Lonestar Resources US Inc.
Q2 2016 Earnings Call Transcript

Published: 22 Aug 2016

[Operator:]

Welcome to the Lonestar Resources Second Quarter 2016 Financial Results Conference Call. [Operator Instructions]. Please note this conference call is being recorded today August 22, 2016. I would now turn the conference call over to your host, Frank Bracken, Chief Executive Officer. Frank, please go ahead.

[Frank Bracken:]

Thank you, Julian. With me today as always from Lonestar are Douglas Banister, Barry Schneider, Tom Olle and [indiscernible]. Also on the call Bryan Moody, who we have hired as our Chief Commercial Officer recently. Bryan comes to us from a look Eclipse Resources and we're very happy to have A&D efforts at Lonestar. Before I get going I want you direct you to cautionary note regarding forward looking statements safe harbor and disclaimer on page two of the conference call slide. I also want to inform you that all the numbers we will refer to you today are those of the Lonestar Resources limited an entity which no longer exists but was the reporting entity as of June 30, 2015. Going forward. Lonestar will report financials for Lonestar Resources US Inc., the Delaware C-Corp which is now the parent company and current registrant on the NASDAQ. All right let's get started. Please turn to slide 3 for opening remarks. The charts on the right of the slide indicate that production averaged 6573 barrels a day equivalent for the second quarter 2016. The company's production rates rose modestly sequentially as new Eagle Ford Shale wells were placed on stream at a slower rate than in past quarters. During the second quarter Lonestar placed two new Eagle Ford shale wells on stream during May of the quarter. Lonestar holds a 42% working interest and a 33% net revenue interest in these wells meaning that Lonestar added two gross 0.8 net wells in the quarter which is down compared to 2.9 wells put on stream in 1Q '16 and 2.3 wells net in 4Q '15. However inspite of the slower drilling pace, I'd point out that Lonestar's crude oil production rose 17% sequentially in the second quarter as Lonestar’s 2016 completions have all been in the crude oil window. Lonestar has also made some very significant strides in the last 90 days in term of improving the underlying value and the market position of our equity. On July 5, 2016 Lonestar achieved a milestone in the company's history when its registration statement was declared effective by the U.S. Securities and Exchange Commission and it shares commenced trading on the NASDAQ global market under the symbol LONE. On July 6th, the company's shares were delisted from the Australian Stock Exchange as a further step to move the domiciled parent company from Australia to the United States as a Delaware C-Corp. We believe that this puts Lonestar on more equal footing with its U.S. peers and is a first step in improving our equity valuation across -- and access to the world's largest pool of capital. Lonestar has been intensely focused on positioning the company so as to enhance its financial flexibility and proactively improve the balance sheet; first, effective July 27th, Lonestar Resources America the guarantor of all the company's debt [entered] [ph] into third amendment to its credit agreement of the senior secured revolving credit facility. Most notably the third amendment provides relief on the revolver's debt to EBITDAX covenant expanding the limit to 4.7 times in the 2Q and then allows for a glide down of 0.25x per quarter over the next four quarters to get the covenant back to four times at the end of 1Q '17. This covenant relief did come at an interest rate grid that we really think is just backed in line with the current first lien market. Importantly, our third amendment also allowed for the issuance of up to $50 million of second lien secured notes, notably this was achieved with no reduction in our $120 million borrowing base. The third amendment provided the tools Lonestar needed to improve our balance sheet through debt reduction. On August 2, the company entered into an agreement with subsidiaries of Leucadia National Corporation which allowed for the issuance of 49.9 million of second lien notes which are secured by second priority liens of substantially all the company's assets. These second lien notes pay an interest rate of 12% quarterly. Lonestar has currently issued 25 million of the notes leaving 24.9 million available for additional issuances and most importantly to this whole equation as of August 18th the company had executed open market purchases totaling $48.4 million of its senior unsecured notes. These purchases were funded by the company’s aforementioned issuance of 12% second lien notes. The net effect of these transactions is $23.4 million in total debt outstanding which also yields a $1.4 million of interest expense savings on an annualized basis and to put that $23.4 million debt reduction in perspective for our equity holders we've reduced debt by more than $3 for every one of the more than 8 million shares outstanding which I think is very significant in the context of our current share price of around $9. I plan to give you an operational update later in the call but want to turn the call 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 second quarter press release or as depicted on slides four and five of our conference call slide deck. Lonestar Resources registered a 13% increase in net oil and gas production to 6573 boe per day in 2Q, 2016 versus 5804 Boe per day in 2Q, 2015. In the second quarter of 2016 77% of the company's production was from crude oil and NGLs. The company continues to focus its technical and capital resources on the Eagle Ford shale where it generated a 17% increase in net oil and gas production over to 2Q, 2015 results to 5999 boe per day. Lonestar's lease operating expenses for the second quarter of 2016 were 4.4 million representing a 4% decrease over 2Q, 2015 lease operating expenses of 4.6 million. Notably lease operating expenses on a dollar basis were reduced in spite of a 13% increase in production volumes. The factors combined yielded a 15% reduction in total field operating expenses on a unit of production basis from 2Q, 2015 level of $8.68 per boe to $7.35 per boe in the current quarter. Adjusted EBITDAX for the second quarter of 2Q, 16 was 16 million compared to 22 million for 2Q, 15 as a 13% increase in production volumes partially offset a 21% decrease in revenues due to a sharp decline in West Texas Intermediate oil prices and Henry Hub gas prices compared to 2Q, 15. Please see non-GAAP financial measures at the end of this release for the definition of adjusted EBITDAX, a reconciliation of adjusted EBITDAX and net income loss and the reason for its use. Lonestar reported a net loss of 12.8 million for 2Q, 16 versus a net loss of 8.4 million in 2Q, 15. This loss into 2Q, 15 includes a $13.2 million loss associated with non-cash mark to market revaluation of Lonestar's crude oil hedges portfolio. At June 30, 2016 $99.5 million was outstanding on our $120 million senior secured facility. I will now turn the Frank for additional comments.

