Sanchez Energy's (SN) CEO Tony Sanchez on Q2 2018 Results - Earnings Call Transcript

Sanchez Energy Corp. (SN) Q2 2018 Earnings Conference Call August 7, 2018 11:00 AM ET

Executives

Kevin Smith – Vice President of Investor Relations

Tony Sanchez – Chief Executive Officer

Howard Thill – Executive Vice President and Chief Financial Officer

Analysts

Jeffrey Campbell – Tuohy Brothers

Tarek Hamid – J.P. Morgan

Jordan Levy – SunTrust

Sean Sneeden – Guggenheim

Andrew Griffith – Southpaw Asset Management

John Evans – SG Capital

Robert Ellenbogen – Credit Suisse

Owen Douglas – Baird

Vivek Pal – Seaport

Jay Spencer – Stifel

Jacob Gomolinski-Ekel – Morgan Stanley

Joshua Gale – Nomura Securities

Operator

Good day and welcome to the Sanchez Energy Corporation Second Quarter 2018 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Kevin Smith, Vice President of Investor Relations. Please go ahead.

Kevin Smith

Good morning and thank you for joining us. On the call today are Tony Sanchez, Chief Executive Officer; Howard Thill, EVP and Chief Financial Officer; Scott Dunlap, Vice President of Operations; and A.J. Phillips, Vice President of Assets Development.

Please note, that we may make references to certain non-GAAP financial measures, which are reconciled to the closest GAAP measure in the earnings press release. Our discussion today will include forward-looking statements which are subject to certain risks and uncertainties, many of which are beyond our control. These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website.

With that, I’ll turn the call over to Tony.

Tony Sanchez

Thank you, Kevin. Good morning, everyone, and thank you for joining us. This morning, in addition to discussing our quarterly results, I would like to spend some time discussing what we are doing to address the operational issues that we have experienced over the last couple of quarters. As noted in our press release this morning, we recently embarked upon a comprehensive review of the Company’s operating business and technical strategy, with the goal of enhancing production and increasing operating margins. We anticipate that this review process and the implementation of the resulting action items will have a sustainable and long-term positive impact on the company and importantly, be the source of steady and continued growth in production that our unique asset base is capable of delivering.

Our employees are fully engaged and supportive of this review and revamp, and believe it is important to the Company’s continued success. After a relatively seamless integration, initially, of the Comanche asset early last year, we have experienced several quarters of production results they have not lived up to our expectations. During the second quarter of this year, we continue to see higher than anticipated production declines on Comanche wells brought online during the second half of 2017 and early 2018.

As discussed during previous calls, the key issues driving this underperformance with the testing of a more aggressive flowback strategy, tighter spacing of the DUC wells acquired with the Comanche asset and poor Upper Eagle Ford well performance and some of the delineation in step our areas they did not deliver the anticipated production rates we had expected. We began taking corrective actions to remedy these issues in the first quarter of 2018. The first step was to revert back to a more conservative flowback strategy, which, while it lowers initial production rates, is expected to result in a more stable and predictable long-term production profile.

We have already started to see the benefits of this strategy and project that may take several months since initiated, until a more stable production profile is apparent in our overall results. Additionally, the topic of well spacing has received a lot of investor attention this year, particularly as it relates to the Eagle Ford. Starting at the end of the first quarter of 2018, we also elected to increase in-zone well spacing where appropriate.

As we have previously discussed, we do not drill wells tighter than 600 feet in zone – with in-zone spacing. In fact, during the second quarter of 2018, our average well spacing was approximately 660 feet at Comanche and over 700 feet at Catarina. It is worth noting that the spacing on the DUC wells I mentioned earlier was tighter than we would’ve liked. But since we only have the cost of completion in these wells, the capital we spend on this completions were still an economic investment.

Beyond those corrective actions, we have also significantly reduced the number of Upper Eagle Ford wells in our drilling plan for this year. And in most cases, we are looking to replace these with Lower Eagle Ford wells. Now we recognize that these corrective actions by themselves would not be sufficient to get us to where we want to be in terms of operational efficiencies and mainly sustainable production growth and increased cash flow margins.

By recognition, led us to what we believe will be one of the most promising steps we have undertaken today, the comprehensive review of the Company’s operations and technical strategy. To facilitate the timely, efficient and thorough evaluation of our operation, we engage a leading consulting firm in the second quarter of this year to conduct a full assessment of the Company’s performance across all aspects of the business.

While this project is focused predominantly on our operations and technical strategy, we are looking at every aspect of our business to improvement. This review process has already lead to the identification of several key areas of focus, where continued improvement should have a meaningful and lasting impact on production and operating cash flows. These areas of focus of our opportunity to relatively low-cost initiatives that can significantly boost the Company’s overall drilling performance, production and returns on invested capital.

The first of the focus areas involves reducing well downtime, in order to achieve incremental production growth, by reducing unplanned compression downtime and planned shutdown for gas lift compressor installation and maintenance and improving upon our strategy for the mitigation of frac interference on existing producing wells.

Improving reliability is a particularly low-cost way in which to achieve incremental production. We are already evaluating, and in some cases, implementing ways to reduce facility and gas lift compressor downtime.

As it relates to nearby frac interference on producing wells, we are conducting a pilot project, into repressurizing parent wells during ongoing completion activity on offset well pads. As the pilot progresses, we intend to provide more details about this program. Another area of continuous improvement involves an enhanced focus on artificial lift and well workover activity. We have identified opportunities to improve the timing and the speed of artificial lift installation, as well as adding additional compression in the field, which is expected to clear identified bottlenecks across our surface operations.

