Lonestar Resources US Inc.
Q3 2016 Earnings Call Transcript

Published: 11 Nov 2016

[Operator:]

Welcome to the Lonestar Resources’ Third Quarter 2016 Financial Results Conference Call. [Operator Instructions] Please note this conference call is being recorded today 11 November, 2016. I would now like to turn the conference over to your host, Frank D. Bracken III, Chief Executive Officer. Frank, please go ahead.

[Frank D. Bracken III:]

Thank you, Sylvana. And with me today as always from Lonestar are Doug Banister, Barry Schneider, and Chase Booth. Before I get stared, I want you direct you to cautionary note regarding forward-looking statements Safe Harbor disclaimer on Page 2 of the conference call slide. All right, please turn to the Slide 3 for my opening remarks. During the quarter, the Company was primarily focused on balance sheet improvements and therefore no new Eagle Ford Shale wells were drilled during the third quarter of 2016. Consequently, the Company experienced a 10% decrease in net oil and gas production to 5,921 Boe a day during the third quarter, compared to 6,614 Boe a day during the three months ended September 2015. The sale of the Morgan’s Bluff property during the quarter partially contributed to lower corporate volumes. In the third quarter 75% of the Company’s production was crude oil and NGLs. And the Company’s production from its focus area, the Eagle Ford Shale play of south Texas, fell by 8% in the third quarter, versus third quarter year-ago levels to 5,485 barrels a day, entirely due the fact that no new wells were brought on during the quarter. I would note, however, the nine months ended production was up 6% over 2015 levels. This being said, we do expect a very sharp rebound and to set a very positive trajectory for 2017, as we are a week away from commencing fracture stimulations on the longest crude oil wells in the company’s history at Burns Ranch, in La Salle County, which will add 3.0 gross 2.8 net wells in December 2016. I would also note that these three wells were more than doubled the net number of net lateral fee that we’ve placed on stream year-to-date and will be important wells for the company in terms of kick-starting renewed production growth heading into 2017. As I mentioned in my opening remark, Lonestar has been highly focused on balance sheet improvement. Since our last conference call, we’ve made significant strides in reducing debt in a material fashion, which in my opinion has radically improved the underlying value of our equity. The table below shows net effective debt reduction across the initiative which has been achieved through a combination of, one, reduced capital spending; two, the purchase of $68.2 million of our unsecured notes in the open market and three, the sale of our conventional assets for a total of $15.8 million. In total, these initiatives have reduced Lonestar’s debt by nearly $50 million since June 30, 2016. I plan to give you an update on operations later, but want to turn the call now over to our Chief Financial Officer, Doug Banister, to review our key financial highlights.

[Doug Banister:]

Thank you, Frank. All of the information I will review today is contained in our third quarter press release or is depicted on slides four and five of our conference call slides. Lonestar completed no new Eagle Ford Shale wells during the third quarter of 2016 and consequently reported a 10% decrease in total company production in the third quarter of 2016 and an 8% decrease in its Eagle Ford Shale production. Third quarter 2016 volumes of 5,921 Boe per day consisted of 3,175 barrels of oil per day, 1,238 barrels of NGLs per day, and 9,041 Mcf of natural gas per day. The Company’s production mix for the third quarter of 2016 was 75% liquid hydrocarbons. During the first nine months of 2016 the Company produced 6,348 Boe per day which in an increase of 6% over the comparable period in 2015. Lonestar’s lease operating expenses for the third quarter of 2016 were $4.0 million, representing a 6% decrease over 3Q15 lease operating expenses of $4.2 million. The sale of the Company’s conventional assets is expected to not only further sharpen the focus of our management and technical teams toward its Eagle Ford Shale assets, but also to improve the Company’s operating cost structure. To illustrate, in the third quarter of 2016, the Company’s total lease operating expenses were $7.36 per BOE. Giving effect to the sale of the conventional assets, lease operating expenses would have been $6.64 per BOE during the same period. Crude oil hedging continues to be an important element of Lonestar’s strategy. We believe crude oil hedging provides increased visibility to cash flow streams and associated liquidity in the current crude oil price environment, and augments the Company’s borrowing base. For 2016, the Company has WTI swaps covering 2,528 barrels of oil per day for October 2016 through December 2016, at an average strike price of $70.41 per barrel. As previously announced, the Company has three-way collars covering 1,000 barrels per day for calendar 2017, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel, but also gives the company an upside to $80.25 per barrel. In October 2016, we entered into additional WTI crude oil swaps covering a total of 1,000 barrels per day for calendar 2017 at an average strike price of $52.90 per barrel. The addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $53.43 per barrel. Also in October 2016, we entered into WTI crude oil price swaps, covering a total of 1,000 barrels per day for calendar 2018 at an average strike price of $54.18 per barrel. Lastly, we entered into Henry Hub natural gas swaps covering a total of 7,000 Mcf per day for the period of January 2017 through December 2017 at an average strike price of $3.36 per million British Thermal Unit. Lonestar anticipates continuation of its long term strategy of hedging when opportunistic market conditions prevent themselves. Now I’ll turn the call back over to Frank for additional comments.

