial lift, we made about $4 million investment in equipment that we deployed this year, largely jet pumps and we can move this equipment around the new wells so it's essentially recyclable. We've also spent a couple of million dollars on some work-overs which is just part of our age -- of wells getting older.
Lastly, we have spent about $5 million on bolt-on acquisitions to-date, which I hope I don't have to convince you yield fantastic returns for our shareholders. So if you back these costs out, we spent about $112 million with the drill bit and really only have two wells to complete and a couple of drill wells left to spend. So please bear in mind that the third quarter saw 8 new completions and costs associated with those completions, as well as much of the completion costs associated with the Horned Frog northwest wells. So it was a very capital intensive quarter on the back of running two rigs for a portion of the year. And even with this big spend, our debt-to-EBITDAX ratio was reduced to 2.5x in the third quarter.
Lastly, I'd like to state that I think we're setting 2019 up to be a year that checks every box. While stage costs were following in the second half of 2018, Lonestar really didn't see any benefit as we locked in our 2018 stage costs at the beginning of the year as part of our dedicated frac spread agreement which was important to us strategically in terms of achieving execution certainty and capital certainty.
And while we're still in negotiations, I'm confident that Lonestar's capital budget in 2019 will significantly benefit from a softer pressure pumping market as lower profit prices should result in lower well costs in 2019 compared to 2018, thereby improving our ability to grow production 20% or more while doing so within cash flow.
Lastly, in every bit as important I'd like to address how we're managing our business around liquidity. While we really prevented going into the specifics in terms of where our amended credit facility will fall out until we close next Friday, I can say this; I do believe that we've achieved our goal of extending the maturity of the facility significantly and also cutting our interest rate grid to reduce interest expense. But most importantly I can say that once closed I'm very confident that the growth in our borrowing base should deliver to Lonestar the highest level of liquidity in the company's history. And in equity capital markets, that is very choppy and very dicey, I think that internal liquidity is critical to ensuring our ability to grow and get our equity priced appropriately. All these developments set up Lonestar for a terrific 2019 and 2020.
Before I dig into our well results, which are really the core of what we're doing, I'd like to review quickly our financial highlights. Please turn to Slide 4 to commence this review. In terms of daily production, the third quarter was materially impacted by 10 gross 8.8 net wells. Of these 8 of those were brought on in during the quarter. I'd just like to add that we got flush production from our Horned Frog northwest wells, which came on in June. In terms of wellhead revenue, it rose 118% via combination of 63% increase in volumes and a 30% improvement in our commodity pricing.
Our pricing continues to be the best in the business. Our third quarter oil price was $2.90 above WTI, while our gas price realization was $0.15 above Henry Hub and added benefit was much higher NGL realizations than we've seen in a while. Lastly, our total cash expenses were below $20 a barrel and our cash margins rose 66% to $31.43 per barrel which I would guess will rank as some of the best in the industry.
Now please turn to Slide 5. We believe our drilling program is generating high IRRs while increasing production in EBITDAX will improve devaluation for our shares. But to maximize the valuation of our equity, we also believe that we need to continue to make material improvement to our leverage ratios and we're dedicated to doing that.
This slide really gives you a snapshot into that rapid progress. The top graph shows increasing production coupled with improved prices is driving rapid growth in our annualized EBITDAX. To be clear, we're calculating this figure by taking current quarter EBITDAX, multiplying it by 4 to represent our EBITDAX on a run-rate basis.
We're ramping EBITDAX very rapidly particularly with disregard to facts of hedging which are transitory. And on this basis we've increased annualized EBITDAX from $14 million in 1Q '16 to $180 million in 3Q '18. The bottom graph reflects our debt-to-EBITDAX ratio over the same time period and in the last 4 quarters we have reduced debt-to-EBITDAX from over 3.5 to 2.5 now and would expect that ratio to drop into the low 2s in 2019. We believe that if we stick to this and deliver it, it should have a positive impact on the valuation of Lonestar shares as we reduce perceived financial risk.
One point that I cannot emphasize enough is that the places that we're demonstrating excellence this year with the drill bit will be our core areas of development for year to come, which should translate into very predictable results.