Through a more active workover program, we believe we can reduce the frequency and length of the time wells are off-line in the field. This enhanced focus on basic blocking and tackling in the field has the potential for numerous benefits. Most visibly, we’ve initiatives should allow us to increase and sustaining production growth over time. The added low-cost volumes and more efficient operations will position us to reduced field level cost per unit, which will drive higher operating margins.

As we progress through this review process, we anticipate there will be many more opportunities for continuous improvement and we look forward to sharing our progress in the return to growth with you in the months to come.

Turning to our quarterly results. Our focus during the quarter was on full field development at both Catarina and Comanche. Accordingly, we operated between six and eight drilling rigs and four frac spreads during the quarter. At Comanche, we drilled 33 gross, 9 net wells and brought online 27 gross, 9 net wells. We currently have 54 gross, 16 net wells waiting on completion or currently completing.

As noted earlier, our development focus across Comanche entails well spacing of at least 600 feet in-zone and is predominantly focused in the Lower Eagle Ford. We are now completing all wells with a full slickwater design and flowing them back on a more conservative flowback drawdown approach.

These operational changes have resulted in positive outcomes so far, most notably, already a more stable overall production profile. Late in the first quarter 2018, for example, we brought 10 wells online in the Briscoe Metcalf lease of the Comanche Area three. These wells were drilled in a quad-stacked pattern that targeted both the Lower and the Upper Eagle Ford shale. They were completed with the full slickwater designs and propane concentrations of approximately 2000 pounds per foot. 30-day and 90-day rates from the Lower Eagle Ford Metcalf wells averaged approximately 1,368 barrels of oil per day and 1,135 barrels of oil per day.

The four Upper Eagle Ford Metcalf wells also had encouraging nine day and – 30 day and a 90 day rates, where the Upper Eagle Ford C wells averaging approximately 870 BOE per day and 815 BOE per day respectively. Catarina continues to be an operational highlight for us. As production results from the South Central area of the asset generate some of the highest returns of our asset base. The eight E31 and E32 wells in South Central Catarina, for example, achieved average 30-day peak production rates of approximately 1200 barrels of oil per day, 32% of which was oil.

In North Central Catarina, we recently brought three additional wells online that are performing in line with expectations. The wells had lateral length that averaged approximately 11,200 feet. The company has now drilled and completed 19 North Central wells. Based on the company success in the North Central area, we have derisked the vast majority of the drilling inventory on the Western and Central portions of our Catarina acreage position.

We conclude that by noting that the Eagle Ford operating environment is robust, with price realizations on oil and natural gas liquids once again increasing on a sequential basis. We have seen a great deal of interest in the basin recently and view this as a positive, given our large concentrated asset position in South Texas.

As a reminder, Sanchez’s oil volumes are priced based on – off of Louisiana light sweet, resulting in realized oil price for the quarter of $65.86 per barrel. While others in the industry are having takeaway issues, given our close proximity to the Gulf Coast, with strategic relationship with Sanchez Midstream Partners, we have ample takeaway capacity.

In closing, while the last several quarters have been challenging, we are confident that the strategy and corrective measures we are implementing will improve our financial performance over the long-term, allowing us to deliver the value for shareholders expect.

With that, that finishes my prepared comments and we’re now ready to start taking questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.

Jeffrey Campbell

Good morning. I’ll stick with one question that has two parts. In the press release, you reviewed four reasons for Comanche underperformance. I’d like to address number two, poor, Upper Eagle Ford performance and several delineation of step-out areas. My first question is, to what extent were these areas valued at the time of the acquisition?

Tony Sanchez

In terms of – this is Tony, Jeffrey. In terms of the valuation, they were not included in the initial valuation for the base case model. We typically want a variety of scenarios that layer in upside potential. And let me give you a little bit more insight into how we are viewing the Upper Eagle Ford and also addressing your question, how it factored into the valuation.

So at Catarina, the Upper Eagle Ford delivers and is fairly well productive and economic across the Western and Central parts. But what we are finding in Comanche is that there fairways of Upper Eagle Ford geology that work fairly well. So the comment on the negative Upper Eagle Ford results is really focused on those wells that were drilled in delineation in step-out areas. In the Metcalf area, that I mentioned during my prepared remarks, we’ve had pretty good Upper Eagle Ford results and that occurred in the fairway.

So as we look at our long-term development plan for Comanche, we will drill Upper Eagle Ford wells in the core fairway, where we now know it works and I think we are pretty comfortable that we now understand what that fairway geologically looks like. So back to your question on valuation, the way we value assets are to understand what the base valuation is, under what is existing production profile and regime. And that did not include Upper Eagle Ford for the most part.

Our upside scenarios to some extent, in varying degrees did, but in terms of what we pay for the asset and the inherent net asset value of our entry point, that is not dependent on success at the Upper Eagle Ford. That is a lower Eagle Ford wells during the cross-section, which continue to perform just fine.

Jeffrey Campbell

Okay. Well, that was great color and my second part on this area was, you mentioned that there were areas that were candidates for optimized spacing and completions based on geology. And I was wondering if this delineation area was an example of that, or maybe based on the remarks that you just made, that help to maybe define the fairway where the Upper Eagle Ford is kind of working in Comanche?

Tony Sanchez

Yes, to some extent is, that particular comment on enhanced completions and spacing is actually more of a catch-all across the entirety of the position. Fundamentally, we just – we haven’t gotten our arms around how closely we can and tightly we could space the wells at Comanche. In some areas, particularly the DUC completions we had early on, those were in field with the wells and it turns out they were functionally drilled, whether Anadarko drilled them or we drilled them, the in fields, they were too tightly spaced. Those wells also had a bit of a hybrid completion, they weren’t 100% slickwater and so we think that there was some deterioration of well performance by a combination of those two factors, mainly well spacing and the hybrid completions.

