Battalion Oil Corp (BATL) 2018 Q2 法說會逐字稿

Good day, everyone, and welcome to the Halcón Resources Second Quarter 2018 Earnings Call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mark Mize. Please go ahead, sir.

Good morning. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. We've also updated our investor presentation for second quarter activity and other operational items and you can access that presentation on our website.

I'll make few comments about our financial performance for the second quarter. And then I'll turn the call over to Jon Wright, who'll talk about operations and then Floyd will take the call to discuss guidance and strategy.

Production for the second quarter averaged 12,769 barrels of oil equivalent per day comprised of 68% oil. This production rate was approximately 500 Boe a day, less than we had projected due to some unexpected downtime that was caused by power interruptions as well as some weather-related issues.

Our realized second quarter oil differential of 90% of NYMEX was less than the 99% differential seen in the first quarter, which was really just driven by weaker Midland pricing. Our second quarter natural gas differential came in at 52% of NYMEX, which was lower than the first quarter of 2018, and that was driven by weaker Waha pricing.

Our NGL differential for the second quarter 39%, was more or less in line with the first quarter which was at 41%. Our LOE and workover expense was $7.3 million for the quarter or $6.25 per Boe versus $6.36 per Boe in the first quarter. And our second quarter LOE and workover per Boe would have been right at about $6 per Boe, if we wouldn't have experienced the unexpected downtime. We expect this rate to continue to trend down in the second quarter or the second half of 2018 as we continue to gain scale and ramp production.

Gathering and other expense as adjusted in the press release totaled $5.5 million for the quarter or $4.73 compared to $5.55 in the first quarter. This metric also was impacted by the unexpected downtime.

G&A expense as adjusted totaled $10.1 million for the quarter or $8.68 per Boe versus $11.35 in the first quarter. This per Boe rate will continue to come down over the remainder of 2018. Again, as we gain scale without any significant G&A additions expected.

With respect to current -- to the current quarter of capital spending, we incurred right out of $132 million in DMC, $29 million in infrastructure seismic and other, and $214 million on acquisitions. The majority of that was the West Quito Draw acreage.

As far as hedging, we did realize the net gain on several derivative contracts of approximately $26 million during the second quarter. We're well hedged on WTI for the rest of 2018 and 2019. We have 11,500 barrels a day of oil hedged at an average price of $53.03 per barrel for the last 6 months of 2018. And we have 15,504 barrels per day of oil hedged in 2019 at an average price of $56.27. We also have 8,000 barrels a day of MidCush basis swaps in place for the remainder of '18 at an average price of $11.69. We have 12,000 a day of MidCush swaps in place for the first half of 2019 at $3.02 and we have 4,000 barrels a day in place for the second half of 2019 at $3.95.

Regarding gas hedges, we have 7,500 MMBtu of gas hedged for the last 6 months of 2018 at an average price of $3.16. We have 20,000 MMBtu a day of gas hedged in 2019 at an average price of $2.80. We also have 15,000 MMBtu a day of Waha basis hedges in place for the second half of 2018 at $1.10, and 25,500 a day of Waha basis hedges in place for 2019 at $1.18.

As of June 30, the end of the quarter, we had $294 million of liquidity. That did consist of $96 million of cash on the balance sheet plus a fully undrawn revolver.

And with that, I'll turn the call over to Jon.

Thanks, Mark. As Mark indicated, we had quite a bit of unexpected downtime in the second quarter driven by power interruptions and bad weather. Although we can't control the weather, we do have the ability to improve the power situation. We have worked with our local utility provider to have a new substation constructed within our acreage position, which will improve power reliability.

We recently connected roughly half of the Hackberry Draw field to the substation via our new feeder line. And we anticipate that we'll have the remaining wells connected within next few weeks on our second feeder line.

Additionally, we will continue to build up our HFS-owned power transmission infrastructure throughout the field to ensure that all of our well sites are connected to the grid making us less reliant on generators for power.

In Monument Draw, we continue be very happy with our drilling results. The Sealy Ranch 6401H, again, cutting oil in late June, and has exhibited very strong results for the current 20-day average of 1,885 Boe per day at 86% oil, which continues to improve. This well may reach a 30-day peak IP rate of around 2,000 barrels equivalent per day, making it our best well drilled to date in the Delaware.