[Frank Bracken:]

Thank you, Doug. As we do each quarter we try to provide some topical commentary that's intended to give you some insights about how we're positioning the company as well as give you some detailed results from the business. I do want to reemphasize however that a significant amount of my focus has been getting our financial position improved and I hope to provide you with further progress on the third quarter call. I will now refer you to slide six to update you on progress we made under our Geo-Engineered Completion Alliance with Schlumberger. The significant amount of production history we had from the 19 wells we previously completed at Beall Ranch made an ideal place to initially tech - test our Geo-Engineered Completion Alliance. The map in the upper left quadrant of slide six shows you the location of our three new wells which were drilled on 500 foot spacing shown in red and the large number of direct offset that have been producing from one to five years now which complicate stimulation and production practices and it's something the whole industry is dealing with as well density increases in the play. The [28H] [ph] well which is the most proximate to the depletion had underperformed our third party projections modestly thus far but in fact it's fracture stimulation gave a 100 barrel a day boost to the offsetting 19H well which has been on stream over three years now nearly tripling that well’s production rate on a sustained basis. For simplicity of presentation we’ll isolate the performance of 21H and 22H for purposes of comparison. Our Geo-Engineered Completion Alliance or GECA was germinated out of the success we had drilling our 26H through 28H wells shown in blue on the slide which use certain elements of the technology package we have incorporated into the GECA which Lonestar believes were significant contributors to the 43% outperformance today compared to the direct offset the 32 through 34H depicted in orange which were completed in July 2014. Lonstar initiated the GECA by drilling -- the drilling and completing the Beall Ranch 20 through 20H wells with an average perforated interval of 6075 feet in the first quarter of '16. The wells were drilled in perforated with roughly 7000, 6000 and 5000 feet respectively and from a technical perspective our goal was to build on the success that we had in the 26 through 28H wells particularly by running through a bit logs in all three laterals to try some very novel things with our frac job. Through [indiscernible] run through the entirety of the lateral and consist of a triple combo log in addition to spectral gamma ray log and dipole sonic log which in conjunction with Schlumberger mangrove stimulation software is providing us with incredibly detailed rock properties analysis which enable us to model vertical and lateral stress rock heterogeneity fractures and even allow us to count for multi-well stress shadows so that we can optimize our zipper fracs that we employ across our portfolio. This work was instrumental in designing our completions which utilize for the first time in loan stars history [indiscernible] Broadband Diverter product and enabled us to do some very novel things within each stage by setting perforations across two different stress profiles half of which could be fraced at low initiation pressures, then after pumping the Broadband Diverter mid-stage we're able to pump the second half of the sand volume into a set of perforations with materially higher initiation pressures. The goal here is to break more rock and to improve perforation efficiency and hydrocarbon recoveries and importantly do so with fewer stages. The most recent set of wells had stages of every 300 feet as compared to 215 foot spacing on the offsetting 26 through 20H. While still preliminary though production results during the first hundred 150 days on streamer are very encouraging as cumulative production is 14% higher than that of the 26 through 28H wells drilled 12 months prior when compared on a barrel per lateral foot during the same period of time. So I think we're getting more rock broken and we're doing it with fewer stages which as service prices start to climb again will be very, very important economics. The graph in the bottom left quadrant shows us daily production performances and time key plots for the older generation of wells and shows through two iterations of these improvements that we've engaged with Schlumberger we've achieved a 62% improvement and cumulative oil production per lateral foot to-date. Lonestar is very encouraged by the results of the GECA update and we'll seek to apply them across the portfolio. Lastly I'd point out this performance coming at reduced cost. These wells were