And then as I’ve mentioned several times, that coupled with more open choke, I think, led to more extreme depletion of the reservoir in those areas, which is what we continue to battle in our base production at Comanche. The new wells that we are drilling at Comanche and flowing them back on a more conservative choke strategy, are performing better than those legacy second half of 2017 and Q1 of 2018 wells did.

So I think we are on the right path. I know we are on the right path here, but unfortunately, some of the wells that underperformed several months ago, it takes time for them to flatten out and be contributing less to the base declines, while the new wells then start to kick in and overtake them. Now we are starting to see some of that effect take place. But overall, I think the comment that you asked about, I would say, is applicable to all areas.

We figured this out at Catarina, for instance, last year. And you would think that being in the same county or two counties, the geology would respond the same. But we are in the volatile oil window here and the geology does change. One size doesn’t fit all. So we are in the process of getting an optimization plan down for each of these sub-areas.

Jeffrey Campbell

That’s really helpful and we look forward to the results with interest. And we will see Sanchez tomorrow in New York. Thank you.

Tony Sanchez

Okay, thanks.

Operator

Our next question comes from Tarek Hamid of J.P. Morgan. Please go ahead.

Tarek Hamid

Good morning.

Tony Sanchez

Hey Tarek.

Tarek Hamid

Noticed in the press release no reference to guidance for fiscal year 2018. Sort of, should we expect any changes from the 80 to 84 you kind of put out for production in terms of the full year?

Tony Sanchez

Yes, that was intentional. We are not changing anything. There are some big changes taking place at the company, and I personally feel that chasing it quarterly with guidance, is probably going to not lead us positive or negative to the right answer. So the plan that is taking shape with a group that we brought into help us actually is basically getting us back to and this is not by design, it’s almost by coincidence, back to the initial budget that we had earlier this year.

And so that’s what the 80 to 84 is based on. I’d say, the once it kicks in, if we are able to achieve some of these initiatives, that’s probably a conservative guidance. But I don’t feel like we are in a position right now to either change guidance, reaffirm it and so therefore, we are just leaving it as it is.

Tarek Hamid

Got it. Fair enough. And then it looks like you had a decent build of DUCs and also some well shut-ins at Comanche, during 2Q, is that correct?

Tony Sanchez

I’d say, yes, probably, at this particular time when we wrote this press release, yes. But I don’t think it’s anything out of the ordinary. It comes in waves as we are completing pads and bringing them online. So if it looks that way, it was for this particular period of time. We are not building a DUC inventory intentionally, but at any given month or two-week period, we might have a DUC build and it probably just happens.

So I wouldn’t read into too much in terms of us building DUC inventory or anything like that at this point. We are completing these wells and bringing them online, in fact quite the opposite, as quickly as we can. So that the new well wedge can overtake the base decline. And then the work-over expenditures you saw in a marginally higher LOE is also a result of more work-over activity taking place as we convert and try to get ahead of what would normally be the plan. We’re trying to get ahead of these wells that are not coming off of natural flow back and changing them over to gas lift and getting them more stabilized as they come off of their natural flow.

Tarek Hamid

Got it. And I guess, as you think through sort of some of these kind of puts and takes, and some of the changes you’re making, it would be helpful to kind of give us a sense of sort of our production looked in July kind of relative to 2Q – sort of up, flat, kind of anything just directionally would be helpful?

Tony Sanchez

Yes, I think from a directional standpoint, I used the word in the prepared remarks, stable, several times to really address that. And I’d say, by and large it’s stable. We have days when it bumps up and then we have days when it comes back down. We did have a couple days in July that we had some major central production facilities shut down because of overheating. Heat waves were having adverse effects on the compressor facilities principally, and creating electrical shorts.

So, those only lasted a couple days. The description of stable, I think, what I view to be a very positive outcome is in these cases that I just mentioned, where large amounts of production went off for a day or two, we were able to bring it back to where it was prior. So, we didn’t really lose any production, which I think really points to the more stable production profile effect of the more conservatively choke-back wells, and the restricted wells.

They just pop-back a little bit better. So there’s a very short window, I was a bit reluctant to point to definitive better production rates because we’ve really only got a month or two under our belts on this more conservative flowback strategy. But it definitely, I think, is showing that production at Comanche is more stable than it was earlier in the year and I expect that as these new wells that we put online over the coming months start to kick in we should have an up-and-to-right effect on our production rate. So, that’s kind of the long winded way of saying flat and stable.

Tarek Hamid

Got it thank you very much.

Operator

Our next question comes from Neal Dingmann of SunTrust. Please go ahead.

Jordan Levy

Good morning guys, it is actually Jordan Levy here. Just a quick question, as you look at optimizing the completions across your position at Comanche, just kind of some little color on how you think about that versus completions at Catarina? And knowing that it’s kind of early days as you test across the Comanche position. Just kind of wanted to see if I could get a little more insight on how those might differ in terms of propane concentration and all that?

Tony Sanchez

I will set this, I will start the answer and turn it over to Scott and A.J. here. You are asking about the differences between how we are looking at development at Comanche versus Catarina?

Jordan Levy

That’s right.

Tony Sanchez

Is that correct.

Jordan Levy

Yep.

Tony Sanchez

So, at Catarina I think we found our groove. We found that 600 to 700 foot in zone spacing and about 430,000 pounds per stage is really the optimal point. And we’ve really just been continuing down that path the better part of this year. If you recall, in the first half of last year, we did some major testing at Catarina and we stubbed our toes. It wasn’t long before we were able to get production back to where it was previously at Catarina, by just going back to what I’d referred to as our plain-vanilla development plan.