The 6401H is located in the central portion of our Monument Draw acreage position. We recently began flowing back the Sealy Ranch 7701H and the 7702H in Monument Draw. As of this morning, these wells are producing over 1,600 and 1,400 barrels equivalent per day, respectively, and their rates continue to increase. One note on this is that these are not peak rates. We expect the peak rates will be in line with other recently reported rates in Monument Draw. These 2 wells were completed in the lower and upper Wolfcamp intervals, at spacing of 330 feet apart horizontally and 250 feet apart vertically, wine rack positioning.

We ran Micro-Seismic on this project and we have confirmed that the frac was contained within each interval with little to no interference. These wells confirm our spacing assumptions that up to 13 upper and lower Wolfcamp wells for 1,280 acre drilling spacing unit in Monument Draw. There's a great illustration of that work on Slide 8 of our investor deck.

Now with 6 additional wells flowing back now or being put online over the next few months, we will have derisk most of Monument Draw for the Wolfcamp by year-end as shown on Slide 7. We also have improved our drilling performance in Monument Draw recently by modifying our drilling fluid program and implementing new bit designs in intermediate section, which has resulted in reduced drilling days. I will also note that we have 8 locations in Monument Draw with intermediate casing preset. We will have a great head start once we move back into this area in 2019. This is about a $14 million impact to CapEx.

We expect to continue to improve our drilling performance here and in our other areas. We put 3 Wolfcamp wells online in Hackberry Draw in the second quarter of 2018. The most recent of these wells, the Bobby 1H, is outperforming our type curve. The other 2 wells were drilled further south in our acreage position, and while they're performing slightly below type curve estimates they're still economic. We expect to put 5 additional wells online here for the remainder of 2018. And all of these wells are focused on areas where we expect to meet or exceed type curve expectations.

In West Quito, we've recently began our drilling program with 2 rigs on a 2-well pad and a 3-well pad. These 5 wells are all 10,000-foot Wolfcamp laterals. The first pad should be online in Q4, while we anticipate the second pad will be online around the year-end 2018. These 2 pads are illustrated on Slide 9 of our investor deck.

Our drilling performance thus far has been on track, with the total drilling days looking to be around 30 days. Accordingly, we will have adjusted -- accordingly, we have adjusted our DMC cost in West Quito downward to around $10.6 million versus $11.5 million as previously reported.

We're excited about this area and look forward to talking about well results here later in 2018.

With that, I'll turn the call over to Floyd.

Thanks, Jon. Jon and his staff are doing a wonderful job of building a world-class asset out here based on technology and cutting-edge practices. We don't hire the low-cost providers, we hire the best providers in any area that we work in. As to rigs and growth. As reported, we dropped a rig a while back bringing our rig count to 3 rigs for the rest of the year and for at least the first part of next year. This moderation in cadence is driven by the basic -- the basis blowout with that differential standing above $15 a barrel today. Not exactly the right time to press for higher and higher production.

I'd like to see realized net prices back over $60 a barrel before I add a rig back in; time will tell on that. Having said that we've dropped a rig and lowered production, we're still guiding to a 33% production growth rate Q4 over Q3 of '18. And that becomes more than a 300% production increase year-over-year, '17 to '18. These are very strong wells that we're drilling out here.

We're running 1 dedicated frac crew today and we'll bring in a spot crew as needed. We -- as I mentioned, we continue to use only the best contractors, the best service providers and the high-end of all equipment as we build our 60,000-acre, 2,000-location position in the Delaware into a durable, profitable type asset base. We have lowered production guidance due to the 1 rig -- our rig count reduction. But as I mentioned, we'll deliver strong growth in spite of that.

We hope to add a rig in '19. Again, as I mentioned, and that is dependent on crude netback pricing. If we do that, that will allow us to continue growth to about 30,000 barrels a day average for the next year. Again, a very strong data point.

On that basin logjam, we have announced an executed comprehensive takeaway agreement with Salt Creek Midstream. A great partner for us in the Delaware Basin. Our agreements with them lead to a 25,000 barrels of oil per day, firm capacity on new construction taking our oil to the Gulf coast at some point in 2019. This will lead to better-than-WTI net prices after transport.