drilled and completed $4.1 million but were in fact nearly twice the length in terms of perforated interval of the offsetting wells. So we're able to see a dramatic improvement on a completed per lateral foot basis and are very happy with the economics associated with these wells. And I will refer you to slide 7 to update you on progress we made on the second set of wells we completed under our Geo-Engineered Completion Alliance encouraged by the results of initial six wells on our Harvey Johnson lease in South Gonzales County. Lonestar has leased an additional 1450 net acres in a project we call Cyclone through June 30, 2016 just west of Harvey Johnson where we drilled six really good wells. Our initial land position in Cyclone area is depicted in yellow in the lease map in the top right quadrant to slide seven. I note that the area -- that the acreage depicted in green were top leases that we took that we could execute to expand our lease position in the event of good drilling results on our initial wells. On May 12 of 2016 Lonestar drilling completed the cycle in 9H and 10H on these lease holds, those wells are depicted in red on the map after drilling a pilot hole and running the same sorts of logs that we've run at Beall Ranch to gather information on rock properties in petrophysics. Lonestar drilled and completed the 9H and 10H in the Cyclone area with an average perforate interval of 6685 feet. Lonestar owns a 42% working interest, 33% net revenue interest in these wells. The two new wells were fresh fracture stimulated with an average proppant concentration of 1518 pounds a foot and I'd like to know we used the Schlumberger Broadband Diverter here in an incremental way to help direct profit into the Eagle Ford while limiting the loss of frac efficiency into the overlying Austin shock which had seems some fairly intense depletion of well bores the directly over lied the Cyclone 9 and 10 making these frac jobs particularly challenging. Results have been quite good thus far. The 9H tested at 598 boe on 1968 [indiscernible] and registered a 30 day average production rate of 486 boe per day. The 10 tested at 631 and registered a 30 day production rate of 521 boe a day. Originally estimated to cost $5.2 million including pilot hole these wells have been drilled and completed for an average cost of $4.7 million. At this combination of cost and recovery we believe this area meets our long term investment hurdle of 30% or higher. Based on a result of the initial Cyclone wells, Lonestar has executed a set of agreements to lease an additional 1322 acres net that directly offset the 9 and 10H wells. These additions increase Lonestar's total leasehold in the Cyclone project to 2656 acres as August 15, 2016. This pro forma [indiscernible] sold position is shown in yellow in the bottom right quadrant of the slide seven with a modest amount of additional acreage still in complete status. This leasehold is expected to accommodate 29 additional laterals on 500 foot spacing with the average lateral length exceeding 7000 feet and should represent nice reserve additions for Lonestar at year-end in 2016. Just a couple other notes, in the property market that really appears to be inflated currently by private equity money and new basin entrants these sorts of organic primary lease additions soon to be a much more prudent way of growth for Lonestar and I turn out that where we're optimistic that we'll be able to pull down more of these sorts of reserve adding transactions during the remainder of 2016. And lastly while we don't have a slide dedicated to it I'd point out that we recently entered into an agreement to execute a acreage swap with another operator in the Burns Ranch area in the South County. This swap will consolidate Lonestar's leasehold position so that we can now drill at our own discretion. Within the leasehold associated with this trade prior to the lease swap we had 19 gross, 15.1 net laterals and booking a total of 152,000 feet. Post-swap we had 18 gross 16.1 net laterals totaling a 151,000 lateral feet. So net-net we’ve swapped into less CapEx while retaining the same number of feet within ultimate perforate interval. Lonestar's commenced drilling operations on the Burns Ranch Eagle Ford B unit number 8, 9 and 10 wells. Those wells have averaged plan lateral lengths of 9000 feet and Lonestar anticipates the completion of these three wells will increase the leasehold that is held by production at Burns Ranch from 2712 net acres to 3328 net acres which would then equate to 86% of our lease hold here which is a nice step in terms of locking that down as HPK [ph] for the future. This concludes our prepared remarks. I'll turn the call back to the Julian now for any questions.