And so we’ll continue doing that, if anything. Initially this year, our plan calls for us to – the Catarina 2018 plan was largely frontloaded for the first half of this year. So I think that we are going to just keep some of the rigs in the drilling that we had planned for the first half of 2019 in level above this year. As it pertains to capitals, I’m sure the next question would be on that. Some of that capital will be spent next year as we complete next year, but we’ll get ahead of it largely this year by drilling the wells that’s going to have a positive effect on the company’s overall production rate, because those wells are working very nicely. And right now, Catarina is a highlight. It’s outperforming and we found our groove.

Production at – our completion designs at Comanche, I think we are taking overall with our partners, were intending to take a more measured approach, but we will continue to test there. Given that, in some areas like the Metcalf area, we’ve seen some very positive results and in other areas, we’ve seen less than positive results, but for a variety of reasons.

In the areas that have not performed well some of the reasons have been overstimulation or wells that were spaced too tightly. And we are measuring now, which – what was the more – the larger effect on the adverse production results and changing accordingly. So I fully expect that Comanche will soon bounce back to where it should be and resume a production growth profile. And when we get that, you’re going to see production ramp for the whole company.

But of note, both of these areas should not be thought of as just one similar geology, they’re very different, more different than we had initially anticipated. And that’s what we are really trying to get our arms around, and the focal point is at Comanche, where we think, it’s probably going to be a bit wider spacing than tighter spacing overall.

Jordan Levy

Got you. Thanks. That’s great color. And just as a follow-up, just wanted to see any potential update on divestiture, as it relates to maybe the Comanche water system, or Maverick, or anything along those lines?

Tony Sanchez

Yes. Maverick, we continue to evaluate proposals. We’ve got several proposals that we are evaluating now for both the Maverick and Palmetto. I will say, we have not changed the way we think about this. We think that there is a lot of value and until somebody pays us for that value, we are not going to sell it on the cheap.

So those are producing assets, they’re contributing cash flow, we just brought some wells on at Maverick, which are very nice, 90-plus percent oil, and these Norma Jeanne wells, there’s only three of them, but they’re all producing about 400 barrels a day. We haven’t choked back. Those are either stable or slightly climbing. So I’d expect them to peek-out somewhere in that 400 to 500 barrels a day range, which is exactly where we would expect them and they are doing very nicely.

So we will be holding firm on selling assets that we will sell them until we get the price that we think they are worth. That said, we are continuing to market them actively and will pull the trigger if we think the right buyer comes along, who’s willing to pay something that we think they deserve.

The Comanche water system, that’s a small deal. I wouldn’t expect anything in the next year or so on that, until we really figure out a long-term development plan for Comanche. It involves doing a structure with all of our partners, and I’ve said this before, net to SN, it’s probably worth $20 million or $30 million, so it’s not huge enough and certainly not our focal point at this stage.

Jordan Levy

Great. Thanks so much, guys.

Tony Sanchez

Thank you.

Operator

Our next question comes from Sean Sneeden of Guggenheim. Please go ahead.

Sean Sneeden

Hi. Thanks for taking the questions. Tony, maybe just on the North Central results there. It seems like a positive development across the board. Can you just talk a little bit more about, how we should think about that part of Catarina? And how do you think about, I guess, the potential for that as you kind of move forward and what roles are playing in the development plan?

Tony Sanchez

Yes, okay. Let me get – let me pull some data here for a second, so just hang tight and I’ll address that. Okay, so we brought 19 wells online in the North Central area. One positive surprise there is that they are producing more oil than we had expected. Their gas-oil ratios are a lot lower. So on a BOE per day basis, they’re going to be lower because of the less gas contribution. But these wells, we’ve now – we initially type curve them off of a broader Central and Western step-out profile.

And I think, what we found is that we’ve transitioned in the earlier section here. We are economic. We will continue to drill more. I think we’ve done enough production history on these 19 wells now, to determine that it is a new development area. And granted, as I’ve mentioned before on a BOE basis, they show lower, but that’s because the oil rates are good and the gas rates are lower. The economics and revenue is still very positive. So yes, there will be parts – it will be a part of our continued development plan and we are very happy with the results so far.

Sean Sneeden

Got it. And maybe I missed it, but was there – did you have a kind of a sense of what – like an IP 30 or at least your kind of oil customers we should think about versus that can advertise North Central area?

Tony Sanchez

Yes. Let me just look at this sheet. Yes, Page 16 of our latest corporate plan shows these North Central’s their IP’s of 450 barrels a day and 2 million cubic feet of gas. I will say, the oil rates around there, depending on how we produce them we could get higher rates. The gas rates are a little bit lower, instead of $2 million, it might be $1 million. So on this particular type curve, which is based on $55 oil, we’re looking at IRR’s of 56% and PD’s per well of about $4 million, which is very positive.

Now, oil prices are higher. These are probably produced more oil than this type curve shows and less gas. So I’d still – there is a – whether it 56% or 60% or 45%, I don’t know what the IRR’s are ultimately going to be. I think it is too soon to tell. But they’re definitely well into the positive range and above our cost of capital. And we expect them to continue to be part of the development plan. So I just guide you to this particular slide here. We’ll update the slide as we get more production data, but there is – we do have a lot of positive well results in this particular area. So I’d expected to continue to be central and core to our development plans.

Sean Sneeden

Got it. I appreciate that. And then just on your CapEx plans going forward, has your thinking around your spending changed at all? And I guess, if so, what you think that ultimately means for cash flow profile? I know, I think previously, it was kind of targeting end of 2019 to be kind of hopefully around neutral.

