Lonestar Resources US Inc.
Q3 2017 Earnings Call Transcript

Published: 14 Nov 2017

[Operator:]

Ladies and gentlemen, thank you for standing by. Welcome to the Lonestar Resources Third Quarter 2017 Financial Results Conference Call. At this time all participants are in a listen-only mode. There will be a question-and-answer session following our presentation and instructions will be given at that time. Please note this conference call is being recorded today, the 14th day of November 2017. I would now like to turn the conference over to your host, Frank Bracken, Chief Executive Officer. Frank, please go ahead.

[Frank Bracken:]

Thank you. And thank you for joining us this morning. With me today, as always, I’ve got the Lonestar management team, and we also have our Chairman of the Board, John Pinkerton with us today. Before I get started, I want to direct you to the cautionary note regarding forward-looking statements, Safe Harbor, and disclaimer on slide two of the conference call deck. Third quarter was a really big quarter for Lonestar and it represents a major step forward for our Company. Lonestar’s 3Q 2017 results are important and the first financial results that fully reflect the positive impact of our Eagle Ford Shale acquisitions which have brought significant scale to our business, which are reflected in dramatically improved cash margins. Moreover, I applaud our operations team who have quickly and forcefully assumed control of the operations and associated lease operating expenses on the acquired assets. Our ability to reduce costs has added significant value to these acquisitions already. Additionally, our conversations with the agent of our bank credit facility indicates that our efforts will be rewarded with another upward redetermination of our borrowing base recommended $175 million, which we expect to be finalized in December. Now, please turn to slide three for my opening remarks. Let’s focus on the key accomplishments of the quarter. First, Lonestar reported a 36% sequential increase in net oil and gas production during 3Q 2017. Net oil and gas production averaged 5,635 Boe a day in Q2 compared to 7,662 in Q3. Production growth was largely attributable to the production additions associated with our $116 million acquisition of producing properties that we closed on June 15, which added 81 gross 75.2 net wells and added 1,883 Boe a day of sales to our 3Q results. Third-quarter also benefited from the addition of two gross, two net wells placed into service on our Cyclone property in Gonzales County at the beginning of July. These wells which are performing well, more than offset natural declines from our producing wells as well as 150 barrel a day curtailment from wells shut in associated with Harvey. Our acquisitions in two new Cyclone wells were even more impactful to adjusted EBITDAX. Lonestar generated 61% increase in adjusted EBITDAX in 3Q 2017 to $20.3 million, versus just $12.7 million reported in the quarter before. I think this is an incredibly important step forward for the Company and that last quarter annualized EBITDAX increased sequentially from $50.8 million to $81.2 million and our production is only going higher. Our initial report card on the acquisitions is in. In just one quarter, Lonestar has replaced contract operators on the property with a full staff of Lonestar employees. In total on a sequential basis, we cut LOE for Boe by 47% from $13.60 a Boe in 2Q to $7.23 in 3Q. Additionally, we spent $2 million on well work which is designed to bring the wells up to our operational standards and that meant that 41 of the 81 operated wells were off-line for well work during some part of the third quarter. Aside from quickly reducing operating expenses, our efforts have resulted improved well uptime and reduced maintenance and in September, production from the acquired assets was at the highest level since April. During the call, I’m going to review the results of our 2017 drilling program, and I think they continue to be impressive. Our Gen 5 five wells at Burns Ranch are outperforming the third-party type curve and at midyear, our Wildcat B1H well got a major upgrade from our third-party engineers. Meanwhile at Cyclone, we drilled four new wells that are performing really well thus far and while it’s early, are in line or better than our third-party type curve. I’ll give you all the details of our impressive 2017 performance later in the call. The only thing that hasn’t been a positive in the second half of 2017 is one that’s largely out of our control and that’s our frac schedule. Our original guidance contemplated getting the better of the half quarter’s worth of contribution from our 100% owned Cyclone 26 and 27 wells, deferrals by our pressure pumping provider were compounded by disruptions caused by Hurricane Harvey, which delayed flow back from August 15th to September 22nd, meaning that first commercial production was established after the quarter end. This delay pushed 1,418 Boe a day growth or 1,100 barrels a day net of productivity out of the third quarter, and out of the second half of the quarter, reducing the quarter’s output by half of that or 550 Boe. Additionally, our service provider altered our back-to-back flop for our Burns Ranch B1H and B2H that should [ph] have immediately followed the Cyclone 26 and 27 and deferred them until October 20th. We’ve just wrapped up our frac jobs on these two wells at Burns Ranch which means that those wells will not commence production until November 20th; it will probably be December before we see full rate on those wells. Lastly, our Hawkeye 1H and 2H on acres that we recently acquired were drilled in place of two wells planned at Horned Frog and will commence frac jobs on those in early December. And therefore, those wells will not contribute into the 2017 results. The silver lining is they will give us a strong tailwind going into 1Q 2018. We tried to capture the effect of these frac date deferrals in a visual sense on slide four. Our initial program envisioned all four Cyclone wells in orange coming on stream the third quarter, and in fact only to two