[Frank D. Bracken III:]

Thank you, Doug. As we try to do each quarter, we tend to provide some topical commentary that's intended to provide you some insights about how we're positioning the company, as well as give you some detailed results from the business. While the third quarter did not see any new wells brought on stream, Lonestar’s activities under the Geo-Engineered Completion Alliance with Schlumberger continues to pay big dividends that I think sets an impressive standard for our future activities. I’ll now refer you to Page 6, to update you on progress we've made under the GECA on our Beall Ranch property. The significant amount of production history we had from the 19 wells we previously completed at Beall Ranch made it an ideal place to test our new techniques. The map in the upper left quadrant of Slide 6 shows the location of our three new wells the #20H, #21H, and #22H, which were drilled on 500-foot spacing shown in red and direct offsets from wells that have been producing from one to five years now. That fact in and of itself complicates stimulation and production and it's something the whole industry is dealing with as well density increases. Our Geo-Engineered Completion Alliance or GECA was germinated out of the success we had drilling our 26 through 28 wells shown in blue on the slide, which use certain elements of the technology package concluded in the GECA, which Lonestar believes were significant contributors to the 43% outperformance today as compared to the offset the #32H through #34H which were completed in July 2014 and as showed in orange on the slide. Lonstar initiated our Geo-Engineered Completion Alliance by drilling completing the Beall Ranch #20H through #22H wells this year with an average perforated interval of 6,075 feet in the first quarter. The wells were drilled with perforated interval of roughly 7,000, 6,000 and 5,000 feet respectively. From a technical perspective our goal is to build on the success we had achieved on the #26H through #28H wells in 2015, particularly by running thru-bit logs in all three laterals and try some very novel things with our frac jobs. Thru-bit logs suite is run in the entirety of the lateral and consist of a triple combo log with the addition of Spectral Gamma Ray and Dipole Sonic Logs, which in conjunction with Schlumberger’s Mangrove Simulation software is providing us with incredibly detailed rock properties analysis, which enable us to model vertical and lateral rock heterogeneity fractures and even allow us to count for multi-well stress shadows, that accompany our zipper fracs. This work was instrumental in designing our completions which utilize for the first time Schlumberger’s BroadBand Diverter product and enabled us to do some very novel within each stage by setting perforations across two different stress profiles, half of which could be fracked at low initiation pressures, then after pumping the BroadBand Diverter mid-stage we could pump the second half of the sand volume into a set of perforations at materially higher pressure. The goal here is to break more rocks and improve perforation efficiencies and hydrocarbon recoveries and equally do so with fewer stage while maintaining higher rates of proppant loading. These stages were 300 feet apart as compared to 215-foot spacing and the offsetting #26H through #20H wells. Couple of additional comments, the #20H well which was most proximate to the depletion and Eastern most well has performed better than another 500-foot offsetting producer on the property. The graph in the bottom left quadrant shows the daily production performance and time key plots from the older generation wells and out of our new wells which are depicted in red. And in total, through two iterations of technology improvement, Lonestar has achieved a 58% improvement in cumulative oil production per lateral foot through 225 days online. Lastly, I'd point out that this performance is coming at continued reduced cost. The graph in the top right shows the completed well cost associated with new wells at Beall Ranch. This shows continued reduction in cost per foot that we have been able to generate with cost per foot begin cut more than 50% in six quarters. In summary, Lonestar is very encouraged by the results of the GECA update and particularly with what BroadBand is doing to broad ability to reduce the number of stages we pump, while actually increasing total propant per foot, which helps us keep our frac cost in check while optimizing stimulation. We’re applying BroadBand across the entire portfolio this year. I will now refer you to Page 7 to update you on progress we’ve made with the second set of wells completed under the Geo-Engineered Completion Alliance. Encouraged by the six initial wells that we drilled on our Harvey Johnson lease in South Gonzales County in 2015, Lonestar initially leased 1,450 acres in our Cyclone project just west of Harvey Johnson. The Cyclone #9H and #10H wells are placed on stream on May 12, 2016. Lonestar drilled and completed these wells with an average perforated interval of 6,685 feet and Lonestar held at 42% working interest in these wells. These wells are fracture stimulated with an average proppant concentration of 1,518 pounds per foot, utilizing BroadBand diverters which allowed us to frac on 300-foot stage spacing and helped us direct propping into the Eagle Ford while limiting loss of frac efficiency into the overlying Austin Chalk, which has seen some depletion of well bores that directly overlay the #9H and #10H, making the frac jobs particularly challenging. The two bottom panels of Slide 7 show daily oil production to-date for these wells. The number 9 tested at 598 Boe a day on 18/64” choke and achieved a 30-day rate of 486 barrels a day. The number 10 tested at rates of 631 Boe a