Tony Sanchez

Yes, look, I think 2018, our CapEx is going to be over, as we’ve said, and we’ve moved it up, based on a variety of contributing factors to that. The first part of this year, our working interest at Comanche were higher as we were doing some of this testing between us and our partners. We were doing some delineation step-out testing, that in some cases, we took some non-consented working interest and increased our working interest. So that led to probably $25 million to $35 million added capital in the first half of this year, that’s a onetime item, we are not going to be doing going forward.

So I’m kind of laying out 2019, the way I see it shaping up vis-a-vis 2018. The other big change in 2018 from our initial budget to current is that some of the test, many of the test at Comanche have involved significantly longer laterals and enhanced upside completions that are more expensive. Some of those, we’ve tested and we don’t think we are getting the uplift in production to justify the added cost. So we’ll be backing off of those. So what is a overspend in 2018, as you look at 2019, I would fully expect that to come down – if I had to guess right now, somewhere on the order of about $50 million.

For 2019, I would slide in a preliminary capital budget, probably on the order of about $500 million, which is bring down from where the actual for 2018 will likely end up. But I think that 2019 will be just much more level-loaded. And we’ll be just doing what we now know works at Catarina and following a more stable production plan at Comanche that does not involve adding non-consented working interest and testing big long laterals with enhanced completions. If those of work, we will do them. But at this point, some of the well results that we’ve seen do not justify the added capital, so we will be pulling back in those cases at Comanche. So I think it’s safe to say we will target $500 million. Maybe there’s a good chance we could save $10 million to $20 million off of that for 2019, but it’s still too early to tell, but that would be the zip code of the capital plan going forward for next year.

Sean Sneeden

Okay, now I appreciate that. I think that makes sense. And just the last one for me. Just on, I guess, on UnSub, I know the initial plan, it was to generate free cash flow at the kind of UnSub level off the Comanche production. Is – I think the paydown on the RBL’s is probably been a little bit slower than expected. Is the expectation that once you kind of get Comanche to stabilize, you start to accelerate the paydown there or how you guys thinking about the plan for UnSub?

Tony Sanchez

Yes, that’s exactly right. As Comanche’s production, it’s a reminder for the rest of the callers. UnSub holds Comanche PDP – the Comanche PDP we had – we picked up at purchase date plus 40% of the development. And so that development early on, that entity took up more capital as we took the bigger completion jobs in the added working interest, it took its share. And so therefore, we haven’t been able to pay of the revolver at the same pace as initially modeled. But I would expect that to be back pay soon.

As we continue there, yes, we’ll continue to paydown the revolver at UnSub with an eye towards consolidation over the next couple of years. If the opportunity presents itself to consolidate UnSub, sooner rather than later, that is something we would act on and we are looking at various alternatives currently. So it is our objective. I want to be very clear. It is our objective to consolidate UnSub and to bring that asset base into the broader collateral pool for the benefit of all of our stakeholders.

Sean Sneeden

I appreciate that. Thank you very much.

Operator

Our next question comes from Andrew Griffith of Southpaw Asset Management. Please go ahead.

Andrew Griffith

Hey guys, appreciate you’re taking the call. I just wanted to ask a quick question on the location count. If I look at your most recent presentation, you’re still advertising 4200 locations, given the spacing, potential spacing issues, the Upper Eagle Ford issues and the discrepancy in the lateral length, have you revisited that? Or should we still think about that location count, just any updated thoughts there?

Tony Sanchez

Yes. I think that it’s certainly preliminary to give an updated 3P location count. Those locations are all there. I’ll go back to Eastern Catarina, for instance, where we drilled wells two years ago that didn’t have high IPs, but they had good oil production. The 3P count, I wouldn’t say has changed. Okay, that 3P count that you get from us, and virtually from all companies, is indifferent to oil prices.

And so there will be oil prices at which even the Upper Eagle Ford wells that we are talking about that don’t work today, do work. So that – what you’re talking about the 4000 wells, those wells – those sticks on the map do exist. Some of them work really nicely today, some of them need $65 or $70-oil, so we are close to it, and others needs $80-oil, some of them work at $45-oil.

So I just want to be clear with that, that well count is something we put out once a year. It’s really indifferent to oil prices. Those are sticks on a map, eventually it will get drilled, but that is not our focal point for the next two years to five years of our development cycle. We will be having some updates and we are very comfortable that at our current development price – pace based on differing price environments that 4000 still holds.

Andrew Griffith

Got, it. Thank you.

Tony Sanchez

Yes.

Operator

Our next question comes from John Evans of SG Capital. Please go ahead.

John Evans

My question has been answered on UnSub. Thanks so much.

Operator

Okay, great, thank you. Our next question comes from Robert Ellenbogen of Credit Suisse. Please go ahead.

Robert Ellenbogen

Hi, good morning. Are you able to disclose or do you plan to disclose the operational adviser, anything more about them or their specific areas of focus? Is it a national general consulting firm? Or someone with petroleum engineers on staff?

Tony Sanchez

It’s both. I can’t disclose the name right now. But it is a – it’s an international large firm that has a specialty practice in oil and gas as well as process improvement. So as I mentioned earlier, we are looking at everything. But the focus is operations with an eye towards getting back on our production growth profile, in that case. And we have 0.5 million acres that we are developing. So this position sure can develop – can deliver a lot of production growth. So we just need to kind of get past some of the issues the process type issues that we run into.

So this is a large national and an international consulting firm. I can’t disclose the name right now. They do a lot of work for the oil and gas companies. They do have petroleum engineer on staff, but it is not a boutique engineering firm that we’ve said bringing in – coming in support our activities. This was more taking a bottoms-up approach to where can we unlock value.