[Operator:]

[Operator Instructions]. We will now take our first question from Steve Berman from Canaccord. Your line is open. Please go ahead.

[Steve Berman:]

Can you talk a little bit about what - may be the type curve you are for the Schlumberger wells and maybe even the Harvey Johnson wells, I know you said the Harvey Johnson is at 30% plus returns. Any thoughts on the EURs in either one of those areas?

[Frank Bracken:]

I would say we’re too early to really talk about the new EURs on the Beall Ranch wells. We will deliver those at year-end. I would note that we did sit down with Von Gonten at the year-end 2015, show them what we had done on the first set of wells, discussed our detailed plans in terms of the Geo-Engineered Completion Alliance and I think we did get some credit from Schlumberger in terms of EURs at Beall Ranch. The good news is we're outperforming those thus far. As it relates to South Gonzales we're talking about something like - you know it will be I’d say on average 350,000 barrels of oil plus associated gas for those wells and at the cost that we've got you know they make good money.

[Steve Berman:]

Okay. What do you anticipate the cost saving in your Beall Ranch wells with the Schlumberger technology there?

[Frank Bracken:]

Well we drilled an average 6000 foot lateral for 4.1 million.

[Steve Berman:]

[Indiscernible] complete, total cost?

[Frank Bracken:]

[Roads opened out] [ph].

[Steve Berman:]

Couple more, can you update us on the sales process on the conventional assets, where you stand with that?

[Frank Bracken:]

Sure. I would just say that we continue to be encouraged that we’re going to sell these assets. I would note that based on the nature of those assets we’re dealing with some fairly small companies many of whom have had to go through some gymnastics to get financing. So I would tell you that's what's probably drag this process out a little longer than I would have preferred but still remain comfortable that that's something that we'll be able to report to you at the end of the quarter.

[Steve Berman:]

And last one from me, second half CapEx assumptions for us for Q3 and Q4 if you could break it out?

[Frank Bracken:]

Let me first say that I think I prefer to limit it to the half year. I think we just have to keep in perspective you know the larger global goals that we're trying to achieve. During the quarter we’re able to secure a substantial amount of flexibility from our banks. We've used that flexibility thus far to reduce net debt and everybody should know that reduction in net debt on the most accretive means possible remains our primary goal for the third quarter as well. We're just seeing too many opportunities to not really focus on getting our house in order on the financial side. So we sold down those two Cyclone wells more than anything to conserve capital but let me tell you this we're going to drill three wells at Burns Ranch we'll drill two wells at Carter Lake. They will happen in the -- they will at least get drilled -- some of them should get completed by no means they will all get completed in the second half of the year but we'll get five wells going. You should expect high working interest at Burns Ranch something on the neighborhood of 30% to 50% working interest at Carter Lake and I will tell you those wells are $5.5 million to $6.5 million a copy.

[Operator:]

Our next question comes from the line of John Aschenbeck from Seaport Global. Your line is open. Please go ahead.

[John Aschenbeck:]

I had a follow up here on Steve's question actually, I just wanted to get the other side of the equation there on the production outlook for the remainder of the year. I know you previously alluded to the potential to hold production flat to up 10%. I was wondering if that was still the case for '16, and then also if we could just take that one step further, maybe get your preliminary thoughts on what you guys are thinking for 2017 assuming the strip plays out and we see oil prices at $50 plus.

[Doug Banister:]

It's funny we have had to make all sorts of adjustments as a company as it relates to how we talk to people, the whole 10-Q process has been a little bit of a ratchet for us. So with said we have made no change to the guidance. Flat to up 10% is still in the cards, it will really be a function of timing and how we spend some of the liquidity we have in the interim. Right, I mean I have got a little bit of a from a timing perspective thought -- I've got two places to spend money, I can spend it in the bond market or I could spend it on drilling. So that's still in Q3, it is going to be a bit of our capital allocation decision tree, but I do think we've made no change in the guidance, zero to 10 is still realistic. As far as '17 goes there are -- I'd prefer to reserve that sort of disclosure you know again what we want to be is very active. We think that the farm-in market or places where we can move the rig to ensure activity that garners us lease acquisitions in competitive environments is they are rampant, even big companies are through lack of the fulfillment of continuous drilling obligations letting leases expire. Many of those are associated with really nasty gas gathering agreements and so those are really attractive to us. So we want to be very well positioned for 2017. We want to be very active in 2017. I just - based on all the moving pieces on the balance sheet I prefer to reserve judgment until probably this time next quarter when a lot of these balance sheet issues are clear for us.