Now let's review the 2018 program which began in Gonzales County. I now ask you to turn to Slide 6 to commence our review of that program. We came into the third quarter with 12,000 acres in the Cyclone/Hawkeye area. We've now grown this position over to 13,500 acres. In January, Lonestar kicked off the program with two extended reach wells of Hawkeye with an 87.5% interest. These wells have continued to deliver exceptional productivity with oil production outperforming third-party projections by 24%. That is through 9 months and the cams on these wells are quite exceptional.
As the display in the bottom-half of Slide 6 depicts, according to the third-party projections these wells were forecast to produce at rates which would have yielded an 80% IRR at $65 oil and $275 gas. Based solely on the out-performance of the wells to-date, these wells have generated 90% internal rate-of-return.
I now ask you to turn to Slide 7. Display on the top shows a dash line that depicts the 8,350 foot level at the top of the lower Eagle Ford. Historically we focused on our leasing and drilling activities at depths greater than 8,350 as is evidenced by the fact that virtually all of our acquired leasehold shown in yellow is deeper than this line.
Our recently completed Cyclone-14H well which was designed to actually test a shallower section for oil potential and was perforated between 8,000 and 8,350 feet in the vertical section. We've run production logs on the well and we've determined that the contribution from this up-dip section is extremely similar to that of the down-dip section which we've perforated and produced in a total of 8 wells in the Cyclone/Hawkeye area. We were sufficiently encouraged by these results that we've acquired an additional 2,653 acres in the area that are consistent with our historical well cost in the -- historical lease cost in the area.
The bottom graph shows you the very significant impact that these very small lease dollars is expected to generate. The lease additions will allow Lonestar to lengthen 22 of our 60 total locations in the area by almost 50%. Incrementally the average lateral length here now exceed 9,000 feet. We estimate that the additional length associated with this acreage adds 1.7 million Boe and $27 million of PV-10, not to mention enhances the returns associated with these wells.
I'd now ask you to turn to Slide 8 to focus you on our Horned Frog area in LaSalle county where we continue deliver excellent production results. We have 2 new well pads on stream from our 2018 program. The G and the H, which is the start of the south and then additionally our first 2 wells on the northwest property shown in blue on leasehold that we acquired this year.
Lonestar owns 100% working interest in the G1H and H1H wells which were placed on-stream in March. These 2 wells were our first wells in the area which utilize our current generation of our geo-engineered completion design using diverters, and as the graph on the bottom of Slide 8 depicts, our G and H wells are performing exceptionally well compared to the offset wells in the area and in fact have produced twice -- roughly twice the area average and have done so on a 22/64 inch choke since inception.
Now please turn to Slide 9. These graphs summarize the performance of both of our well sets that we've drilled to-date. The top graph on Slide 9 shows you the predrilled projections for the G and the H based on our independent petroleum engineers forecast, those are in green. Based on the projections of 1.2 million BOE and their forecast of hydrocarbon mix, these wells would generate a 55% rate of return.
In red, we've layered on to the actual performance of the G and H wells. The impact of our geo-engineered well designs are pronounced. Not only are the equivalent rates for these wells outperforming third-party projections on a constant choke and slower decline, but they've also improved the returns dramatically. If we're simply to revert the type curve to back to the type curve in month 8, these wells would generate 106% IRR. It's also worth noting that the G and the H produce nearly twice the oil of our prior wells on this lease track. So I think it's safe to assume or conclude that we've delivered excellent IRRs with these new wells.
I would now ask you to focus on the bottom-half of Slide 9 to review the continued outstanding performance of our first 2 wells at Horned Frog northwest. The number 2H and number 3H commence flow back operations in June and reach peak rate in July. Based on the study of the area, our geo-science group actually recommend that we drill a pilot hole here to fully assess the lower Eagle Ford section.
They concluded that we should target a member of the lower Eagle Ford that was actually almost 50 feet higher in section than our prolific reservoir we encountered with our G and H wells. Our on-drive petrophysical analysis determined that our new target had substantially more movable oil in it, so our goal is to improve oil recovery to increase returns. In all respects, our early results have been -- continue to be encouraging.
The graph on the bottom-half of the page depicts our internal pre-drilled type curve for these wells. These wells were fracture stimulated with over 2,000 pounds of proppant using our geo-engineered completion design with diverters. These wells which reach peak rate in July have now produced -- been producing in excess of 4 months and have produced on average a cumulative of 115,000 Boe during that timetable.