And I can’t disclose any numbers right now, because they are very preliminary. But there is some tangible, significant tangible, uplift, in production, cash flows, better LOE, enhanced margins, EBITDA per BOE margins that we and they think we can capture. So it basically help us identify that and then enact practices of improvement, large and small. So I’ll give you one example. Gas lift conversions, we were – this wasn’t a new idea, it was the different timing and putting the proper process in place to accelerate gas lift conversions, which is why in the second quarter.

We saw an uptick in LOE, because workover rigs are moving in and accelerating some of those quick-and-easy wins. So that we can get marginal uplift in production, and at a minimum get some stabilization in the decline rates that you normally see. So in that particular example, what was a more drawnout plan, I would say, for gas lift conversions, it was accelerated because we are able to quickly quantify what the benefit was, so little to no – little capital.

And just do it now. And so as we sort of revisit and I don’t want to say overhaul, because that’s too strong of a word right now, but revisit our operational practices, looking for ways to enhance and optimize as what we are focused on. And we’ve been very happy with this practice. Our broader employee base, I think, has been very accepting and enthusiastically participating on. And so I think across the company, we see the added benefit of taking this step. Really that was – that really came to fruition because a few months ago, I felt like we were playing whack-a-mole on some of these just normal operating problems and we needed to fix our processors, in order to properly address them.

Robert Ellenbogen

Got it. Thank you very much. That’s it from me.

Operator

Our next question comes from Owen Douglas of Baird. Please go ahead.

Owen Douglas

Hi, good morning guys. Thanks for taking the questions and providing some pretty open ended answers here. Got a – hopefully, sort of a quick one. Just in terms of a I know that you guys are taking a step back, taking a look at the operations, but just on the financial side of things, you have kind of just a cash balance, which has moved down a little bit. At the same time, you also happen to have the 7.75% senior unsecured notes coming due in 2020, which I think you kind of have to deal with about a year earlier.

Can you help me understand, just in terms of timing, when do you think you will be able to get this company to a point where it’s either actually free cash flow positive or breakeven? Or in a position to address the maturity of those 7.75% notes due 2021?

Tony Sanchez

Well. On the first part of your question is exactly what we are doing right now. Our focus – I’m going to answer this in two parts. Our focus here, barring any asset sales, is to get to free cash flow positive as quickly as possible. So part of the exercise we are undergoing right here with the consulting company I’ve been talking about is how do we – is putting a plan in place to get to cash flow positive as soon as possible and making sure that we have funds and liquidity to do so. So there’s a pretty good plan taking place already and then basically, what it does is it gets our production rates back to where they should be.

And so I think that’s exactly what the focal point is. At the same time, we are, as I have mentioned earlier, we are engaging in multiple processes to sell non-core assets and to rise capital to potentially either take that capital and consolidate UnSub or take that capital and paydown the 2021 bonds or a large portion of the 2021 bonds. So if we were to sell and bring in a good amount of cash, the first probable place that we would put that cash would be to refinance or to buy in and paydown the 2021 bonds.

So that would be – that’s kind of our approach and as I’d largely describe that approach its – we are focused on everything from improved operations to asset sales and debt paydown, all at the same time. And we are undergoing the processes that we’ve talked about publicly at Maverick and Palmetto and when we get a good number, those are non-core assets for us right now. If we get a good number, we will sell it, if we don’t get a good number, we are not going to sell. That has not changed.

And furthermore, we’ve even entertained a couple propositions to sell minority interest at Catarina. That asset has been doing tremendously well. And if that were to come to fruition, we will take some of that capital and delever with it. So – but we are open to any and all balance sheet solutions here, which I think we’ve got a lot of tools to work with here that include a combination of all things I’ve just mentioned. But we want to be very proactive in this.

We are not waiting around until 2020, we are doing it. And I think that in the renewed interest in the Eagle Ford, there’s a lot of interest in good quality-producing assets. And this basin having a lot more running room and having more interest than it did last year and not really being burden with some of the takeaway issues that that other basins are burdened with. So a lot of attractive things about the Eagle Ford, I think, we can capitalize on now.

Owen Douglas

Okay, that was helpful. And just to be clear on this, you mentioned, it sounded like part of the view is that you need to kind of grow production. What is that level which you think is necessarily to achieve free cash flow positive?

Tony Sanchez

Well, it depends on capital. So I think that we’re probably – in terms of production growth and we looked at this ad nauseam. There is not just one answer, there’s not one answer and don’t read between the lines here, I can’t tell you, okay, 90,000 is cash flow breakeven, because that is dependent on a variety of other factors like CapEx, drilling pace, what does inventory look like? What are we going to do the following years? Where is it going to grow from there?

So it’s not an exact number. But I would target, just from a very high level, I would say, our production targets for our two-year plan from where we stand today and probably one-year plan, involves growing production somewhere on the order of 10% to 20% from where it is now.

Owen Douglas

Okay, that’s helpful. That puts you right around that 90,000 [ph] MBoe per day number. Okay, great. Well thank you very much appreciate the time.

Tony Sanchez

Yes.

Operator

Our next question comes from Vivek Pal of Seaport. Please go ahead.

Vivek Pal

Hi, thanks for taking my questions. First, Tony, how is the consultant being compensated? Is it straight-hard dollars? Or is it percentage of proceeds, and will it show in CapEx, G&A? How do we kind of look at it from a number’s perspective? Or it’s not even big enough?

Tony Sanchez

Right now it hasn’t been big enough. The way this is currently structured is, it initiates, for the first several months just as a straight consulting traditional-type arrangement to pay a monthly bill. The actual enacting of it, we could do one of many different ways, including a success fee. And that success fee being predicated on achievement of a variety of initiatives, all of them value uplifting and all of them reoccurring. So that has not yet been determined yet.