day on the same choke and achieved 30-day production rates of 521 Boe a day. Each production plot clearly depicts that after being placed on jet pump during the quarter, the wells are outperforming the Company's prior expectations which were set by the initial production trends. The #9H has produced cumulative of almost 57,000 barrels in 180 days. Meanwhile, the number #10H has produced a cumulative of almost 60,000 barrels during the same time period. Originally estimated to cost an average of $5.2 million these wells have been drilled and completed for an average cost of $4.7 million, including a pilot hole. Based on our ability to drill longer laterals on the rest of the acreage we’re assembled we’re highly confident that at current strip prices, the IRRs on these wells materially exceed our hurdle rate of 30%. Based on the initial success we had on the Cyclone project, Lonestar has executed agreements to lease an acreage which almost doubles our – which actually does double our position and directly offsets the Cyclone 9 and 10 wells. These additions increased Lonestar’s total leasehold in the Cyclone project to 2,906 acres as of August 15. This pro-forma leasehold position is shown in yellow with a modest amount of additional acreage shown in top lease status in green. This leasehold is expected to accommodate 29 additional laterals with an average lateral length exceeding 7,000 feet and should represent a very nice reserve addition for Lonestar in 2016. At year-end 2015, Lonestar had no approved reserves associated with this property. I’d really like to point out that each year we try to have one of these type of meaningful, material drilling-related reserve additions. Last year was the Horned Frog property where we booked 9.5 million barrels approved reserves equivalent at year-end 2015 on a farm-in we did with a major oil company. This year it will be Cyclone. 31 locations in total, 29 remaining to drill, we've de-risked the technical elements of it. We've got at the curve really quickly in terms of our understanding of how to artificial lift these wells. And we're very encouraged by our success here and we – really my goal each year to put one of these in the company. They engender very cheap organic reserve growth for the company. One last way to look at it, we’ll have about $3 million of total sunk lease costs in this property divide that by the 31 locations, we're really talking about less than 100,000 of location which is absolutely nominal when you consider the $4.5 million of well cost. That’s just highly effective use of our capital in our minds. And in a property market that appears inflated by private equity money and new basin entrance, these sort of organic, primary term lease additions seem to be a more prudent source of growth and we’re optimistic that we’ll be able to pull down more of these opportunities for real reserve ads in the future. I now refer you to Slide 8, to update you on progress we've made on the third set of wells under our GECA and overall progress we've made in terms of leasehold additions. The map in the top left quadrant of Slide 8 shows Lonestar’s lease acquisition by vintage. As is typical Lonestar strategy, we really rolled up our sleeves here and methodically put together a position at a low cost. The company has built a total lease position of 4,013 net acres over two years in five different transactions which included acquisitions, producing property purchases, acreage trades and primary term leasing. In 216 Lonestar put a cherry on these efforts while we executed a lease swap within another operator and consolidated Lonestar’s position. So that now can drill at 100% of its own discretion. Within the leasehold associated with the trade prior to the lease swap, Lonestar had 19 gross, 15 net laterals and following the lease swap we have 18 gross, 16.1 net laterals and we believe that these laterals are positioned on the best part of the acreage when all the technical factors are considered across the block. The panel in the top right quadrant of Slide 8 summarizes our Burns Ranch activity. Lonestar recently completed drilling operations on the Burns Ranch Eagle Ford #8H, #9H and #10H with projected perforated intervals of 9,620 fleet, 9,440 fleet, 8,460 fleet respectively. These wells were drilled to an average measure depth of 1,807 fleet and we’re drilled it from spud to TD in an average of 13.3 days. In terms of rates of penetration and drilling costs these new drilling results compare incredibly favorably with the wells that Lonestar drilled in 2015, the one, two and three on Burns Ranch, achieving a 97% improvement in average rates of penetration. With the 2016 wells shown in red, improving to 1,351 feet a today compared to Burns Ranch wells drilled in 2015 shown in blue which averaged 683 feet a day. Lonestar plans to use BroadBand diverters on the #8H, #9H and #10H which will allow us again to set up 300-foot stage spacing, reducing the number of frac stages and associated costs while achieving design proppant concentrations of up to 2,000 pounds per foot which would be the highest in the Company's history. Based on availability of frac crews capable of conducting pressure pumping operations with the BroadBand proppant diverter, Lonestar anticipates that it will commence operations here next Saturday with production commencing before year-end. In conclusion, I’d like to say that while we as the team and I personally have directed lot of energy towards balance sheet improvements, I hope this presentation affirms for you the fact that we’ve stayed incredibly focused on advancing our technical prowess in our well results this year, which sets the company up for a very exciting 2017 and beyond. This concludes our prepared remarks. I’ll turn the call back over to Sylvana for questions.