[John Aschenbeck:]

Got it, that’s helpful. Actually a segue here into my follow-up and the potential for additional debt buybacks which seemed like a no brainer if there's more of those available. I just want to get your thoughts on what are the remaining opportunity set is there, how many of those you thing could buyback if any?

[Frank Bracken:]

Well our goals and limitations -- we would love to buy them all back right but I think that you know the bond holders are a desperate group of people they have various views about commodity prices and Lonestar but suffice to say that the transactions that we've engaged in to-date have been incredibly accretive to the company and it's certainly our desire to continue to execute similar trades and it's a market. There's a buyer and a seller and we'll have to see how we do but it is our intention to continue to pursue them and we have the financial flexibility to do that.

[John Aschenbeck:]

And then last one for me, just wanted to get more detail on the upcoming Brazos County completions and sorry I missed this but was just curious how much those are expected to cost and then what kind of initial rate from those wells would be considered a good rate?

[Frank Bracken:]

Those wells would be about $6.5 million and one of the things that we've really been trying to do in Brazos County Brad is expand our scope in this depth that I would call on strike with all those really, really high rate apache wells. And I'm sure you noticed that we issued some stock for a 50% interest in a couple really big units in the quarter. We've also as part of that traded some leasehold and we'll have a partner in those wells. So they're about $6.5 million, at this point we're going to plan on running three strings of pipe which does elevate the cost associated with these wells, but what we've got a bigger playground now as well and that's really kind of what we want to do. We want to spread our capital dollars over this swath of acreage. I would tell you that we've really always tried to refrain from making forecasts about what wells are going to do in any given area but I would refer you to the Walker Family, the Ray wells that are a immediately offsetting this acreage, those are apache wells, very, very high. They've all had test rates well in excess of a thousand barrels a day. They should be pretty there's added CapEx, we would clearly expect incremental productivity associated with these as well.

[Operator:]

Our next question comes from the line of Jeffrey Coles from Jefferies. Your line is open. Please go ahead.

[Jeffrey Coles:]

Good morning, Frank. Thanks for taking my questions and congrats on the progress you guys have made so far with the balance sheet. So just kind of a few questions just wanted to start off on the cost side, you mentioned that you're starting to see some creep in services cost and kind of seeing how low your F&D [ph] cost has been over the last four years. Just wanted to kind of could you talk a little bit about kind of what you see as the permanent -- more permanent reductions in cost that you've seen in F&D versus kind of the services cost on it?

[Frank Bracken:]

Yes let me let me clarify that. We haven't seen any increase in cost yet but what if I'm going to put two and two together and Wall Street analysts are correct and oil's going to be high 50s or low 60s I think that that back cost creep would be inevitable right But we have seen zero to-date, I can assure you that. But it's just something that we anticipate and clearly with everyone the single biggest cost associated with stimulating any of these horizontal wells is your pressure pumping job and so we're -- that's we're really focused on and while the industry is choosing to solve this problem of heterogeneity within the reservoir with tighter and tighter spacing we're viewing this application of broadband as a means to really develop the differential cost structure, right, I mean everybody else is moving to sub-200 foot spacing so that they can break like rock. We’re back and off to 300 feet using the broadband pills as our differentiator. So we would anticipate that for some time that practice -- and broadband is effective we think in terms of giving you better perf efficiencies, you’re going to get a better denominator in your finding cost equation but I think as pressure pumping costs go up your ability to get the same or better performance with fewer stages is going to really help your numerator out and on the F&D side. So that's a kind of a big strategic push we're making to try -- we're little we've got to get legs up where we can, it's not through pure purchasing power or anything like that. We just have to try to be craftier and more forward thinking. So that's what we're trying to do there. In terms -- I think it's going to be a long time before you see a lot of improvement in rig rates. There's a lot of stacked iron out there that's going to have to come back to work so we don't think that's a big issue. So it's I would tell you I think pressure pumping is where you're going to see it first and because I think the pressure pumpers as an aggregate are you know -- they might be doing better than breaking even in the field right now but I think fully loaded they're probably not. So I think they're going to try to exert price leadership as soon as they can.

[Jeffrey Coles:]

And then just quickly, you mentioned in the press release that you picked up some acreage from last quarter, just kind of wanted to see within Brazos is that closer your engineer or non-engineer properties and kind of how were you thinking about that transaction from a strategic point of view?