We’re in the process of having those discussions. I will say that the price here is very substantial. It would be transformational for the company and it is things that I we’re all very excited on. So I don’t have an exact number for you just, simply because it hasn’t been determined yet. Currently speaking, it’s a traditional add-to-G&A, it’s a onetime item that would pay a bill once a month.

Vivek Pal

Okay. And Tony, in terms of your relationship with Blackstone and GSO, given the challenges at Comanche, is there any updates? Or this is business and it happens? Or is there any kind of a talk of – even with GSO say, go back to paying time and get some cash-free to either paying CapEx or to pay down the secured debt to the UnSub. And if you could also provide some specifics in terms of how much secured debt you paid down at the UnSub level this quarter? And if that’s sustainable?

Tony Sanchez

Yes. So for the second part of your question, we’ve paid probably a few million dollars down, $4 million down this quarter. We would have expected to pay, I don’t know, $8 million to $12 million down this quarter, but because of the lower production and the higher CapEx, that capital was used for that. Now, I don’t expect that to be the case. I expect us to resume revolver pay-downs at UnSub. Remember, UnSub right now is generating $150 million or so of EBITDA, and the secured debt level of EBITDA is at like $180 million or something.

So we’re basically onetimes levered at $167 million at UnSub. Sorry, I’ll correct that. So it’s under-levered as an entity. We will continue to pay it down, while we have discussions with GSO about what to do, if anything, but the objective, I think we’re both on the same page. We both want to consolidate UnSub sooner rather than later, because we think it’s better for the overall balance sheet and the strength of the company.

But I think they would agree with having a strong operator manage the entity. In terms of Blackstone, on the private equity side, that’s a separate relationship, but there is no real update there per se. They continue to hold their working interest in the same entity and we have much the same, I guess, overall objectives as revolvers had. So I’m not sure if there is another question vis-a-vis our relationship with UnSub, but it really hasn’t changed.

Vivek Pal

The last question from my side. In terms of, when you say, liquidity, the cash component I understand, on the bank lines, a bulk of it is on the UnSub level. Is it realistic to assume that as true liquidity in the event that this thing takes a little longer and you don’t want to deplete your cash, because you want to be prepared for 2019. And you say, all right, we’re not going to pay down the UnSub, but actually take down more secured debt that is available to you at the UnSub level. And then eventually kind of revisit the whole thing, is that true liquidity, is my question?

Tony Sanchez

Yes, it is, the drawn balance on the UnSub revolver is currently $167 million, and the revolver amount available is $375 million, is that correct? $380 million. So we have over $200 million of undrawn capacity at UnSub. Now we can’t currently pull $200 million we can’t draw $200 million on that revolver and move it up to the restricted group.

But there are ways, I think, that we could come up with and we don’t have the optimal answer quite yet. But when I think about liquidity on a consolidated basis, I do count the $200 million of unused capacity at UnSub as available liquidity in some form or fashion. We’re not in a position right now to be specific about how that would be overall made open, but when I keep talking about consolidating UnSub sooner rather than later, it would be with one of the goals being to unlock that liquidity for the benefit of the consolidated group as well as make the assets available that are currently underpinning net RBL available to the whole broader secured and unsecured credit group at…

Vivek Pal

So you can take – I’m sorry, so you can take the $200 million and move it upstream, I understand that. But can you use that to fund Comanche’s CapEx?

Tony Sanchez

We can use it to find UnSub’s shares of Comanche’s CapEx.

Vivek Pal

Okay, got it. That’s what I meant, so that’s available for that. And roughly what percent of CapEx is that, right now, give or take.

Tony Sanchez

Yes, so it’s 40% of SN’s overall Comanche CapEx goes to UnSub. So 40% of every well that we drill, net to our share. So we have 25% of a well at Comanche, 40% of that 25% gets funded out of UnSub. Now, yes, we can use that UnSub revolver capacity to fund that, but we don’t need it, because it’s already – it’s basically self funding. It’s generating excess cash. That excess cash is paying the dividend on the GSO pref and paying a little bit down on the revolver. So yes, it’s there, but we haven’t needed it.

Vivek Pal

Right, okay all right thank you very much Tony.

Tony Sanchez

You’re welcome.

Operator

Our next question comes from Jay Spencer of Stifel. Please go ahead.

Jay Spencer

Thanks for taking my questions. A lot of my questions has already been asked and answered. But just to kind of follow-up on some of the most recent question. I’m trying to get a handle on the cash flows between the restricted group and UnSub. So your cash balance went down from $550 million at the end of the first quarter to $438 million at the end of the second quarter. Is all of that cash burn at the restricted group or some of it down at UnSub? And was any of the cash distributed from the restricted group down to UnSub? Thanks.

Tony Sanchez

So, on the second part of your question, the answer is no. We’re not taking any cash from the restricted group and sending it to UnSub. That kind of ties into Vivek’s previous question, which is it doesn’t need cash. The numbers that you see are consolidated, most of that cash sits up top. Some of that cash is working capital cash that we use. We handle and market and JIB all of our partners.

So at Comanche, we are 25% working interest. So we see cash coming in for all of our partners the second half of the month and then we distribute out revenue and royalty checks and make vendor payments the first part of the months. So there are some ebbs and flows in those cash balances. That’s the numbers that you are seeing. It is consolidated and we don’t break out how much sits at UnSub versus at the restricted group. But by and large, all of that is at the restricted group, with the exception of maybe a little bit. And Howard…

Howard Thill

It’s Howard. To echo what Tony saying, I mentioned this on the last quarter and I can mention every quarter, I wouldn’t look at the cash balance at the end of the first quarter, minus the cash balance at the end of the second quarter and call that cash burn because at the end of the first quarter, we had a number of – to Tony’s point, a number of payables that we’re – it was just the timing of the quarter, when sales, how the payments fell for invoices and receipts revenue runs. So you really have to look at it over a longer stretch of time and just on a month-to-month, quarter-to-quarter basis, as part of what that cash burn looks like and to go back and look at the cash flow statement to pull those items out, working capital et cetera. So we do keep a close watch on that and we can also depend on the timing of interest payments and whether they fall on, like this quarter, the last day of the quarter was on a Friday and the interest payments fell on a weekend. So there is a lot of variability in those cash balances of being just at the last day of the quarter.