of those four wells contributed. Our Burns Ranch wells in green coming on in November and now coming on in December. Meanwhile, we deferred our Horned Frog wells shown in purple to complete our analysis of the 3-D survey over the property in favor of two wells on our newly acquired Hawkeye property. You see our Lego [ph] stack -- you’ll see that by 1Q 2018, we’ll be completely caught up with our original program and we should see significantly higher production at that point in time. Now turning to slide five for some financial highlights. There are some of our standard graphs here on this -- on slide six as well for your reference. But there’s a terrific story to tell here in terms of expanding margins in Lonestar’s business. First, let’s look at the daily production table on slide five. 3Q production volumes were up 36% and consisted of 69% oil, 16% NGLs and 15% natural gas. The Company’s production mix in the third quarter was 85% liquid hydrocarbons. And while third quarter volumes in total increased 36%, crude oil production actually increased 47%, sequentially, which served to further improve the profitability of our production stream. As a result, our crude oil mix increased from 63% to 69%, which bolstered our average wellhead realizations. I would like to now turn your attention to product pricing, revenues table also on slide five. Lonestar generated meaningful improvement in its wellhead price realizations, even while WTI declined modestly. Our wellhead oil price realizations actually rose by $1.44 a barrel, despite the fact that WTI actually fell $0.07 per barrel sequentially. We achieved this realization by aggressively remarketing our crude to new buyers who would take better differentials and we actually took advantage of the export markets. Meanwhile, our NGL realizations improved due to market forces and the liquids markets, while our natural gas prices were essentially unchanged. These factors combined with the fact that our Boe production mix got oilier in the third quarter, yielded $2.78 per Boe sequential improvement in our wellhead price realizations. Now, let’s take a look at the table entitled cash expenses on slide five. Lonestar’s cash cost structure actually saw reduction on absolute dollar basis in the quarter and a significant sequential improvement on a per Boe basis, which was achieved by stringent cost control and expanded production volumes provided by the Marquis and Battlecat acquisitions. To review the details, while LOE increased from $3.5 million to $4.5 million quarter-to-quarter, we’ve reduced LOE on a per unit of production basis by 7% to $6.40 per BOE in the third quarter. Production taxes, which increased 43% to $1.5 million, was proportionate to the 48% increase in oil and gas revenues we reported. On a unit basis, LOE per BOE rose 4% from $2.10 to $219 per Boe. G&A expenses were cut by 26% from $3.4 million back to a more normal $2.3 million in the quarter. This translated to a 47% sequential decrease on a unit-of-production basis from $6.12 per BOE to $3.26 per BOE largely based on our ability to operate an expanded asset base associated with the acquisitions without expanding our overhead. Lastly, interest expense was cut 16% from $6 million to $5 million, as a result of the extinguishment of the Company’s 12% second lien debt in the quarter. That means interest expense was cut from a $11.64 to $7.14 per Boe. In aggregate, our cash expenses were reduced by 29% on a per unit basis from $26.74 a Boe to $18.99 per Boe, a real indication that we’re scaling our business. Lastly, an 8% improvement in wellhead realizations associated with our oilier mix combined with a 29% reduction in our cash expenses yielded a huge improvement in our cash margin, which more than doubled from $8.63 per Boe in the second quarter to $19.15 per Boe in the third. Now, as we do each quarter, we’re going to focus on a continued improvement in our well results. The properties that we’ve drilled to-date will see the bulk -- in 2017, will see the bulk of our drilling dollars in 2018. And in this respect, I don’t think there is any material execution risk to the program in terms of well results. Let’s now turn to slide seven, to update you on our recent acquisitions. Before I delve into the production results of our drilling program, I want to highlight some of the outstanding initial performance on our recently announced acquisitions. Lonestar assumed operatorship on the acquired properties on June 15th. Lonestar quickly transferred daily operations from third-party contractors to Lonestar employees, and immediately got to work on addressing reduction in costs and headcount in the field as well as reducing chemicals and electricity costs. We also conducted approximately $2 million of capital improvements on about half the wells to get the companies up to snuff -- the properties up to snuff. This spending has resulted in improved performance, reduced maintenance and reduced operating costs. The two charts on slide seven, clearly demonstrate our early success. September’s production represented the highest month of production since April, and we’ve really gotten after it on LOE, which has been reduced by about 50% to $7.23 in our first full quarter as operator. While I’ve historically said, Lonestar has most of the value to the drill bit, our field operations team is clearly shining on these new acquisitions by lowering costs, improving economic limit, and adding net present value to the asset. I’ll now refer you to slide eight, to update you on progress in LaSalle County on our Burns Ranch property. I’m particularly pleased with the excellent performance out of our Gen 5 wells drilled at Burns Ranch, the number 9 and number 10 wells. Lonestar implemented a number of technical improvements to these wells, which include employing azimuthal gamma ray to stay in our petro-physically defined geo target through multiple dip changes; increasing profit concentrations to 2,000 pounds, which included the use of diverters; and also more conservatively managing production to maintain lower GORs in our Gen 5 wells. 