As you can see, these wells have -- from both the production curve chart and the [indiscernible] chart had outperformed the 3 stream forecast both in terms of peak rate and cumulative production rate to-date. What this display does not show is the petrophysics that we perform to pick a new target has paid off in spades. These 2 wells have produced 91% more oil per foot than our previously discussed G and H wells, and what this means through 120 days is that our cash flows on these wells have averaged $7 million a well or 35% more than forecasted by the type curve. Additionally, these wells are rapidly approaching cash payout even after just 4 months.
I'd also like to mention that I think our Horned Frog assets are still vastly underrepresented in our 2017 proved reserve base. Only 9 of our 27 locations were classified as PUD, and those were booked at 8,000 foot laterals. We're hopeful that the early performance of our G and H wells and our northwest wells will ultimately result in higher assumed oil and gas recoveries and a significant upward revision to reserves at year-end.
I'd now like to turn you to Slide 10. In May 2018, we produced our first 3 producers on stream in Karnes County on leasehold that we acquired as part of our Battlecat acquisition. EOG resources that we -- we regard as an absolutely outstanding Eagle Ford operator has set the bar for us in this area and our third-party engineers used EOG's offsetting wells to the west as the basis for their reserve forecast. So the bar here is set very high. Lonestar completed the Georg 18, 19 and 20 with average perforate intervals just under 6,000 feet using our geo-engineer completion design. To-date, we're very happy with the results.
Over four months these wells have produced just under 100,000 Boe on a 3-stream basis and to-date these wells had outperformed projections of our independent engineer by about 5%. More recently in the third quarter we completed 3 more wells, the 24, 25, and 26. Those wells are also about 6,000 feet in terms of perforated interval. To-date they've registered max IPs of 867 Boe a day and through 3 months are now inline with our third-party type curves.
In aggregate our first six wells in the area are performing very, very well and inline with a very high bar set for us by EOG up our west leased line and these wells look like they're well on their way to earning 100% IRRs and will definitely be a part of our 2019 drilling program.
Please now turn to Slide 11. If there was one shortcoming to our Karnes County leasehold, it was that the leasehold limits literally limited our lateral lengths. While I'm pleased to announce that we've improved this situation considerably through a combination of an acreage swap and a primary term lease we'll have added 275 acres which are contiguous to our lease -- existing leased lot. That acreage is shown in blue. These lease acquisitions can -- and the extent to which our laterals can be lengthened are exhibited by the dashed lines as we show them in that map.
It's amazing what a little acreage in the right place can do for you. This acquisition allows us to increase the length of 20 of our 27 remaining locations by a 34% -- by 34% and gives us a lot of locations that now exceed 7,000 feet. You're all very familiar with the impact that longer laterals have on our returns and should be able to connect the dots on how high the return should be from these extended laterals.
I'd now like to focus you on the other graph -- sorry, I'd now like the focus you to Slide 12. An important part of Lonestar's underlying value creation strategy is the baseline tack-on acreage acquisition program that we've been executing for years. The first building block of our asset growth strategy centered around using the scale and the reputations that we have in these communities we're actively drilling to surgically add mass through primary term leasehold acquisitions and trades. And as I state on almost every one of these calls, a fundamental goal is to be able to not only replace our production and drilling inventory each year through this mechanism, but actually grow it. And as these transactions have come at very low cost, we generate very high rates of return while requiring negligible amounts of capital to do so.
Slide 12 shows you the areas in which we've acquired acreage in a tack-on basis year-to-date, the areas where we've been very active year-to-date with the drill bit. And the table at the bottom of the page shows the individual and collective impacts of these tack-on acquisitions.
In sum we've acquired just about 4,000 acres at a total cost of about $4.2 million. Importantly we estimate that this acreage added over 8 million Boe approved reserves which is twice our estimated 2018 production and moreover at $65 oil flat these reserve additions add an estimated $90 million of PV-10. And because most of these lease acquisitions add lateral length, they clearly enhance the IRRs of our drilling inventory. Lastly I'd just add I don't think we're done with tack-ons in calendar 2018.
I'd like you to turn to Slide 13 to wrap up my planned remarks. Our third quarter Eagle Ford production of nearly 12,500 barrels a day exceeded guidance and set a record for the company. We made considerable progress in terms of improving our leverage ratios, having reduced our debt to EBITDAX ratio now to 2.5% -- 2.5x. Our 2018 drilling program is exceeding our expectations, generating high rates of return and programmatically probably about a 12-month payout.