On cost, inflation seems to have moderated a bit. It's hard to pick a day, a point in time and say it's done, but it has definitely slow down, maybe even flattened. Drilling, the completion CapEx is now approximately $400 million for 2018, down about $35 million from before we dropped a rig.

Infrastructure and seismic spending will be about $20 million or a bit more higher than before at approximately $100 million. This is driven primarily due to additional costs related to building out a high-spec gathering and treating system at Monument Draw, where we are seeing elevated levels of H2S.

Hawk Field Services remains a large focus of ours. It's a very vibrant and valuable asset. The additional build-out is -- part of this additional build-out to deal with the issues at Monument Draw as part of Hawk Field Services. And we'll provide an even more highly valuable asset encompassed within our subsidiary. We reported the launch of a process to sell at least half of this awesome asset, Hawk Field Services. We've received a very high level of interest from both strategic and financial parties. I expect to have nearly 40 CAs executed soon as we go down a path that we have gone down before successfully.

We expect the marketing process to be complete within a month or a month and a half, and a closing within a month or a month and a half after that. We're open to both a partial sale or an outright sale of this valuable asset. Any proceeds from this divestiture will enhance our liquidity as we move towards cash flow sufficiency.

We have several additional liquidity and leverage-enhancing projects under consideration at this time. We are not pursuing any significant acquisition ideas today. And as far as strategy, it's really pretty simple. Great rock, great execution will lead to a great end result for all of our investors.

Operator, we're ready for questions, if there are any.

(Operator Instructions) And we'll go first to Jeffrey Campbell with Tuohy Brothers.

I thought that Slide 11 was interesting. I was looking at your economic comparisons of the 5,000 and 10,000-foot laterals. And it appears to show 1:1 production ratio between the lateral links. In other words, the production is doubling when you're doubling the length of the lateral. So I was just wondering is that consistently which

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in your current well performance?

I believe what you're looking at there, it shows that during the first 5 years, it's not exactly linear. You don't expect to 100% just double based on lateral length 5 versus 10. But certainly, the early days, it's very dramatic increase.

Well, and the early years are the ones that count, so that's good. I also thought I would ask you, Slide 16 has a -- I know this is pretty forward-looking but I just thought I'd ask. Slide 16 has a nice description of derisked zones and others that look -- that would be appraisal zones. First, I was wondering, as you think about your development cycle, when do you think would be perhaps the year when you would do a first speculative zone test? And second, I'm sure you're watching all the activity

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base. And so based on what you see with peers, is there a

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particular zones that seem to be pretty promising and might be the first one you would go after?

Well, we've done a couple of Bone Spring tests. We've done some upper Wolfcamp and lower Wolfcamp tests. In the basin, I think you'd be hard pressed to call any of these speculative. The possibilities are a little bit different in different parts of the basin. But certainly, a couple of zones in the Bone Springs -- in the Bone Spring, additional Wolfcamp zones. But probably more importantly, about the economics of this spacing test that Jon mentioned, if we find that we can drill wells in this chevron or wine rack pattern, they're only a few hundred feet apart, but still maintain the integrity of our frac jobs. That meaning keeping the frac jobs really tight to the drilled well bore. That adds much more value than anything we could do with finding some wildcat zone. We do have plans. We're not going to do it this year, likely. But we have plans to drill deeper tests at both Monument Draw and Hackberry. And we also plan to drill deeper into the Wolfcamp, I think we, just for simplicity, call it Wolfcamp C, at some point in the future up at West Quito. So there's a lot of ammunition out here for continued growth. But with 60,000 acres and a couple of thousand locations now, I mean, how many do we want to count. We could count a lot more.

Right. And that sort of reinforces the notion that you don't make any more acquisitions at this time.

And we'll go next to [Tariq Hamid] with JP Morgan.

You talked a little bit about the deal with Salt Creek. And just what kind of color you can give us on how to think about the sort of the cost of some of that long haul takeaway. Any color would be appreciated.