300 days into production, a type curve’s beginning to be firmly established, and we continue to be encouraged with the results of our Gen 5 wells. Our dedication to excellence does not end at completion. We have been highly focused on disciplined flow back and production practices which may not make the flashy IP rates, but do make the great EURs and returns. We told you before that we thought the rapid increase in GOR we experienced in our Gen 3 wells impaired our oil EURs by prematurely reducing flowing pressures below bubble point. And as a result, we’ve been much more stringent in our choke management techniques on our Gen 4 and Gen 5 wells as part of our oil maximization strategy. At 100,000 barrels of recovery, our Gen 3 wells exhibited GORs of 2,700 while our newer Gen 5 wells which have been much more stringently choke managed have recovered the same 100,000 barrels of oil while registering a GOR of 1,600. To-date, we have been reticent to discuss reserves forecasts, but with 300 days under our belt and fairly predictable rates, we feel more prepared to discuss reserves and it’s good news. Our Gen 3 wells, which have been on stream for 900 days have recovered an average of 131,000 barrels and are currently projected to recover an average of 320,000 barrels or an average of 40 barrels per perforated foot. In a little over 300 days our Gen 4 well has recovered 100,000 barrels and is tracking to an EUR of 495,000 barrels of oil or 55 barrels a foot, which is in line with our third-party type curve. Meanwhile, our Gen 5 wells have also recovered 100,000 barrels of oil in a little over 300 days and are currently tracking to recover 540,000 barrels or 60 barrels a foot, which exceeds our third-party type curve. But I just want to punctuate, if you think about this, we recovered in 300 days about 80% of what we recovered in 900 days on our Gen 3 wells. So, that’s real progress. After Harvey-related delays, Lonestar’s finally completed fracing its most recent wells at Burns Ranch, the B1H and B2H. We drilled the total depth of about 18,000 feet and perforated intervals on those wells are about 9,450 feet. We had 92% working and 69% net revenue interest in these wells. As I said, fracture stimulations have been completed; we will drill out plugs over the weekend; and flowback is expected to commence on November 22nd with commercial sales expected a few days after that. Upon first production of these two wells, Lonestar will have completed five wells on these leaseholds in 2017 and consequently will have held 100% of our acreage at Burns Ranch by production. I now refer you to slide nine, to update you on our progress at Cyclone. On July 1, Lonestar established commercial production on the 4H and 5H wells. We have 100% interest in those wells. These wells were fracture-stimulated in engineered completions with average proppant concentrations of 1,820 pounds per foot over 30 stages on a well in engineered completions, utilizing diverters. The 4H and 5H contributed during the entirety of the third quarter and these wells produced an average Max-30 rate of 653 Boe a day and have cumed over 50,000 barrels each in their first four months of production, which is pretty strong performance, if you look at the chart on the bottom of slide nine. After significant delays, fracture stimulations operations on the 26 and 27 wells were completed and those wells were placed into flowback on September 22nd, and established commercial production roughly on October 1st. We again have 100% working interest and a 79% NRI in these wells. These wells were actually completed again in engineered completions with average proppant concentrations of 1,525 pounds a day over 28 stages per well and again utilized diverters. The wells have yielded Max-30 rates of 709 Boe a day, which are far in way the best wells we have seen at Cyclone to-date. So, we are very encouraged by the early productivity of all four of these wells which are tracking or exceeding the third-party type curve thus far. I’ll now turn you to slide 10, to update you on our continued efforts to build scale in the Cyclone area. I refer you to map of Cyclone at the top of slide 10. Lonestar continues to encounter success in additional -- leasing additional tracks or acquiring additional tracks in this area that are contiguous to our Cyclone and leasehold. At December 31st, we held 2,656 net acres, which accommodated 24 net laterals, through a couple of little piecemeal bolt-on deals at June 30th, we increased our leasehold to 3,512 acres, which accommodated 36 net laterals, many of which have been elongated with our leasehold acquisition. Now that production has been established on the 26 and 27 wells, approximately 86% of the leasehold and cyclone is held by production and two of the wells we have planned for cyclone in 2018 will HP our leasehold here in its entirety. I would also like to note that as our operations have expanded here, we spent a little over $2 million to install a gas gathering network and a water disposal backbone across the property. This will reduce future well costs, increase revenues by selling gas and NGLs for the first time as well as reduce operating cost, and the project itself will pay out in less than one year. I now refer you to the Hawkeye acquisition map at the bottom of slide 10. During the third quarter, Lonestar made another significant acquisition in a portion of Gonzales County where we married great drilling results with a low cost scrappy effort to build an asset base. Lonestar acquired a set of assets on the courthouse steps of Gonzales County that we now will refer to Hawkeye. That name just made sense to us and it was right next to the other [indiscernible] that we named Cyclone after. We paid a total of $3.4 million to acquire 6,257 gross and 1,655 net wells, which is extremely close to our Cyclone position and shown in magenta on the map. The acquisition included $2.5 million of PD-10 and the PDP category. Most of which was associated with wells that Lonestar already operates in Cyclone. That means, we spent $900,000 for 1,655 net acres, which equates to $543 an acre. And we haven’t wasted any time