[Operator:]

Thank you. Ladies and gentlemen we will now begin the question-and-answer session [Operator Instructions] We will now take the first question from the line of Jeff Grampp with Northland Capital Markets. Please proceed.

[Jeff Grampp:]

Good morning Frank.

[Frank D. Bracken III:]

Hi, Jeff.

[Jeff Grampp:]

Wanted to talk maybe little bit about these upcoming Burns Ranch wells and definitely appreciate all the detail on all the science and technical work you guys have been doing. But when we look at the improvements you've had at Beall Ranch is that kind of a decent proxy or benchmark that we should be thinking about when we look at, and your old Burns Ranch wells versus the new generation of designs. And then could you also just remind us what type of AFE or cost you’re expecting on these wells?

[Frank D. Bracken III:]

Yes, so these are, let’s just call these 9,000-foot laterals in terms that are perforated interval, through long hauls, probably 5.5, 5.7 in terms of total costs, we’ll just kind of see how we can work down the pressure pumping cost. But I can tell you that today the wells did come on average probably four days short of AFE. So we’re in a positive spot there. There's a lot of factors that go into these well performances. One of the things that we're attempting to do more often is run de-fit pre frac. I mean what we're doing is we're injecting some assets that pressure is in the total of one of the wells and conducting some pressure analysis. And I would tell you that I think we're in better rock than we are in on the one, two and the three. I think that's a combination of doing 3-D seismic over the block, determining the best path, well path to be in the deepest rock possible to be in rock that has the lowest chance of any Austin Chalk depletion interfering with our frac jobs, et cetera. So while I'm hugely reticent particularly when we’re in registration to give you any forecasts, I can tell you that that all the technical work we've done provides us with a lot of encouragement that we're going to make, that we will make meaningful improvement over the first set wells. I'd be – do I have a bet around the office as to what they're going to do? Yes I'd be really reticent to share that with you. But we're worksided based on the science we’ve done to date, the thru-bit logs that we've seen, et cetera.

[Jeff Grampp:]

Okay, great that's a perfect color. And then, can you just kind of talk maybe a bit maybe at a high level just kind of future drilling plans and you've got these Burns Ranch wells coming on and then how should we be thinking about future drilling plans across your assets as we go into 2017?

[Frank D. Bracken III:]

Yes, so like we do every quarter with our board, we re rank every drilling location we have on strip for IRR and then we – and clearly – and I would tell you that just in general I think at current strip the bulk of our inventory generates way north of 30% and a lot of it, two-thirds of it probably north of 40% IRRs a strip. Again we owe that differentiation to the way we’ve constructed our acreage and our ability to drill a lot of long laterals. So we clearly want to drill things that exceed our hurdle rate and provide excellent equity returns for our investors. I would tell, but we also have other things to consider. We don't have a lot of HBP considerations, but that always comes into play in terms of thinking about forming units. But we also think about adding reserves and there’s places that we can strategically drill wells that are best for adding proved reserves which are the only things that are considered in our borrowing base. So I think it would be safe to assume that we're going to drill between 11 wells and 14 wells next year. I think that's what's in our S-1 that you can read. I think that it would be safe for you to assume that we’ll drill two to four wells at Cyclone, we'll drill two wells at Carter Lake which is in Brazos County that offsets all those or pack those whopper Apache wells that we drilled. We’ll probably be back at Burns Ranch for a few and we’ll probably be a Horned Frog for a few. I'd also point out that in December last year we didn't own any land at Cyclone and wouldn't have any drilling plans there, is our ability to wheel the rig around and get in there on a one year lease that got us that opportunity. But I would say that while I think that's a pretty good sense to balance and there’s are some pretty good detail provided in S-1 about how we might spend our money, it's always subject to change, as we’ll always let new opportunities take the bit away from HBP properties in favor of new reserve adding properties.