Well, we're probably not at liberty to say, put some exact numbers on that. It's a competitive situation out there for our partner. I will say that the transport costs are basically pretty nominal given the logjam. I don't know if we've given out any modeling advice on that or -- Quentin, maybe you have something to say?

I would say, if you look at the forward strip of Houston or LOS or (inaudible) Houston pricing in late '19 or early '20 when we expect to get on that pipe. Around that pipe, it's a $3 or $4 premium to WTI. We expect that realized net of our transport cost of premium to WTI accounted for that premium that you're seeing in the market. So I would tell you our fee is rather nominal, as Floyd indicated.

Got it. That's really helpful. And then you wrote in the release that you have the ability to increase the capacity on it each year annually. Can you maybe just talk a little bit about sort of how high that could go and sort of what the mechanism would be?

I'll ask either Anthony or Quentin to address that. But we found in every shale play that we've been involved in, which has been pretty much every one of them in the United States, that these logjams occur. They endure for a year or more and then they move. And so I think that you don't ever want to have all of your product going in one spot. So we intend to keep our options open for some of our crude to be sold in the basin in the future, and with the vast majority of it going to the coast. I think Steve's on the phone. Steve, you got anything to add to that?

No. No, Floyd. I think that sums it up. The flexibility is key as you say in every -- how these things move around over time. And so we wanted to make sure that we weren't in a position where 2 or 3 or 4 years from now, we'd be staffed somewhere that might not be as attractive then as it might be a year from now. And we've built in (inaudible) in the agreement to (inaudible) our capacity on the line over time

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production, if we choose to.

Steve, I believe that written in part of that agreement is about 50% increase in the -- under the existing agreement.

Yes, I believe that's about right. Over time, that's right. And we have ability to change it each year once we get going.

Got it. That's helpful. And just last one for me. You made a brief comment in the slides about completion cost. But (inaudible) a little bit about what you're seeing on sand with some (inaudible) as well as pressure pump increase?

Jon?

With regard to sand, really, we're starting to see a lot of in-basin sand coming online. It's primarily in that 100 mesh. I will say that we are using in-basin sand for the 100 mesh. As far as pumping crews, we see some softening in the market there. Some availability to pick up a spot crew when needed. So I think we're pretty set from that perspective.

And next we'll go to Jason Wangler with Imperial Capital.

On the infrastructure (inaudible) , can you maybe talk about, would you parse those areas up? Or just kind of the different ways you're looking at simply just looking to monetize an interest in the asset.

So as contemplated today, the potential sale of this is across the basin to include every aspect of infrastructure, be it water, gas, oil, blending, treating, compression, disposal, everything, power. It would be our initial intention to sell off about half of that business. And on a go-forward basis, that party will be our partner in the growth of that business. I don't know if that's what you're looking for there, Jason.

No, that's helpful. And then, just as we think about beyond just 2018, the rig program, whether it's 3 or if you'd go to 4. Do you have a sense of kind of where you'd focus those? Obviously, you've had some really good results in Monument and we'll see about West Quito but it's a great location. Just how you think about where those rigs are kind of going to float around as we think longer term.

Well, it probably doesn't come through very well in our presentation or our discussion. We are -- in all new areas, you work pretty hard to define your best area within each of your holding areas. And so we have 3 main ones here. We've actually defined some really good rock down at Hackberry Draw. We'll continue drilling down there. And we've had a few areas where the results are a little less attractive. We won't drill in those areas at Hackberry. But the largest part of our acreage down there, we've had some really interesting results. And with this moderation in inflation, we think that we can -- that there some upside in price and our cost down there. So we're not going to discontinue that by any means. I wouldn't say it would be an even third, third, third going forward. That just changes over time. As we move to 100% pad drilling, your rig or your well count is driven by pads.

So if we can get ourselves into position of drilling more multi-well pads, you're longer in one area than you might have been just drilling singles. So you might find yourself, one year, drilling more wells than you might have thought at Hackberry or more at Monument Draw just because of the pad drilling situation. Generally speaking, I'm going to guess, it's going to be about 25% at Hackberry and the rest, kind of, evenly split between Monument Draw and West Quito. But again, we just brought on a couple of great wells down at Hackberry. We see no reason to deemphasize that, except in just the bald nature of the rate of return of a well that's going to make $2 million Boe compared to a well that's going to make $1.25 million Boe or whatever.