here. Lonestar’s currently drilling two 10,000-foot laterals at Hawkeye with an 85% working interest, and those wells should be placed on stream in the first quarter of 2018. I now refer you to slide 11, to update you on our record-setting Wildcat well in Brazos County. Lonestar owns 50% working and 38% net revenue in the Wildcat B1H, which was placed on stream in May. Well’s now been on stream for six months and was completed in an area where a very capable operator drill close to 20 wells with high proppant concentrations, and were very well stimulated by current industry standards. With the benefit of evaluating those offset wells, Lonestar set an objective of improving upon those results by keeping our lateral and a petrophysically derived geo target, pumping about 2,100 pounds of proppant in non-geometric engineered completions which were done with the benefit of advanced logs to total depth. We previously reported that Wildcat B1H established a 30-day Max rate of 2,123 Boe a day, and I’m pleased to report that the well is still performing very well. And the well has now produced over a quarter of million Boe in six months. These rates were all achieved on a 24/64” choke. We wanted to remain very conservative in our choke management procedures with the goal of maximizing crude oil recoveries through hitting due point. We are now past due point and we’re taking action to open up the chokes on this well little bit to get a little more productivity out of it in the near-term. Let’s now turn to slide 12. Wildcat B1H was actually classified as probable in our third-party reserve report at year-end 2016. In that report, gross reserves were estimated at 840,000 Boe. At the request of the Company, our third-party engineer updated its reserve forecast for the well to account for actual production results. The reserves actually -- reserve estimate increased 29% into a forecasted EUR of 1.1 million Boe. Results here are extremely encouraging. We have a big leasehold here. And notably, we booked no proved reserves to this area yet. Our partner has a lot of acreage in this zip code in the deep Brazos portion of the Eagle Ford, and we’re collaborating on how to develop it. Hopefully, we’ve also given you some handle on the scale we’ve established in our business as well as the improved margins associated with our production and our EBITDAX run rate which increased 61% to over $81 million annually. We’ve achieved these results by effectively assimilating our recent acquisitions and delivering aggregated outperformance to our type curves with our 2017 drilling program. I’d like to now address what these improvements mean to our 2018 guidance. Let’s turn to slide 13. We’ve upgraded fourth quarter guidance to account for the significant delays in frac dates we’ve experienced, but also improved oil price differentials and cost structure, which should result in some modest sequential growth in production and EBITDAX. If there is a silver lining in the frac delays, they should provide some extra punch to our 2018 drilling results. We’re currently guiding to a 2018 program that sees 16 to 17 net wells -- sorry, 14 to 15 net wells drilled but will place 16 to 17 wells on line. The drilling program is forecast to result an average production rate of 10,000 to 10,700 Boe a day which should have a liquids mix of roughly 80% for the year. At the low-end of guidance, this represents 50% growth year-over-year. We are experiencing excellent crude oil price differentials currently with a couple of dollar premium over WTI and in 2018 right now, we are projecting the crude oil differentials are flat to a premium of $0.50 over WTI, as well as improved NGL and natural gas realizations which are based on the location of our forecasted production and the midstream contracts associated with that production. On the expense side, we expect to continue to scale down and drive lower our LOE and G&A costs on the unit basis. And this well schedule we guide to is projected to cost between $95 million and $100 million with projected EBITDAX of $100 million to $110 million. That means our capital budget should range from cash flow neutral to cash flow negative by $10 million. I’m sure, you will have some questions about where these wells will be drilled. We are happy to wave our arms with you on the call. But we have a budget, we have a Board meeting in December and we will actually set a fixed well scheduled at that time. So, in short, before I turn the call over to questions, we have made a lot of progress here. We have grown our business, our productivity and our EBITDAX run rate considerably with no appreciable expansion in overhead. I think all of our wells are performing extraordinarily well and could be subject to upward revision. And the wells in the areas that we’ve drilled in 2017 are largely where we are going to drill in 2018. So, I think that the production response should be very, very predictable. Lastly, I’d like to mention that 4 of the 10 wells that we will get -- put to TD in 2017, we are on properties we did not own at the beginning of 2017. So, there’s a lot of fluidity to what we did this year, and it’s something that creates a little bit of havoc with our frac schedule. It’s been a real corporate objective of ours to be in a position to lay out a firm, fixed drilling plan for 2018. That’s going to do wonders when it comes to getting firm frac dates in 2018, and we also are confident that that’s also going to improve our efficiencies and our absolute realized costs on frac stages as well. So, 2018 is going to be a big year for us. We have accomplished a lot this year and looking for to delivering some really superior growth, while I might add, continuing to improve our debt to EBITDAX. We are now conforming credit with our revolving credit facility with LQA debt to EBITDAX of 3.4 times. We think we will drive that number down somewhere between 2.7 and 2.9 times by the end of next year, which I think has great implications for the valuation of the equity. With that, I have concluded our prepared remarks, and I’ll turn the call back over to the moderator for questions.