[Frank Bracken:]

Sure. I mean I think I would tell you that that transaction was part of the global series of transactions that we entered into with Leucadia. I would characterize it is as somebody that we chose to partner with. We know the people within that organization well, have longstanding relationships with them and I would tell you that we’re helping each other out. We're helping them out in the field in terms of trying to get the most out of their asset that they have ownership of and they're trying to help us with our balance sheet issues and they've got equity and warrants now that incentivize them to see Lonestar succeed.

[Operator:]

Our next question comes from the line of Matt Heckler from Logan Asset Management. Your line is open. Please go ahead.

[Matt Heckler:]

Frank, just a couple of questions. First is around liquidity, can you give us a rundown of where you stand today in terms of cash -- in terms of what you could borrow on the ABL?

[Frank Bracken:]

We can borrow up to 120 million on it until we sell the conventional assets there's no reduction in that. Next borrowing base redetermination is November 1st.

[Matt Heckler:]

Okay. So you got the full 120 there and what's your cash balance today?

[Frank Bracken:]

It was 5 million at the end of the quarter.

[Matt Heckler:]

Okay. And then on the [indiscernible] go amount of that 50 second lien, that whole 25 million I guess is still available.

[Frank Bracken:]

Correct.

[Matt Heckler:]

And how does that all intercept? Because I guess I thought that your credit agreement debt was capped at 140 but if all of these are available then I've read that indenture--

[Frank Bracken:]

The thing that governs our senior secured incurrences is the senior unsecured note indenture and that's a total of 150 million. Yes you're right there's lots of threading and needling that gets done but all year we've really tried to engage in a drilling program that matches CapEx and cash flow. So we're trying to live within our means there and then work the other piece of the balance sheet around as we can.

[Matt Heckler:]

We will move on. Can you tell me about the IOG facility has any of these recent financings changed the status of that facility and what's available on that today and I guess how come you guys haven't sought the use more of that capital.

[Frank Bracken:]

Yes, in fact we are. The Cyclone wells -- we drew I want to say about to five to drill the Cyclone wells. Here we are using it and the Cyclone project we did all the science. We've mapped this regionally. There are more opportunities out there we had. We have some theories about how broadband could help us mitigate the effects of [indiscernible] depletion. We went out and tested it and we've tested it very successfully we think and IOG in the Cyclone wells for about 50%. So we're able to really the key to getting that acreage was giving older gentleman a one year lease, the guys going to live forever, he looks like he will be alive for another 50 years but he just wanted to see wells drilled on his property before he died. So we signed a one year lease having the availability of the IOG money was really critical in being able to make that commitment to him and so that acreage set up most of the -- testing that project really set up the incrementally lease acquisitions that we are able to pull down. So I want to tell you in rough terms we've used about 15 of the 85. I can tell you that we're working on lots of things right now that could take precedent over some of the other drilling or augment the other drilling where we would absolutely seek to use that IOG money in calendar 2016. We're really pleasantly surprised by the quality of the acreage that's coming back to the market in proven areas and it's something we talked about as our original business plan as being a secondary and tertiary buyer of acreage and I will probably tell you if I wouldn't believe this kind of acreage come back to market. So we'll need that money desperately as you point out we're going to be tight but we've been tight all year. We'll use that IOG money to our advantage in the second half the year.

[Matt Heckler:]

And there was a pretty big working capital move quarter over quarter, I know it was a coupon quarter but what else is happening there in the payable section that is driving that and how would you tell me to think about networking capital to the balance of the year?

[Frank Bracken:]

Yes I would tell you -- first there were several things going on, there's lease acquisitions associated with the Cyclone area. There was an extra lease acquisition that we took down, one of the other operators in Burns Ranch made a boo-boo and didn't catch an extension and we were able to pick up some more acreage so that was not a inconsequential piece of that working capital move but you've also got just got wells that dragged from late in the year. Wells that straddled year-end were drilled in the first and second quarter. So a lot of that was just make-up getting those knocked out.

[Matt Heckler:]

Okay. And what about the back half of the year? Used or source of cash into the back half of the year?

[Frank Bracken:]

Maybe real late in the year, we might run -- you could see those run up a little bit at the end of the year as well. Really is going to depend on timing of wells and completions and that kind of stuff. That stuff we tried to predict internally and never do with complete precision, there's just too many moving parts out in the field.

[Matt Heckler:]

And then can you talk to us a little bit about your hedging strategy from here. I think your MD&A talked about you added some hedges for '17 but what are you thinking and -- what it would take you to be more aggressive to hedge your production in '17 from here?