Our next question comes from Mike Kelly with Seaport Global.

Floyd, I was hoping maybe you could expand upon your thoughts for 2019. You mentioned you'd like to get a rig active earlier in the year. But you also said that you'd like to see $60 to make it happen. Just like a little more thoughts on that. And then maybe if you guys do have a decent base case, maybe a 3-rig scenario and what that could look like for the capital spend for next year. And what's a decent number on running 3 rigs?

Yes. The $60 that I referenced would be kind of a net back price after differential things have softened or evened out. So we don't know when that might happen. If you're running 3 rigs in 2019, you'd look to spend a bit more than $300 million, maybe $325 million or so and maybe give yourself a spread around that of, say, $300 million, $350 million. If you brought a rig in part way through the year, that would increase about $50 million. So if it was 3.5 rigs, it'd be about $350 million to $400 million, something like that.

Okay, that's great. You don't want to take a stab at potential growth there on the 3- or 3.5-rig program?

Well, of course, I did mention that we would expect under our current -- our current expectations will lead us to think that we'd be average about 30 for the year. And if it was fewer rigs it would be about 10% less or 10% or 11% less than that. I mean, those are [stabs] by the way. As we've seen, we need to pursue the appropriate development of these assets. And you can't do that if you have a lot of uncertainty on commodity pricing. So right now 3 rigs would be about what I said and yield about $25 million to $30 million, 30,000 Boe per day. And 3.5 rigs it yield about another $3 million or $4 million net barrels per day on top of that.

4,000. 4,000.

Understood. Okay. And then one more for me. You mentioned in the press release there's several options to fund near-term -- the near-term outspend. You talked pretty extensively about the midstream component of that. But you also mentioned in the press release JVs and other options, and I was hoping if you could give maybe a little more context around those second 2.

Mike, we're super focused on leveraging liquidity as always. We've got a tight plan. We're good to go at this moment. But if we -- anything we can do to enhance that, I think might relieve some of the market concerns that we hear. So if you think about a company our size, basically a startup, we started a -- bought our first property last year in March out here. Sold everything else. Only 60,000 acres, several thousand -- couple of thousand locations or more. We can't drill that many no matter how many rigs. So a JV that involves selling off some of that acreage or selling off some of that drilling would be kind of an attractive way to sort of reduce our inventory without reducing our growth trajectory.

So there's several things that we're looking at along those lines. I don't want to highlight anything other than the current move to move forward with this Field Services partial sale. And that's a simple matter. We're trading at $1.30x EBITDA, and we can get 10x more than that for it, so we'll -- it's an asset that we shouldn't own all the time. It's pretty simple there. (inaudible) but we have several ideas. And these things are kind of running in parallel with everything else we do. In parallel meaning we're working really hard on the drilling by getting the drilling cost down, we're working really hard on the efficiency of the frac jobs. Working really hard on the infrastructure build up regardless of the sale because these wells will be producing for 50 or 100 years or whatever. These leases will, for sure. And you have to build a durable platform for that kind of activity. So we're focused on all of that. At the same time, quite focused on balance sheet and liquidity.

And next, we'll go to Ronald Mills with Johnson Rice.

Floyd, there were at least under the Salt (inaudible) also mentioned the building of some oil pipelines to get your volumes to link. Is that designed to get all of your oil volumes off a truck and in the pipeline and (inaudible) that have on the cost structure?

Well, I'd like Anthony or Steve to really address the details of that. But within a couple of months, we expect to be, essentially, off truck and in-pipe. Trucking is, gosh, 4x, 5x as much as the pipeline costs; about 5x as much. So that's a significant factor. It's also just a big factor. You get muddy, trucks breakdown, drivers don't show up, whatever. We're going to get all of the oils to link and from there, as soon as these other pipes open up, we'll get all of our oil out of the basin, all that we choose to. What else?

Yes. And also, Floyd, part of the deal includes a purchase option to move all the oil from link. So that improves your takeaway.

And that [solution] be operational for the -- at some point in the fourth quarter?