[Operator:]

[Operator Instructions] We will now take our first question from Jeff Grampp with Northland Capital Markets. Please proceed with your question.

[Jeff Grampp:]

Good morning, Frank. I just wanted to go back to your comments here on looking to be seemingly capital neutral, maybe slight deficit for full year 2018. I imagine as you guys continue to ramp production, you’re neutral or maybe better exiting the year and with leverage continuing to head in the right direction. How are you guys thinking about free cash flow generation potentially as you guys exit 2018 and into 2019 and longer-term? Is neutrality or better something you guys are looking at or as your leverage continues to move down, are you guys maybe more comfortable with some amount of outspend to accelerate the growth to your prospects?

[Frank Bracken:]

Look, I think, fundamentally, we are absolutely committed to improving the equity valuation of the stock. And we think that is best done through something that closely resembles cash flow neutrality. That’s particularly important for us and that we can -- the well performance and the rates of cash flow that those wells throw off, are such that we’re going to be able to actually grow EBITDAX at a fairly rapid rate, thereby decreasing our debt -- our leverage ratios down into a range that I think is much more normal for a company of our size. We, internally, and while it would be early, we think we can be cash flow neutral in 2019 and 2020, and still grow production double digits. And I think that in a vacuum and this price environment, those are good intermediate and long-term goals for a company like ours.