[Jeff Grampp:]

Okay. Appreciate that detail. And then last one from me you kind of touched on the borrowing base side of things in reserves, can you talk about kind of how conversations are going on the fall redetermination or any kind of expectations there?

[Frank D. Bracken III:]

I would tell you that, we are highly encouraged. I would tell you that, if things go to plan, I would tell you that, I think, that the net of the asset sale there is a reasonable probability for a modest borrowing base increase.

[Jeff Grampp:]

Great. It sounds good. I’ll let someone else pop on, thanks Frank.

[Operator:]

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

[John Aschenbeck:]

Hey good morning, Frank. I had a follow-up on Jeff’s question about the Burns Ranch wells. What kind IP should we be looking for on the wells, I'm not sure if I missed it but I was wondering if you can maybe provide the average IP of the historical wells and then what percentage of it towards the historical well should we be looking for? Thanks.

[Frank D. Bracken III:]

Do you want and IP or do you want Max-30?

[John Aschenbeck:]

Whichever one, whichever one you think is the better indication of the wells performance.

[Frank D. Bracken III:]

Well, I'm positive. It's the latter not the former. If I'm not mistaken those wells average and they were let's call them 8,000 feet perforated interval. I want to say they averaged a little over 600 barrels a day for on a 30-day basis. And that's the oil and they probably had a 400 Mcf, 500 Mcf a day gas component to them. So the softest way out of that would be gross that up 9,800 [ph] because these wells are 9,000-foot. After that – I’ve got bets in the office we're never going to be in the business given new estimates on wells, there are just too many variables. But I would just tell you that we've done everything we can from a science perspective to deliver absolutely the best wells possible, where we are looking very forward and probably late January to making public the 30-day rates. We just think these are going to be – these will be catalogue in terms of bringing everything we’ve learned in this play to bear on an asset. We're optimistic based on the lateral logs and the de-fit and all that good stuff and how much profit we're going to try to get away. But let's leave it at history and some simple algebra at this point.

[John Aschenbeck:]

All right, surely that’s helpful actually the historical information is very helpful.

[Frank D. Bracken III:]

John, I know we’ve released those rates, those 30-day rates probably in the first quarter report of 2015.

[John Aschenbeck:]

Okay, got it. I'll go back and check that. I guess, second one, last one from me really higher level in terms longer term overall strategy so to get your thoughts on it, because you kind of touched on it in your closing remarks, because there's a couple moving parts here with the company, both making significant strides on the operational front and then you've also made and are making some significant progress on the balance sheet. So just looking forward not just necessarily on 2017 but also beyond that seems like the focus can really get back on ops and to get the company back in growth mode and 1.9 not too long ago. We're talking about the potential to grow 20% over a five-year outlook. I was wondering if that's now again the goal with the progress that's been made both on ops and on the balance sheet? Thanks.

[Frank D. Bracken III:]

I would tell you the following. I would tell you that one, I know that probably, historically my time has been spent 80% on acquisitions, and operations and financial engineering of those operations. I probably spent 20% of my time this year on those. When the oil price falls they did, you've got to do everything in your power to do everything you can for your equity holders. And that's what my intention has been focused. The good news is that we’ve got a phenomenal team that Barry leads and we've while undertaken curtailed activity, we've really made that activity count in terms of, I think becoming an industry leader in the way we think about cost effective production in the Eagle Ford. So we've got an inventory decade worth of inventory that we can drill. When we think about it, we think of ourselves as somebody who with the right balance sheet can organically grow, as you said, kind of 20% compounded organically with the drill-bit at meaningful properties each year to our inventory. And then we want to position the balance sheet so that we can be acquisitive. I mean there's – unlike our Chairman, John Pinkerton at our Board meeting made an observation. He’d been through seven of these cycles and he said in every other cycle, the majors and the really big independence just bought up all the little guys. This cycle they're actually net sellers they’re in 13 basins and they decided they need to be in nine. They’ve got higher returns in other areas that they operate. So I think the amount of the asset sales that are going to transpire in the Eagle Ford in the next 24 months are going to be mind-boggling in terms their volume. And our view is that if we can get our balance sheet properly positioned that we can remain – we can grow 20%, add to reserves each year with the Horned Frog and Cyclone type deals. But if we can be patient like we were with our Clayton Williams acquisition at the end of 2013, and maybe it takes everybody getting through the [indiscernible] and getting full and we're the only guys that are skinny when they bring up the hot food. I mean it may be that we've got to be that patient, but we think the volume of properties out numbers the sellers’ capacity to buy them and we think that's a good backdrop for our company.