Jay Spencer

Got it. Okay, that helps a lot. So it sounds like, correct me if I’m wrong, UnSub is still chugging along, it’s paying down debt, albeit, just at a really small phase in the second quarter, which you guys expect to pickup going forward?

Tony Sanchez

Correct.

Jay Spencer

Okay, that’s all I have. Thanks.

Operator

Our next question comes from Jacob Gomolinski-Ekel of Morgan Stanley. Please go ahead.

Jacob Gomolinski-Ekel

Hey, good afternoon. Thanks for squeezing me in here. You mentioned, you’re looking toward consolidation over the couple of years and now you’re looking at various alternatives to consolidate sooner rather than later. Can you expand on what some of those alternatives might include?

Tony Sanchez

Yes. I mean, I’m not going to expand on specific alternatives. I will say that they range from selling an asset down and paying depending on what we sell paying part of the 2021 and then using some of that capital to effect that consolidation of UnSub up sooner than it was originally expected. So if you look at the GSO Pref in terms of cost-to-capital. On the company’s capital stack, irrespective of entities, it ranks among the highest, so it makes sense for us to pay it down ahead of time.

Again, predicated that depends on what we sell and for how much and how much of those sale proceeds we want to use for 2021 pay down. So I don’t think there’s been anything mentioned. So in conversation, that we aren’t looking at now, but I’m not going to get more specific in terms of what we are necessarily chasing from the structure standpoint to achieve just because we are – it’s very premature to do so.

Jacob Gomolinski-Ekel

Okay. And then, just I’m not sure if you mention it, but did you have a sense for 2018 exit rate?

Tony Sanchez

No, that goes back to our guidance not being changed, not being raised lower or front. So it is what it is and we are keeping the same going for exit rate. I don’t think we’ve given exit rates in a while, anyway. We got away from that a year or two ago, just because it tends to manipulate numbers.

Jacob Gomolinski-Ekel

Okay. Fair enough. That’s it for me. Thank you very much.

Operator

Our next question comes from Joshua Gale of Nomura Securities. Please go ahead.

Joshua Gale

Hey, good morning, sorry, good afternoon now. I was hoping. You could highlight some of the primary assumptions behind the 4,200 location count. I know your previous caller had sort of touched on this a bit, and fully understanding that it’s a 3P location count. And just wondering if you could share some of that basic assumption behind lateral length, spacing and number of zones? And the purpose of the question is really just to try to triangulate what I would call a high-graded location count and incorporating the fact that you’re drilling 8000 foot laterals, instead of 36,000 feet. So borrowing from your phrasing, there are sticks on the map, but maybe the sticks are changing how close you are together and how long they are?

So really just wanted to get a sense of with your current lateral length, maybe excluding the Upper Eagle Ford in areas that you’ll be deemphasizing going forward and to the extent that there were any spacing assumptions outside of the DUCs that you acquired, tighter than 600 feet in zone, why didn’t that back out?

Tony Sanchez

Yes, the assumptions, first is spacing assumptions I believe are at 600 feet, right? So that doesn’t really have an effect. We have been testing tighter than that, particularly in the DUCs and we’ve been testing marginally wider. But it doesn’t really are – I wouldn’t say, it has an overall effect. It might bump a couple of hundred locations off, if that’s 600, we are going to 700. I could tell you right now, we’re probably going to stick at 600 in some areas may be drilled at 700 in some areas. And perhaps, even end up at 550 feet or 500 feet in some areas a bit tighter. So it’s going to be around there and I expect there to be, in some areas, locations drop-off and then in other locations, be it locations added. So there is not much of a change right now. We are drilling wells anywhere from 6,000 foot laterals to 12,000 foot laterals in some areas to get stranded acreage and get those stranded reserves out of the ground. So on average, I think we are at 7,500 feet per well is the lateral length and as of now, it’s not necessary changing the number of locations. It is capturing resource that previously would’ve been stranded.

Joshua Gale

Got it, okay. Because I know you first started talking about drilling longer laterals last fall, and this is 4,200 location number first popped up in the January representation of this year. So it fair to say that some of the change to drill longer laterals is incorporated in that 3P location number?

Tony Sanchez

Yes. I just got a note past. The inventory is really calculated of laterals that were built around a range, 6,000 to 7,000 foot laterals is what goes into your inventory range, when we go drill longer laterals in that, they don’t have necessarily effect of replacing other wells. They capture stranded resource and in the areas where we are pursuing longer laterals, it’s a capital efficiency exercise, where we are able to maybe drop a well, but almost double the lateral length and get much better use of our capital. So you can’t think of it just in terms of – if we double a well length, we’re going to drop a lateral. No, you’re going to get the resources, you’re just getting it out of one well instead of two and you’re going to save money on surface facilities and the vertical section of the well.

Joshua Gale

Got it. Yes, I wasn’t suggesting that you lose the resource, but for modeling, PV-10 for location based on a longer lateral, I want to make sure if we sort of capture the right amount of resource. Okay, thank you.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Tony Sanchez for any closing remarks.

Tony Sanchez

Well, I would like – everybody, would like to thank everybody for joining us today and thank you for your extensive questions. They were all very good and constructive and I look forward to a better production results and speaking to everybody in next quarter. Thank you.

Operator

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.