I'd remind you that these results are in areas that we view as core to our long-term development plans. After a feverish third quarter, our capital discipline dictates that we slow activity for the remainder of 2018 and we really only bring 2 more wells online that will meaningfully impact the fourth quarter. This dynamic as well as some lingering effects of Frio river flooding at Burns Ranch means that we'd expect production to grow again to 12,600 barrels a day to 12,800 barrels a day, 76% growth year-over-year. I would also note that we expect a sharp rise in crude oil production in the fourth quarter to as much as 8,000 barrels a day at the high end of guidance.
We're very confident in our previously issued 2019 outlook which is based on capital spending of $120 to $130 million and fees production increasing to 13,000 barrels a day to 14,000 barrels a day and adjusted EBITDAX increasing to a range of $140 million to $160 million. Importantly this program can be executed with a single rig and is essentially funded by internally generated cash flow.
As we complete our negotiations around drilling equipment and a dedicated frac spread agreement, we'll be able to come back here with a much higher level of precision about the deliverables in 2019.
Now with that, this concludes my prepared remarks and I'll turn it over to our Chairman John Pinkerton for a set of brief concluding remarks.
Thanks Frank. First I want to congratulate the entire Lonestar team for another terrific quarter. Importantly for all Lonestar shareholders, we're starting to stack up successful quarters on a consecutive basis, I think that's really important. As you look over the -- just the last 6 quarters, we've increased our EBITDAX by approximately 3x from about $12 million per quarter to about $37 million a quarter, that's really terrific. More importantly we've decreased our debt to EBITDAX ratio during that same time period from about 5x to about 2.5x on annualized basis. So that when you take the two of those together, not only increase in EBITDAX, but also reducing your leverage, that's a gold star in my opinion.
It's really the impact of the entire Lonestar team that we're continuing to expand that should get the credit for all that. I'm really pleased with the progress of the organization.
Looking forward a little bit, 2018 is -- from a financial perspective is 3 quarters complete, but from -- really from a drilling and completion perspective it's essentially complete. And the good news is that for Lonestar shareholders that every single key performance indicate that we're going to exceed this year. So really it's going to be a terrific year for the company in every respect, both financially, operationally technically every category.
Looking a little further ahead, what I'm most excited about is 2019 and 2020. When you take the drilling results that we've had and the confidence around those results in terms of moving forward and we combine that with the longer lateral lengths, it really sets up 2019 and 2020 in a great way. In a way it really turbo charges what we're going to be able to do in '19 and '20.
So I think the -- what we've done here really sets us up terrifically for 2019 and 2020. We've got a larger, clearly more valuable drilling inventory with much longer lateral lengths. So our confidence in our ability to be able to continue to have the kind of results we had in '18 looking forward for '19 and '20 is growing dramatically over the last 9 months.
We are in particularly focused operationally in terms of driving the drill bit. We can grow this company dramatically on a per share basis with the drill bit. And we're going to stay disciplined around that. We'll continue to look at bolt-on activities, both on the leasehold side and on the production side, but we're going to be incredibly disciplined. And the reason for that is really easy and that's because our technical and operating teams are really driving superior results and high rates of return.
So it's a great time to be a Lonestar shareholder. I would encourage all of you all to -- if you have any extra dough to continue to add on the shares. I think this company is really set up, although we're small, I'd like to say dynamite comes in small packages, this company really is starting to hit on all cylinders and I couldn't be more happy with the progress we've made organizationally and just with the results and they're just start -- they're just now starting to come through the financial statements. And in particular, I'll echo what Frank said on the debt side we're really, really focused getting this company to 2x on the EBITDAX -- I mean, the debt to EBITDAX and maintaining a really strong liquidity position. And we're not going to sacrifice that for anything.
But on the same side our operating teams are making it in some respects easy in the fact that they're really generating exceptional returns, and at the end of the day the real value out of an E&P company is the ability to take its cash flow and put it back in the ground and deliver very high rates of return, and despite the fact that we're small we've got some disadvantages around metrics like interest and G&A per barrel, we're offsetting that by some of the highest margins in the business.
And really what I think are some of the highest rate of return wells when you take in both margins and the revenue side in terms of the oil premiums they're getting and the NGL premiums that we're getting, it really bodes well for the company and we're set up like I said nicely for '19 and even into '20. So I couldn't be more pleased a little made with the progress we've made, Frank and the team and Barry and the others have really done a terrific job of setting up the company and we continue to add high-quality people to the organization and I think the just -- the contention of these laterals, I can't emphasize enough the impact that has in terms of the returns.