[John Aschenbeck:]

Got it. That's helpful. Thank you, Frank.

[Operator:]

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

[Ron Mills:]

Good morning, Frank.

[Frank D. Bracken III:]

Good morning Ron.

[Ron Mills:]

Couple of questions. Just given the third quarter you are focused on really the balance sheet. When you think prospectively in terms of rig counts and activity, how should we think about a completion schedule? Will it become more normalized and kind of have three to five wells completed a quarter or how should we think about well forecast?

[Frank D. Bracken III:]

And again, that's a good question. And I refer you to the S1 where we’ve lined out some range of the capital spending. But I would tell you that the subtext of that is that we expect to bring these wells on sometime these three wells, sometime in the month of December. We expect to pick the rig back up probably early January. And the most efficient way for us to use and we're picking up the same rig and we've had a rig in the field for two years and that teamwork and that familiarity with equipment is very, very meaningful to our ability to do what we do. Our drilling manager is second to none and he’s got a rhythm with those guys that we don't want to – that we will not alter. The best way to run that rig is to run it continuously. If you start thinking about something like 3-ish wells a quarter is probably a good way to lay things out. If the activity is going to be steady the completion should be steady too.

[Ron Mills:]

Perfect. And then a couple questions on the engineered completions, it seems like based on that I was rightfully so the move is to move to the Geo-Engineered Completions across the asset base

[Frank D. Bracken III:]

So let me give you a little example on Burns. I think that the thru-bit logging would have on a geometric basis probably had us drill – probably had us on 200-foot, 215-foot spacing. So that would have been 45 stages. With BroadBand we're going to be able to pump, we're going to the stage space at 300 feet. So that's 30 stages. So in terms of time alone and you also think about the time it takes you drill out plugs. There's a significant number of days on location that will save per well. Clearly the sand volume doesn't change but you've got far less perforating, far less plug setting and all that. So it's definitely just – and it stays on stages in – they charge you that horsepower by the day really is how they do it. So it’s allowed us to achieve considerable savings. I mean if we across our portfolio today look at using BroadBand versus using kind of optimized geometric completions would have given us, I’d tell you our total well cost savings probably averaged 7% or 8%. So much bigger implications in terms of what it does for our pressure pumping costs.

[Ron Mills:]

Perfect. And then…

[Frank D. Bracken III:]

The real strategic thought there is that the equity markets and anybody I talk to would seem to indicate that there's a consensus that at some point in our – not too distant future, we might see $60 oil again. And one of the things that we as a company have to guard against and I think as an industry is not allowing all the economic rent to transfer to the service companies. As you they're starving too. So doing things like this where we can make technology-driven efforts to reduce the total number of stages we're pumping and insulate us from dollars per stage cost increases, are things that we think will financially differentiate our company if and when prices move up.

[Ron Mills:]

Perfect. And then on the third quarter, you didn't have any completions. Is that fairly representative of what your base decline rate would be for your company?

[Frank D. Bracken III:]

Well I would say it would be far higher than it would be on a projected basis. We brought three wells on in the first quarter and two wells on in the second. That's probably totals just under four net wells. So you had a good amount and we brought on a bunch of wells in the fourth quarter of 2015, that we described on Page 3. So you got a lot of flush production, so these wells will be hyperbolic that 8% sequential would – I would imagine fall off every quarter there after, for that PDP asset.

[Ron Mills:]

Great. And then lastly, just from an A&D standpoint, you talked big picture, but is the focus more on doing kind of like you did with Cyclone and what you've done with Burns Ranch and try to continue to add pieces where you currently or how is the market backdrop changing in terms of opportunities opening up, as you [indiscernible]?