[Jeff Grampp:]

Okay, great. Appreciate those comments. And on 2018, you kind of mentioned, during 2017 getting some delays and kind of I guess issues out of your control, frac dates. Are you guys potentially looking at a dedicated frac through, [ph] your activity levels kind of warrant that or I guess just generally kind of how are you guys thinking about securing frac dates next year?

[Frank Bracken:]

Sure. So, I think the preponderance of the noise -- we had a fairly set, set of frac slot set for 2018. And most of the noise was really associated with Harvey and all the scrambling that our service provider had to do to make everybody happy. And clearly, when our level of activity, we on occasion will get bumped around a bit. We also, as I mentioned, four of the wells that we drilled, were I’d call them opportunistic. We picked up new acreage and got on them, HPP them rapidly. And so that plays a little bit with the schedule as well. We have a schedule internally that we think is very fixed. It’s all along again, and we’re in discussions with our pressure pumping -- with several pressure pump providers now to try to get fixed windows. Whether it’s us exclusively or whether we share some portion of a frac spread, the clear objective is to get dedication that takes a lot of the guess work out of what we do. And I think we’re in much, much better position having the ramped the EBITDAX, like we have, to be able to do that next year.

[Jeff Grampp:]

Okay. And then, last one for me, just on the Cyclone area with the recent results here, I guess just kind of comparing and contrasting the 4 and 5 versus 26 and 27, it looks like you guys are actually able to get better IP rates and seemingly better performance on the new wells with shorter laterals and less proppants. So, just kind of want -- I know it’s still early days here, but anything you can kind of point to that may explain how you guys were able to generate those kind of results?

[Frank Bracken:]

Right. There is a -- our simulation guy is just really tremendous. And every single one of these wells has its own set of nuances. And in Cyclone area, path of what we’re doing so effectively is keeping the fracs from growing into the Austin Chalk. So, we’re keeping all of the frac energy and all the proppant, and I say all, the preponderance of all the proppants in zone. So, our team does a really good job of monitoring each stage, figuring out what we can get away with in terms of proppant to get those results. So, you’re right, highest rates with the shorter lateral. So, big step change, positive. We’re looking -- we don’t just look at this on a rate basis, we’re looking it on a returns basis. And he’s very cognizant of that. So, we’re just -- every time, we drill a set of these, we’re going to do our best to do detailed work on what is the best answer for this specific area. Now, I’ll give you another example, the Burns Ranch 1 and 2, B1 and 2 which actually have less chalk depletion above them than anything we’ve drilled, we’re putting 1,820 pounds away there. And we’re putting -- that’s just not a point of all the 1,820-pound job, there is near and far field diverters that we are using. They are really intended to keep that frac in zone. So, any place we can do more with less in the current environment, we are going to try to do that to maximize returns.

[Jeff Grampp:]

All right. I understood. I appreciate the comments, Frank and look from to 2018.

[Operator:]

Our next question comes from the line of Mike Kelly with Seaport Global Securities. Please proceed with your question.

[Mike Kelly:]

I was hoping to dive into the Brazos County acreage a little bit and just wanted your thoughts on the initial development strategy. How you think this ultimately unfolds, you guess? [Ph]

[Frank Bracken:]

Yes. And I’ll be a little circumspect in that that we’re still working with our partner. But, a lot of our best acreage is HPPed now, a lot of theirs isn’t. We are partners and we are working on ways to codevelop that in a manner that it suits their needs to avoid expirations but suits our needs from a capital perspective. So, I think you’ll definitely see us drill some wells there next year. We are highly focused on cash flow neutrality. So, the best situation for us is being involved but being involved on a probably a lower interest basis in acreage that we don’t own. And so, we think there’s parts of what we did at Wildcat that we can improve upon. We will be seeking to do that. But we are out scouting pads right now. Those capital expenditures are worked into our guidance, kind of on probably a two-well basis. But we are really -- the goal is to prove up that area, then I think it will be -- we will have another set of portfolio management decisions to make in terms of whether this is something we want to divert additional capital towards, whether we want to monetize this asset, but we will cross that bridge, when it comes but these are clearly -- 1.1 million Boe wells, don’t happen every day. And so, we want to be able to extend the footprint of those positive well results before we consider our options in terms of how we develop this or seek value for it.