In terms of the returns on these wells, it takes wells in the 35% to 40% range and takes them into the -- essentially doubles the returns into 70% to 80% range and in some of the others -- in some of the higher quality areas up over 100%. If we can continue to do that, I can promise you that the reserve share that adjusted the production share that adjusted EBITDAX that adjusted is going to increase dramatically, which will flow into the valuation of our stock price. So I couldn't be happier, things doing great. Really, really terrific results. Continue to buy the stock, it's really cheap. I like it a lot.
Thanks, John. I guess, we'll turn it over to questions now.
[Operator Instructions]. We will now take the first question from Neal Dingmann, SunTrust.
Hey Frank, you guys have been really successful, I think the last release said you added about 4,000 acres I think year-to-date at a cheap cost. And my question is really with the strategy would you continue to do that, and is that -- one is that going to be available in sort of your bolt-on areas? And two, by doing that will you continually be able to increase your lateral length by doing this?
Yes, so it's a great question. I would tell you that I am more encouraged by the opportunities out there now than I have been since prices crashed, and there's two dynamics in the field. One, a lot of the leases -- this is a sophisticated group of lease owners. This isn't the middle of Ohio, this is people who've leased their mineral several times and they're lawyered up and fortunately for us what that means is that the leases that were entered into as this play exploded are onerous and they allow for shrinkage of the producing unit down to fairly minimal acreage over time if drilling is not continued on that original unit. What that means is that -- and the way it comes shook out is when prices are $30 or $40 a barrel, the mineral owner is a long-term thinker, he doesn't really want to go force his rights under the lease because he's not going to get a good PV on incremental drilling, and so we saw a lot of laxity in the mineral owner community. But as prices have risen, we've seen these guys through their lawyers get much more aggressive about asking for releases on acreage that should fall out contractually, and it just so happens there's a good bit of that happening in the guts of areas that are important to us.
And as we have built our reputations in these areas, we're becoming the operator of choice and so it's a combination of kind of more aggressiveness on the mineral owners, and Lonestar during the same time period becoming much more prominent. We're a name in the coffee shops and we get things done and lease bonuses are very little bit of the equation, royalty checks are a big piece of the equation. So I would tell you that I feel better about our ability to accelerate this activity than I have in a long time.
And then just -- I don't want to get too granular on this, but just talking about the sort of the timing, I think you had 10 wells that were relatively late in the 3Q, could you just talk about timing a little bit and I guess what I'm getting at is Frank, how you're thinking you'll sort of exit the year what kind of trajectory you'll start '19 with?
Look, I think that we've given guidance for the fourth quarter. If you ask -- if you think about it, we've got a bunch of wells that are coming off a flush in the third, and only two wells, the Asherton wells that provide fresh volumes there. So after running two rigs in the middle part of the year, there's a balancing that's occurring there. And it's, look, we had the inventory that just put the hammer down and spend, spend, spend, we could have kept the second rig going, but we have this overriding objective of reducing debt to EBITDAX. So took our foot off the gas, we'll bring those two wells on, with those wells are on and we've announced the results, they're very, very good. And then very late in the quarter we'll bring another pair of wells on Hawkeye. They will only kind of touch the December month within the quarter. So they're not expected to be huge contributors.
Neal, I would tell you this that we're in the final throes of establishing what are rig schedules going to look like, where negotiations on pressure pumping and once we get those things nailed down, we will come back to you with a very clear view on how the year ought to unfold, but I would tell you we're excited about the equipment that's being shown to us, we're excited about the cost at which it's being proposed to deliver to us, but bear in mind I think the big goals, look, being able to set the table for a company with lots of liquidity and improving debt metric, and one that can grow 20% compounded through internally generated funds, those are our big goals. Those are things that we think are important to our stocks valuation and you just got -- I plead with everybody, bear in mind that this is going to still be a little bit of a rollercoaster, it's going to be really, really fun, but everything in a smooth line on it. So from start to finish, a fun ride at 20% growth. It will wobble around a little bit in between, so that's probably all the guidance I can really give you without breaking my rule of not giving firmer guidance till I have all the i's dotted and t's crossed.