I think within 2 months as far as being off of trucks.

That's right, Ron. This is Steve. We expect the Monument Draw oil to be (inaudible) and that's of course the be the biggest share of the volume in Ward County by October and then the West Quito by December. And as Floyd and Anthony mentioned, of course, it helps us (inaudible), but also, particularly, Monument Draw where the volume would be ramping, it helps us a lot just on (inaudible) because as Floyd said, trucking, being as a less than perfect way to move that much product.

Okay, great. And Floyd, maybe just -- and maybe for Jon. If you think about strategy where you took the rig out of Monument Draw where you've seen some of your [better results] and took it down to Hackberry. How do you weigh that allocation? And when do you think about bringing a rig back to Monument? Is it trying to play the timing of when we're going to see increased capacity and improved Midland pricing?

Let me ask Jon to add to this. But we moved a rig back to Hackberry because we have several great locations to drill down there, simple, that the cost that we expect to experience are going to be reasonably competitive. At Monument, we kind of outran our coverage in terms of infrastructure. And we need to do some more work there. Having said that, we've had this process where we had intermediate rigs out there drilling down to the curve, I think to the curve is a fair way to say it. And I think Jon's got 5 or 10 of those already drilled. So he's got a -- maybe it was 8 exactly.

A good list of wells that are going to be frac-ed anyway. So we're not going to experience a big loss of production growth from Monument Draw. You've got limited ability to spend money, and you take those rigs where they should be in terms of the best investment, where they should be in terms of technical coverage. Sometimes you might be waiting on seismic. Sometimes you might be waiting on a marketing agreement or some pipe or some infrastructure. So Jon, what else would be there?

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No, Floyd, you'd mentioned earlier in the call about the installation of a gathering system for the wellhead for sour service application. So those are some of the things that we're working on over in Monument Draw. But as you mentioned, 8 wells that are set with intermediate casing. So that was a forward spend for us. We got a bit ahead of ourselves with that. And so that contributes to the capital spend in 2018, but will have a positive impact for '19. We're working on all fronts here. The results at Monument Draw have been great. I think certainly exceeded our expectations. We're working on the cost side as well. So there's 2 sides of that. We've been pumping some of our frac -- more recent fracs both in Hackberry Draw and Monument Draw. We've been pumping a smaller job, approximately 2,000 pounds per foot. And as indicated by the results, those frac show good initial rates. I mentioned that we're using in-basin 100 mesh sand. We'll have some considerations about how we progress with that as we move forward. We'll continue to focus on optimized clustered efficiency while increasing our stage link. So what the end result there is a lower cost. So we're making great wells. We're focused on lower cost through our completion efficiencies, drilling multi-well pads throughout the rest of 2018 and '19, which further adds efficiency to our operations and decreases cost. So those are the key points that we're really focused on, Ron.

Great. And then one last one on West Quito. Are your first 5 wells you're drilling, what zones are you targeting out at West Quito?

So those 5 wells are targeting the Wolfcamp, Upper Wolfcamp interval.

And our next question comes from David Beard with Coker & Palmer.

Most of my questions have been asked. So I just had a follow up on the Salt Creek (inaudible) Relative to timing. If it comes out in the fourth quarter, will you be able to move all your oil volume in that theoretically? Or is there some restrictions?

When the pipe, when it's available, we'll have our full allotment available to ship.

And next, we'll go to Vivek Pal with Seaport Global.

Could you give us a sense of timing and potential value of the midstream assets? Is $300 million realistic for the whole base?

Gee whiz, we wouldn't sell it for that, period. That's a crazy low number. Timing wise, you're looking at about a month or a month and a half before we winnowed the interested parties down to the really -- the real interested party. Another month and half or so to finalize paperwork and maybe a little bit longer to close. So think close certainly late third quarter, early fourth quarter, something like that. Unless somebody...

Do you believe the proceeds will be sufficient to fund the cash burn or you may have to pursue some other options that you were telling on Mike Kelly's question? And just to be putting our numbers in, is more debt -- taking on more debt an option to kind of fund the full burn?