[Frank D. Bracken III:]

I would tell you that there’s two tiers in that question. With respect to lease driven farm in or drilling commitment related activities, I would tell you that market is really – it's good for us in two respects. One, we continue to see quality opportunities that frankly, one of the things you’re seeing in the market is that with the absence of activity over significant periods of time South Texas mineral owners are starting to enforce continuous drilling clauses in their leases, and they're putting more pressure on operators to drill or release the acreage. So that in and of itself, defines an increase in opportunity for us, a company who can move quickly and get a rig to work efficiently. So we think that backdrop is probably as favorable as it’s ever been, right. I mean if our costs are lower, our entry costs are going to be lower and we continue to use the IOG facility as the Trojan horse [ph] into those opportunities to keep our up front dollars low. So we're very encouraged by what we see in that market. We've got a steady flow of opportunities. We probably whet eight or ten opportunities for every one we take, but even one a year when you can add nine million barrels at Horned Frog and probably not quite that much at Cyclone, those are great kind of organic, modest growth opportunities for us. We’re in every data room. We have to be constantly on top of the market in terms of looking at everything. Then those are good learning experiences for the company too. We learn a lot about how other people do their business even if we're the loser. I would tell you that market has been discouragingly frothy so far. But it was discouragingly frothy last cycle and we just – we suited up every game and put in our minutes. And at the end of the cycle everybody got tired and we were fresh and we scored 40 points and we pulled down the Clayton William acquisition, which has been a very important asset for us. So we're going to remain highly disciplined about the way we buy things. We think people are really stretching right now or they've got a price expectation that greatly exceeds the strip which isn't our business and we can't hedge it, we don't believe it. So we're going to stay in tune in that market.

[Ron Mills:]

Great. Thank you so much and congrats on all the success.

[Frank D. Bracken III:]

Thanks.

[Operator:]

And our next question comes from the line of Brian [indiscernible] Private Investor. Please proceed.

[Unidentified Analyst:]

Hi, Frank.

[Frank D. Bracken III:]

Hi, Brian.

[Unidentified Analyst:]

I just want to do, if it's possible to explain a little bit more on the share issuance, how the process might proceed and timing just ballpark. Just to give people a sense for how that capital can come in, do you have floors on issue price, anything that you can provide for us?

[Doug Banister:]

The first thing my lawyers told me is I can say very little. We do, it's clearly a public record that we haven't asked one filed for an equity offering with named lead underwriters. We filed that document on the 26, of October. Ordinarily if you're not going to receive a full review, you would receive comments back from the SEC within 15 days, and that's net of holidays. So that probably put you next week sometime. We also have to take into account for the fact that 44 days, 45 days after the quarter, second quarter financials that are part of that S1 will become stale. So we'll need to amend our S1 for our third quarter financials, which you see before you today. And there's always time associated with responding to comments from the SEC and we would – ordinarily you would make your amendment to incorporate your third quarter and respond to their comments at the same time. So if you can’t go run all that calendar algebra, that would probably put you into the first week of December before you'd be in a position to go raise equity. And I’m just trying to speak generically to the experience I've had in doing this over my career. I wish I could tell you specifically how that process will work in terms of price, and volume and all that kind of thing. I can't I'm just not, it would be against the advise my legal counsel to do so. I would tell you though that strategically what makes sense for us is not a band-aid but the balance sheet, but a perfect, complete and an entire fix to our leverage. We want to be aggressive in the market not defensive like we've been this year. And we want – ultimately it should be any public company’s goal to have an institutionally liquid stock. We look at our valuation compared to our peers and in the analyst reports that we see, looks like we're trading at a big discount. I don't think that's because our acreage isn't as good if not better than most of our peers and I don't think it's because our technical efforts are not preeminent. I think that it's a matter of developing fully liquid security in the market. So those are the kinds of things that will go into our Board's decision about size, and pricing and that stuff. I guess that's all I can say about that. But I hope that's at least modestly helpful to you.

[Unidentified Analyst:]

Yes, I appreciate that. I’m just a little bit curious about the process as well too, our shareholders notified or is there a way to subscribe in advance or how does that all work?

[Frank D. Bracken III:]

Well I mean I guess in essence because we filed an S1. Everything is related this process is public. So that’s there. I would tell you I think the – it will become apparent in the amendment the full suite of underwriters in the transaction. We’ve got some people who’ve dedicated research to us and we feel it’s important to acknowledge that contribution through participation [ph] the offering. And so there’ll be several firms in the deal. And I guess what you could do is get your broker to reach out to them first in stock.

[Unidentified Analyst:]

Thank you very much.

[Operator:]

Our next question comes from the line of John White with ROTH Capital. Please proceed with your question.

[John White:]

Good morning guys.

[Frank D. Bracken III:]

Hi, John.

[John White:]

Thanks for taking my question. On the frac job, on the upcoming frac job, did you say you're going to 300-foot spacing versus 250-foot?