And the next question is from Ron Mills with Johnson Rice.
Question, with more than 90% of your acreage HBP, how big picture do you think about capital allocation amongst the 3 areas given the strong not just performance but returns generated in those areas? And how do the recent bolt-on acquisitions maybe impact those stocks?
Yes. Well, clearly you see where we're investing money in our tack-ons. And where we're investing money in the terms of the drilling program. It's a very simple equation for us. The returns in the central and the west are outstanding. And in fact I think just the way we're drilling completing our wells or migrating those returns to levels that that we had frankly not foreseen. So those areas -- returns will -- those areas will continue to see the bulk of our capital dollars. We are -- we do anticipate drilling a well in the east in the first quarter. We've kind of come to some agreements with our partner about how to do that. Those are nice returns, but they don't compete. And we've talked about it every quarter. We've finally gotten the moon, the stars kind of lined up. I think we'll drill that well, demonstrate the kind of results that we got in the Wildcat well. And then you'd try to sell that asset and redeploy it back in the guts. So we'll continue to -- look, we've focused on the returns at Cyclone/Hawkeye, Karnes and Horned Frog for very specific reasons. We've got lots of inventory there. We can expand our positions there and we can deliver very high returns. And so that will be where we spend the bulk of the budget. So I think you should rest assured that the kind of deliverability that we've demonstrated this year is the kind of deliverability we'll demonstrate in future years from investment in the same assets.
Yes, Ron, this is John. I think the other thing that's important for everybody now is that we've really in some respects this year was -- what I'd call the first year the company had a true linear drilling program that we set at the beginning of the year, and just ran it and let the team kind of just do their thing. And it really has kind of convinced us that -- 1 is that we believe our operating tenure contains as good as we thought they were. The second thing though is by adding the lateral lengths and having this history behind us, next year's program and in '19 and '20s programs will be high rate of return, but from our perspective, lower risk. So I think that's really important in that the maturation of the company is that we're going to -- our ability to generate these returns and our confidence in that and therefore our confidence in terms of service equipment and whatnot in the contracts and the length of those contracts.
It's all kind of all -- it's all circular to some degree. The longer you commit on the service contracts, the better pricing you get. And so that's what really Frank is talking about is trying to really hit that hard. And the good news is we've got lots of people coming and seeing us, and they're doing a terrific job of working on this. And I think later in the year once the board, they get their act together in terms of exactly what they're going to do and present to the board, we'll obviously get that out in the market as soon as it's approved, but it's really a question of higher returns, but at lower risks, just because we've been there, we've drilled the wells, we have more confidence. I think that's really important for shareholders. And people like you, they're analyzing the stocks that -- the company has just grown up a bit and I think that's going to be really good news over the next 24 months in terms of being able to deliver on what we say we're going to do.
And Frank, when you talk about negotiating the pressure pumping contracts, it sounds like there could be some significant improvement there. How do you think about reallocating those savings? This year you had two rigs for a portion of the year. Next year, you're still thinking about a similar CapEx budget as you -- on the D&C side as you had this year. So in terms of cost -- those cost savings, do you redirect those savings into the ground or how do you think about that and the impact on the profile?
Well, so I think that with the -- why don't you just kind of step back a little bit? Look, I think that globally the leading operators in the Eagle Ford Shale are becoming inventory-deprived. And so I think one of the ways that we can really position this company to optimize its long-term terminal value is making sure that we continue to expand the quality and quantity of our drilling inventory. So if we're inventory-rich, those assets should trade at a premium long term. And that's an objective that we keep in mind every day because we are NAV focused. You can't always depend on the stock market to value your assets correctly. You've historically been able to depend on the industry to do so.
So we're going to -- we're going to cater toward that long-term goal. That being said, I really think that we've got a couple of things that are critical. One is this notion that we need to be very vigilant about the debt ratio. And so we'll probably just like we did this year really, start off the year on a pretty measured pace, watch how things go, start to deliver in those respects. And as long as we are delivering the well cost that we think we should be delivering with the new contracts that we will enter into, clearly the obvious thing to do is let out the rope a little bit. And if you can get more wells drilled for the same dollars, that's a huge win for shareholders. So yes, we'll be cost-vigilant early as long as we contain those costs. I think you could see the -- you just let the rig run longer and let out the rope and get more productive wells on stream later in the year that sets you up for a better 2020.