Let me answer a question you didn't ask. Absolutely no intention to place any equity. We have no intention of placing any debt other than our normal and appropriate use of our revolver which is undrawn at this time, as you know. So yes, we have a plan that allows us to proceed without that sale. And it just enhances our plan if we make that sale. We've got a lot of interested parties, so we won't be forced to go to any other alternative. If we choose to, we'll do so because of just common sense. But first off, take that $300 million thing and erase it off your sheet.

All right. Okay. Can you elaborate on that? Is $400 million, $500 million a realistic number? Or you don't want to speculate at this time?

We've had a lot of experience in infrastructure build outs and [sales]. It's been sort of a fact in our business for years that the toll roads leading from your wellbore to the markets are more valuable sometimes than the NP asset in terms of EBITDA multiples, that seems to be the case today. I wouldn't be very interested in selling it even at $400 million. So I mean you're way -- you're just way low. I mean it's -- I guess we haven't reported any numbers on EBITDA from that business. But I mean we're certainly not getting any value in our share price for that. So it's hard to stay. The market will speak as it does with everything. I don't want to salt the market with any expectations. But our expectations are a fair price for a great asset and that number will be appropriate to the projected EBITDA.

That's terrific. I would love to be (inaudible). In terms of limitations on drawing on your revolver to fund cash burn (inaudible) or is it for you to use any way you choose?

We have no limitations. We've got a, as you know, decades long relationship with our banks, our borrowing base documents have barely changed in 20 years. There's no limitations whatsoever. There's limitations if you want to go buy a yacht or something or -- I mean, something silly. But in the course of business, we don't having any limitations. Actually, a yacht, I've never had one. It sounds kind of good.

Well, that is great. Just in terms of RBLN, how many banks do you have? Do you need like a majority? Or do you need everyone to agree with the amount? How does that work with you guys?

We have 6 banks in our credit facility and different votes take different levels. We have some votes that are 50%, some 2/3 and some 100%. I can assure you -- there's a only few things that require 100%, and this is not one of them. So our banks are well aware of our plans. And there's not going to be any issues at all. They're going to work with us. The pipe system, really, it doesn't get any credit, the RBL either. That's purely based on our oil and gas asset. So we will not have any issues around that.

There are no voting required to draw the $200 million?

No, not to draw, no.

And next, we'll go to David Epstein with Cowen and Company.

Your commentary on the midstream (inaudible) very interesting. Obviously, right, $400 million would, correct me if I'm wrong, probably approach double or more what you've put into it. How do you think sort of the value relative to cost? Or how do you think the market would think about that, potentially?

Well, the market would have no idea what to think, tell you the truth. We would think at this early stage, a triple on our cost would be a great -- a good outcome. We would think that some multiples of EBITDA that approaches a triple on how we trade would be a good outcome as well. So those are sort of ballpark-ish ideas there. But double on our cost would not be attractive.

Okay, appreciate that. I noticed on your (inaudible) slides, you raised them considerably, particularly for West Quito. I assume a lot of that is a function of the D&C dropping to $10.6 million for West Quito wells. Are (inaudible) assuming in terms of differentials, does this assume like a [2020] kind differential once things are back to a normalized number or what?

Yes, we use a blended differential that includes the near-term higher differential associated with Midland pricing. And then the longer term, once we get on the pipe to the coast, we'll be realizing a differential above 100%. So again, most of the economics of a type curve are dictated by the later years, the first 6 months versus the later years. So it's somewhere right around 100% differential on oil or the type curves after blending the near term and the long term.

Appreciate that. And if I could, quickly. Can you tell us what capitalized G&A is? And I was curious, now that you guys are a little bit less in acquisition mode it seems, will that have any impact on your capitalized or expense G&A stock or cash expense?

I have no idea what that even is. Do any of you guys know? Go ahead, answer.

Yes. For the full year, that number should be about $12 million. That's looked at every quarter. But as we sit here today, $12 million is a good number for you to use.

And that will conclude our question-and-answer session. I'll turn things back over to our speakers for any additional or closing remarks.

No additional remarks. Thanks for dialing in. We'll be talking as you care to. Thank you.

And that will conclude today's conference call. Thank you, everyone, for your participation. You may now disconnect.