[Mike Kelly:]

Can you just remind me, what’s the nature of that JOA with the partner there? I mean, slide 12 shows you guys got a pretty blocked up leasehold. But, just give me little more color what really is entailed by that relationship right now?

[Frank Bracken:]

It’s -- in my mind, it’s better than any JOA. There’s just a strong bond of mutual interests. The private equity backer of our partner is one of our biggest shareholders. So, anything he does to help the PE backed company, he is simultaneously helping us. So, there’s a lot of economic ties between the two entities. We have a great working relationship with them and continue to do good things for each other out here. We clearly are the technical leader. And sometimes when you got one group who is really technically strong and other who has got lots of money, those things work out well. And I think that’s how this relationship will continue to progress.

[Mike Kelly:]

And then, just a general one for me on 2018. What do you view is the biggest risk to the program in 2018?

[Frank Bracken:]

So, I mean, I hate to be flip, but the -- we are going to drill wells where we’ve drilled wells already. We are going to drill some Horned Frog wells. We’ve not gotten past Gen 3 there and we are going to do a lot to improve those wells. We’ve got 3-D seismic that we think will help us land an even better target out there. Infrastructure is all built, so the wells should be cheap. And, we are going to drill some -- we permitted these laterals to 13,000 feet. We’ll let the rocks tell us when we quit, but they are going to be good wells. And we hope to rewrite the reserve forecast out there. But, you know what the baseline is. We’ve established it. A lot of the rest of the program is going to in Karnes and Gonzales. I think we’ve set the bar at a very predictable level there. So, the program I think is set. You know what the widgets look like. I can tell you that that I think there is -- you think about what we’ve done this year, done a huge acquisition that we’ve rolled into in existing overhead base. We’ve made two acquisitions that have caused us to redivert our well schedule and we’ve experienced lots of disruptions from the hurricane late in the year. So, we’ve dealt with a lot of disruptive factors and still delivered really good results. I anticipate a much quieter 2018 from a development standpoint and that we really know where we’re going to drill. I think, by the end of the first quarter, we’ll have every one of our pads built. In 2017, we were -- we are really focused on building out infrastructure. We’ve spent money at Burns Ranch to build SWD backbone and gathering backbone which will serve to reduce our costs, long-term, on our new wells. We’ve done the same thing at Cyclone. We acquired a lot of 3-D, which we think is important to staying in target. So, kind of frontend loaded some of that. It should result in better net well costs for us. So, I don’t think there is a lot of guess work there. We drilled a lot of two-well pads in 2017, because we spent that upfront money, because we were really cognizant of CapEx to cash flow cycle times. Next year, the bulk of our program will be three-well pads. So, should be able to bring out some efficiencies there. Pressure pumping costs have been very stable for the past five months. Our outlook is that they probably remain that way. And lastly, prices are great now; we’re enjoying higher prices, but we’ve got a very robust hedge book. So, that hedge book is designed to deliver close to cash flow neutrality and much lower prices, should that happen. So, we feel like this has been a big year transition. Next year is going to be a little calmer or a little more -- little better planned. And we think we’ve isolated all the variables we need to execute.

[Mike Kelly:]

That’s great color, Frank. I appreciate that. It looks like you guys set up well for 2018. Thanks.

[Frank Bracken:]

Thank you, Michael.

[Operator:]

Frank, we have no further questions in the queue.

[Frank Bracken:]

Okay. I just want to wrap up by saying, I appreciate your time. We’ve made a lot of progress over 2017 to position the Company to be long-term cash flow neutral, but still grow at attractive rates. And we’ve done a lot of balance sheet repair over the last couple of years. What we’ll be looking for going forward is delivering growth on a per share basis. We think that’s really important. Cash flow per share ought to be over $2 a share next year. And on a stock with the four handle on it, that’s strikes me as something that we’ll probably get re-rated as long as we can execute. And as I hope, my comments on this call have reflected, we’ve got a lot of things nailed down to execute next year and deliver that 10,000 barrels plus and a $100 million plus EBITDAX. Thanks very much.

[Operator:]

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