And then lastly, just the bolt-on is a big part of your strategy. Any high-level comments on the acquisition market in terms of buyer's market, seller's market in how it applies to your long-term needs?
Yes. Well, we've been really strategic about how we wanted this year to be choreographed. I mean first and foremost, the acquisition market will -- was completely locked off to us when we had a $3 equity value. You could -- there's no way you could dream of financing anything when the stock didn't reflect the underlying value of the assets in any way, shape or form. We felt like it was really important to demonstrate the efficacy of the geo-engineered completions to put some runs up on the board as it relates to the quarter and begin to give the company a bigger disposable cash flow base from which to operate. We then felt like it was important to augment that program with the tack-on leasehold acreage. It's not a Lazy Eight in terms of returns, but it's really high. And we've wanted to demonstrate that we could do that. We've also been through our existence extremely disciplined about what we're willing to pay for assets.
And I would tell you that in the first half of the year, maybe the first 7 months of the year, that our returns disciplines were causing us to "lose asset bidding circumstances." There's a lot of private equity money that was put to work. And they were just more aggressive than we were. Clearly, we've got a great little team here. We've got the ability to ramp our a little drilling completion engine to a much higher level with existing personnel. And I think that makes good business sense when we're investing and using that machine to generate the returns we are. But you've got to be disciplined about it. And so our view was then that a lot of the big money would have been deployed in the first half of the year. And the second half of the year would turn and that there were going to be an increasing number of let's call it non-discretionary sellers that came to the market where they're selling out a basin as part of a basin exit, whether they're enduring continued financial duress. Those are better sellers for Lonestar and we've just maintained a lot of returns discipline. We're not going to bid up for things that don't earn us our hurdle rates. I would tell you that I think that mark -- and I would tell you I think the year's playing out exactly like we thought it would. So we haven't sunk -- we haven't gotten any of the big fish in the boat yet, but we've got lots of hooks in the water and it looks like the market is heading our way.
Yes, and it's John again, Ron. The one thing I would say is I think there's 2 ways we can really screw this up. One is we lose discipline on the leverage side and do something that gets us over-levered again. And Frank and I've got a commitment to each other that isn't going to happen. So there's that. The other thing is we've seen it in time and time again with companies large, small, and indifferent, they do a big acquisition that doesn't work out. And oftentimes those are out of the basin, thanks, and we've had a lot of those opportunities. And again I think it's a testimony to us we just haven't -- we know we're small, but on the other side of it, we know that we can grow, we've got great confidence in our drill team and our operations and our drill inventory. So we're going to -- if we can grow this thing 20% per annum for the next 5 years or so with our drill inventory, we're going to be disciplined around that. And we're just not going to make a lot of mistakes that I can bring and really share those with Frank and the team. So it's -- we'll see, I mean, we're going to continue. Like Frank said, we'll put lines in the water, but we're going to be disciplined and we find things we can buy their -- the in-basin things that fit our size category and things that we can get financed reasonably. We'll go after those, the ones that aren't, that they're going to put us at high risk, we're just not going to do it. And the reason we don't have to do it because we've got a great drill inventory, and we're drilling the high rates of return well, so it's pretty clear to us.
And our last question comes from Rehan Rashid with B.Riley.
I've got maybe two kind of tack-on questions, no pun intended there. What is -- when we are looking into the '19 capital budget, what kind of feedback are you getting on your sand cost, is local sand and/or just generically speaking kind of once again the outlook for sand and what it means for your aggregate completion cost? And then I've got one more please.
Sure. Well, I mean I think there's been -- I don't do nearly as much of it as you guys do, but I read some of the third quarter reports and analysts' commentary on what's going on with sand and undoubtedly prices are coming down. And a lot of that is driven by -- it's really driven by largely in-basin mines opening up in the Permian and in the Eagle Ford. And juxtaposed against a waning demand for completion services in the fourth quarter and I think into the first quarter of next year. So more supply and less demand means falling prices, and we really didn't benefit year-to-date from that in that we locked everything down for 2018. So whether it's in-basin or out of basin, it's definitely backing up a lot of supply. And I can tell you that I think the bids that we're receiving absolutely reflect lower profit pricing. So that for them is in large, the pressure pumping companies is it's kind of a cost-plus pass-through. I mean they'll definitely make some money handling it for you, and bulk buying it, but if prices go down you -- then you're in a period of renegotiation, you always derive the benefit of those lower input costs. So that's -- that is one of the many drivers that is giving us optimism about our 2019 completion cost.