[Frank Bracken:]

Sure. So we have kind of move that up to we kind of nearly double that and we've got an effective floor of 52, that’s a really -- and we've just been trying to kind top pick the market when we can on these trades in the year. Historically you know the hedging business has been won [indiscernible] said okay, $90 oil, $80 oil. The returns that we're getting in the business at those prices are excessive, right, they are 80%, 90%, 100% IIRs there. You go lock those in all day every day. The current environment is a little different, right, I personally feel like the strip probably under bought. I think prices are going to be higher than 52. Now we don't want to better business on that but you know one of the things that we're wrestling with intellectually right now is what if you go lock in price early, service costs rise and you've got the bad juxtaposition of those two for the first time. So we're being pretty prudent about what we've got hedged. And what we have got hedged is I would call it good security at $52 if Dooms Day comes and prices go way down and we get really choked off in terms of what we can spend next year, that's how we thought about it thus far but it's a more complicated equation than we've had in the past.

[Matt Heckler:]

But can I ask you does the bank lenders require you to do any basic amount or do they have any restriction again doing more?

[Frank Bracken:]

There are not any and nor have there ever been any Lonestar hedging requirements. I think they've always been pretty happy with the way we've done our business in that respect. The limit -- and one of the real improvements to our credit agreement that we when we moved it to Citi was we got a vastly expanded capacity to hedge so we can hedge up to 90% of expected volume. So that's probably as liberal as anybody three times our size and we probably earn that because we've been pretty good at it so far. So it doesn't -- it's really, I would tell you that the -- our agreements really don't would never get paid [ph] how we do that business. We will -- just be our own judgment, got a lot of leeway there.

[Operator:]

Our next question comes from the line of James West [ph], who is a Private Investor. Your line is open. Please go ahead.

[Unidentified Analyst:]

Sure it's about [Technical Difficulty] from my understanding it's 65% interest [Technical Difficulty] and that the expiration unit going to begin unravel here in 90 days and what is your position is on that and the plan to just let it go?

[Frank Bracken:]

Let me restate as fact as opposed to that. We have very little bit -- the federal unit formed and maintained through a series of capital expenditures which involve drilling several wells. We have very, very little acreage which is going to expire in calendar 2016. If you'll carefully read our 10Q we made an allowance for those expiring acres because I think the likelihood is that we don't get anything drilled this year there's still a change, we got to look at it probably [indiscernible]. I would tell you the least a acreage doesn't really start to unravel till 2018. So there is still time to do things out there. We just have a lot of other considerations including partners to deal with over there.

[Unidentified Analyst:]

[Technical Difficulty] requirements of couple of wells that need to be started much faster sometime this quarter in order to keep that unit in place?

[Frank Bracken:]

Well the unit doesn't really stay unless you drill but the unit, the real benefit of the unit is once you establish commercial production prevents the expiration of any acreage. So we think we have got enough to be out there to potential of getting what we need to do from a drilling perspective whether or not the unit can be revised or not.

[Operator:]

[Operator Instructions]. Our next question comes from the line of [indiscernible]. Your line is open. Please go ahead.

[Unidentified Analyst:]

Frank, you mentioned earlier in terms of 2017 beyond that opportunity continue to expand acreage due to expirations. Can you just expand a little bit on those thoughts and are you really looking more to expand more in adjacent areas or are you also continuing to look at other parts of the Eagle Ford where you may see some explorations?

[Frank Bracken:]

Yes one of the cornerstones of how we've built this company is trying to develop drilling completion expertise from one end of the play to the other because we're -- while a lot of the asset packages that are hitting the market I would characterize them as it normally PDP long and inventory short which doesn't attract me at all and we just won't participate in those things. They just don't make any sense for Lonestar. We're trying to build -- the only way to really create value unless you're just price given -- is with the drill bit and so we wanted to -- we maintained and established I think expertise from Brazos County to Dimmit County. We're looking for incremental -- I think the smartest way to build value in this business is drill what wells are required to hold blogs of acreage that can become available and once HVPD [ph] and then [indiscernible] that acreage for what presumably -- what we get seemingly all presume to be a better price environment. That's really what we're trying to do in this market is buy things that we can earn our hurdle rate on but will really rerate as commodity prices improve. There is not a county we won't look in, I can tell you most occurrence is so unbelievably drilled up you're not going to find your way in there unless you require big package but we're saying we built expertise in Gonzales and we continue to see opportunities there that are really created through lack of drilling by the prior operator. We’re seeing the same thing in the South of Dimmit and there's just too much for many of these big companies and in some cases little companies say rights over and it goes away. There might [indiscernible] about picking up what makes sense to us and one last point I can make is that we really are trying to build in every county where we can bolt on, task on and build mass within each county that has strategic advantage to us as well.