[Frank D. Bracken III:]

Correct.

[John White:]

And that's just because of the 9,000-foot longer lateral?

[Frank D. Bracken III:]

No, it’s because we're using BroadBand to stimulate rock throughout the lateral in different stress regimes and pumping that pill – mill mid stage allows us to get much better perforation efficiency across the lateral. That's really the key to using that product is doing that. And we’re going to do some different – we're going to do some control and variable experiments we’ll probably pump a well at 1,500 pounds a foot, one at 1,800 a foot and one at 2,000 pounds a foot.

[John White:]

Okay, so if you could give more…

[Frank D. Bracken III:]

We're going to get max volume away. We’re just a key to BroadBand as we're dealing it with fewer stages. Total…

[John White:]

Okay, fewer stages – fewer stages but more exposure to more rock.

[Frank D. Bracken III:]

There it is, that's the summary.

[John White:]

And can you describe further describe the frac job in terms of proppant in the mash and whether or not you're using coded?

[Frank D. Bracken III:]

We've pump 100 mashed initiate the bulk of the jobs is 30, 50 at very high concentrations. We tail-in with a Schlumberger product that has the same sorts of characteristics as Resinco [ph] right to give some stickiness to the tail of each stage.

[John White:]

Very interesting. Some people in the Permian are sandblasting their casing before they run it, they claim they get a better bond with the submit job. Is that a practice of the Eagle Ford?

[Frank D. Bracken III:]

Not that I know of.

[John White:]

Okay.

[Frank D. Bracken III:]

I don't know that. Frankly, I don't know that, I think we've got when you have a laterals that, I hate to use the word porpoise but move up and down like ours do. I think the notion of getting a phenomenal bond through the lateral is probably just really to execute but I don't think we've experienced any problems that give us any trouble in terms of stimulation or production. So that may be something specific to those formations out there.

[John White:]

Thanks for that detail. One last item, you’ve mentioned this several times on the call but just how many bets do you have in the office and can you give us an idea of your total exposure?

[Frank D. Bracken III:]

They're all – the only thing that I have at risk is my integrity.

[John White:]

Okay. Well, that's good to hear, Frank. It’s been a great year.

[Frank D. Bracken III:]

[Indiscernible] election on Friday though.

[John White:]

Well it’s been quite a year with NASDAQ listing the balance sheet repair and now some 9,000-foot laterals to the closer out, so congratulations.

[Frank D. Bracken III:]

Thanks a lot, John.

[Operator:]

Our next question comes from the line of Steve Berman with Canaccord. Please proceed.

[Steve Berman:]

Thanks. Good morning, Frank. Just a quick Brazos question, have you seen anything little more recently out of either Apache or anyone else in that part of the world?

[Frank D. Bracken III:]

No, activity is – Apache absolutely carpet bond, the acreage that offsets Carter Lake. Those wells are generally quite good. I think they did a lot of different testing on a lot of different well spacing. And as is typical of our strategy will be the beneficiary of being able to stand back and analyze that before we set up our stage spacing. I think – my guess is they’d probably regret some of their 500-foot space wells they did. But we always try to be highly cognizant of what people do well and where they feel like they need to make improvements, we try to incorporate those in free drill. I would tell you just kind of globally, there’s three big players there’s Halcon, who have their own balance sheet repair so to speak to attend to this year. There is Apache, who appears to be not focused on this area in favor of their projects in West Texas and elsewhere. And then there's Anadarko who I guess there's all kinds of chatter on the street about their Eagle Ford position. So you’ve had three big horses for very different reasons pursuing very low levels of drilling activity. And frankly – with prices having recovered the economics of drilling are a lot better than they were in March, I can tell you that.

[Steve Berman:]

And can you are reminded how many acres you have there?

[Unidentified Company Representative:]

So we've got – I tell you we've got about 3,500 undrilled that are – that have immediate production offsets to them in the Eagle Ford and then we've got another 5,000 that are a bit south of that don't have any engineered categories to them at this point in time.

[Steve Berman:]

Great. That's it for me. Thanks, Frank.

[Frank D. Bracken III:]

Thanks, Steve.

[Operator:]

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

[Frank D. Bracken III:]

All right, well everybody thank you for your attention and we're flattered by how much you pay attention to us and the questions you ask. And thank you for your participation this morning.

[Operator:]

Ladies and gentlemen, this concludes the LoneStar Resources’ third quarter 2016 financial results conference call. Thank you for joining us today. You may now disconnect your lines.