And I just wanted to confirm that you have a lot of sand cost locked in for '18, so you didn't benefit from that, so that's a good reminder. On the --
Go ahead, sorry.
No, we're, $0.082 cents a pound all year long.
Oh, well, okay. On the directional guide for '19 that you have now, can I -- just a quick reminder, is that based on a 1-rig growth count -- growth one rig count or is that something north of that?
No, that's -- we can execute that plan with one rig, just go and put, put, put, all year long.
Got it. And if I were to kind of say, hey, what will it take for you to take it up to 2 rigs? Just a framework around it rather than timing or kind of next year or '20, I know you can't -- just maybe what framework, if you can lay it out for us, what will it take for the platform to increase that to 2-rig run-rate?
Sure. So first let me just for everybody's benefit say that, you all keep poking around at shape of '19 and things like that. Until I can outline whether I'm going to be at Horned Frog first and Georg second and Hawkeye third, it's very difficult for me to give you a responsible view as to how all that shakes out, and there's a myriad considerations that go in the sequencing of our wells. And I won't bore you with them, but we're working really hard on that as a team. So I do want to reemphasize that. Look, our pro -- we think our equity is grossly undervalued. What do we do to solve that? We continue to deliver quarters on a basis that meets or exceeds the world's expectations. We programmatically grow 20% a year compounded and do so within cash flow. And if you can pull that off and continue to reduce your leverage metric, which I think reduces the equity markets' view of financial risk, then we have done most of what we can do to influence that equity value.
Look, we add assets and grow NAV on a per share basis from that perspective, but those are the things that we can manage to improve that. I think for a company Lonestar-sized, that -- those dynamics are paramount. And we do not want to ever get back to a place where we're starting to reverse the progress we've made on the leverage metric. And I think the demonstration of cash flow self-sufficiency is important -- and it's important externally. At the returns we're generating I don't think we're -- we in the border are nearly as wound up about whether we spend $15 million more than cash flow or not. The returns are exorbitant in my book. But what does come into play is the fact that every 6 months we do the things we can do to enhance the availability of that borrowing base in the aggregated liquidity the company has because it's the ability on a micro basis these tack-ons, it's the ability to strike really, really quickly that gives us our advantage. I think having enough liquidity that will allow us to strike very quickly on the producing property side is equally important, and you can't strike quickly unless you can write a check.
So that's kind of the next evolution that I hope will demonstrate to you is that we've been trying to run -- we've been trying to from point to point maintain about $100 million of liquidity, and it doesn't -- as we get close to the end of a borrowing-base cycle, it looks like it's going to squeeze up, but that's really the baseline that we've wanted to run the business on. Our hope is that really starts to expand beyond that $100 million mark and we've got a lot of dry powder to pounce on additional opportunities when they come. I think that you would see -- if we make -- so to answer your question, for us to go to two rigs, it's going to take more inventory because we don't want to burn through our inventory and we don't want to regress on our financial metric progress. So it might take to go to two rigs for a whole year probably take several of the kind of acquisitions that we think we can do. My hope is that we can line enough of these kind of deals up that in fact we leg into a 2-legged program sometime in the second half of the year.
But as it stands right now, you read the notes from this morning. You get beat up if you tap on the brakes for only growing 10% annualized in the fourth quarter. You get beat up if too many of your dollars go out the door in a quarter on CapEx. We're going to be disciplined about that stuff and we -- while we do some of it for you all -- for your all -- your benefit, the real -- what we're really trying to do is be disciplined and amass liquidity to aggregate more assets in the basin.
Just one last one, I apologize for running long. The resource base update with all these kind of acreage and stuff, when could we maybe get one -- I think the last number I remember was from the beginning of the year close to that 90 million barrels, 95 million barrels, is that number I remember correctly and can -- when can we get the next one please?
You will get the next update sometime in early March when we issue our pre-reserve report done by our third-party engineers, WD Vangott & Associates.
And gentlemen, those are all the questions we have.
Thank you very much. Well, appreciate your time and attention today, and we look forward to talking to you in March with fourth quarter results.
And ladies and gentlemen, this concludes our Lonestar Resources third quarter 2018 financial results conference call. Thank you for joining us today and you may disconnect your line.