[Unidentified Analyst:]

Are there any limitations on the use of the second lien, I know you've used a lot of it to-date to repurchase bonds but are there any limitations can it be used for drilling, can it be used for leasing? Just curious.

[Frank Bracken:]

If you're really borrow [ph] you can read the whole document. The used proceeds are general corporate purchases and bond repurchases.

[Unidentified Analyst:]

Okay. And then I know in the Cyclone area the recent lease acquisitions they really kind of fill in most of most of that area and I think you talked about setting up 29 additional longer laterals, when you look over the Q2 plan on drilling over the next 12 plus months is the focus going to be on some of the more 7000 foot plus type laterals or do you still have other areas that you may have to drill in the meantime?

[Frank Bracken:]

Well so it very intentionally the preponderance of our drilling inventory, our 8000 to 9000 foot laterals everything in Horned Frog eight plus, everything at Burns is now I think now pushing nine, Carter Lake we can at least get an 8000 foot laterals in and then here we've added 29 7000ish foot laterals at Cyclone. So you know the simple fact of the matter is that in most of the Eagle Ford you've got to have that lateral length turn hurdle rate for us. It gets cut to finance you know 5000 foot laterals out of cash flow. So we've got pretty big abundance of that sort of thing around and clearly this is where we'll focus our capital for the foreseeable future. I would just tell you I think that the likelihood we can do more of this is pretty good and keep attacking on these long lateral inventories.

[Unidentified Analyst:]

Great. And then lastly into the -- in terms of the sluggish relationship. Can you just remind me is there a finite into that or is that something that that we will continue indefinitely just I can't remember the terms of that.

[Frank Bracken:]

Sure. It's a 10 well program which should cover us this year. And we're very intentionally trying to allocate those wells across our portfolio right to see -- there are about six technologies in total that we're applying and once the 10 wells are done we will be able to sit back and evaluate what helps us where. In this deal we spend the money, we agree upon that the tight curve that should be met, if f the wells aren't 10% better than that tight curve we don't pay Schlumberger anything. If the 10% we pay them their pay them their invoiced amount a year later, if they're 20% better than the tight curve we pay them a bonus and our rate of return go berserk if we have to pay them that bonus. So we're rooting for that. So there's a lot of risk here on these first 10 wells but I would tell you that we have a very good relationship Schlumberger, I think frankly some of our technical people have been additive to some of their process particularly in terms of deployment of the broadband product. I think we are helping them incrementally. So I would envision that while some of these things may ceased being to be freebies for us or discounted or deferred for us we were believers in some and or all of these technologies and we'll seek to use them as appropriate property by property going forward. I mean we're pretty bought into what we’re achieving.

[Operator:]

Our next question comes from line of Patrick Sheffield from Beach Point Capital Management. Your line is open. Please go ahead.

[Patrick Sheffield:]

Just two quick ones, one the follow up to Matt's question earlier regarding secure capacity. You mentioned that in the bond [indiscernible] limits secure debt to 250 million if that's true today we're sitting at 125 million of secured debt between the new second lien and the revolver. Just curious how you think about using the remaining 25 for bond buybacks, would that effectively take you to zero liquidity unless you pay down the revolver, is that correct or how should we think about how you balance the two?

[Frank Bracken:]

Yes, your statement is correct. We also have the conventional asset sale that would generate liquidity in the meantime.

[Patrick Sheffield:]

Yes. Okay. And then just something that was in the Leucadia agreement that just wanted to see how you're thinking about. There is an reference to an equity offering if you are able to raise a certain amount of equity then Leucadia would need to put in a certain amount of equity as part of that raise? Are you considering an equity raise later this year or should we read anything into that?

[Frank Bracken:]

Well what we're trying to do is set out a long term plan and clearly first and foremost we're trying to address the debt side of the balance through asset sales and bond repurchases, right. Those things are helpful to the equity. If the market conditions -- if we had adequately solved our balance sheet issues from the debt side of the balance sheet prior this year what that to be clear if we went to the market and raised equity this year Leucadia would backstop half of that offering that's really what the agreement reads. So if we were to do it we go in with a lead order for half the offering but you know I tell you that sort of thing is super market dependent and super dependent on us achieving all of our other goals. If we don't get our absolute debt down the equity is pretty pricey.

[Operator:]

Okay and there are currently no further questions in the queue at the moment.

[Frank Bracken:]

Well thank you all very much for joining and thanks for the questions.

[Operator:]

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