Good day, everyone, and welcome to the Halcon Resources Second Quarter 2018 Earnings Call. Conference is being recorded. At this time, I would like to turn the conference over to Mark Meisz. Please go ahead, sir.
Good morning. This conference call contains forward looking statements for a detailed description of our disclaimer is released yesterday and posted on our website. We've also updated our investor presentation for our Q2 activity and other operational items, and you can access that presentation on our website. I'll make a few comments about our financial guidance for the Q2, and then I'll turn the call over to John Roff to talk about operations, and then Floyd will take the call to discuss guidance and strategy. Production for the Q2 averaged 12,169 barrels of oil equivalent per day, comprised of 6 percent 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 interruption and some weather related issues. July 2nd quarter oil differential of 90% in NYMEX That was less than the 99% differential seen in the first quarter. It was really just driven by weaker Midland pricing. Our 2nd quarter natural gas differential came in at 52% in NYMEX, which was lower than the Q1 of 2018, and that was driven by weaker Waha pricing. Our NGL differential for the 2nd quarter, 39%, was more or less in line with the Q1, which was 41%.
Our LOE and work expense was $7,300,000 for the quarter or 6 $0.25 per BOE versus $6.06 per BOE in the first quarter. And our 2nd quarter LOE and workover rate per BOE would have been right at about $6 per BOE if we would have experienced the unexpected downtime. We expect that to continue to trend down in the second quarter or half of twenty eighteen as we continue to gain scale and ramp production. Gathering expense, as adjusted in the press release, totaled $5,500,000 for the quarter or $4.73 compared to $5.55 in the Q1. This metric also was impacted by the unexpected downtime.
G and A expense, as adjusted, totaled $10,100,000 for the quarter or $8.68 per BOE versus $11.35 in the Q1. This per BOE rate will continue to come down over the remainder of 2018, again, as we gain scale without any significant acquisitions expected.
With respect to
our current quarter of capital spending, we incurred $132,000,000 in D and C, dollars 29,000,000 in the quarter, seismic and other and $214,000,000 on acquisitions. The majority of that was the West Quito Draw acreage. Finishing, we did realize the net gain on settled derivative contracts of approximately $26,000,000 during the second quarter were 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 as in 2019 and an average price of $56.27 We also have 8,000 barrels of Midcush Basin swaps in place for the remainder of 'eighteen at an average price of $11.69 We have 12,000 a day of midstream swaps in place for the Q1 of 2019 at $3.02 We have 4,000 barrels a day in place for the second half of twenty nineteen at $3.95
On the second half
of twenty nineteen, we have 7,500 NMBtu of gas hedged for the last 6 months of 2018, a decrease of 3.16 dollars We have 1,000 NMBtu a day of gas hedge and 29,000 NMBtu at an average price of 2 $0.80 We also have 15,000 NMBTU a day of losses hedges in place for the second half of twenty eighteen at 1.10 dollars and $25,500 a day of the losses in place for 2019 at 1 point $1. As of June 30, the end of the quarter, we had $294,000,000 of liquidity. That did consist of $96,000,000 of cash on the balance sheet, plus a fully undrawn revolver. And with that, I'll turn
the call over. Thanks, Mark. As Mark indicated, we had quite a bit
of a reduction 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 provider to have a new substation constructed within our acreage position, which will improve power reliability. We connected roughly half of the Hackberry draw field to the substation via our new feeder line, and we anticipate that we will have the remaining wells connected within the next few weeks on our 2nd feeder line.
Additionally, we will continue to build
our HFS owned power transmission infrastructure throughout the field to ensure that all of our wells are connected to the grid, making us less reliant on generators for power. In Monument Draw, we continue to be very happy with our drilling results. The Sealy Branch 61H began cutting oil in late June. And we have very strong results with the current 20 day average of 185 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 6,401H is located in the central portion of our Monument Draw acreage position. We began flowing back to Sealy Ranch 70 702H in Monument Draw. This morning, wells are producing over 1600 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 two wells were completed in the lower and upper Wolfcamp intervals as spacing at 3:30 feet apart horizontally and 2 50 feet apart vertically in rack positioning. We ran microseismic on this project and we have confirmed that the frac was visible with little to no interference These wells confirm our spacing assumptions of up to 13 upper wells per 12 acre drilling spacing unit in 1 McGraw. There's a great illustration of this work on Slide 8 of our investor deck. Now with 6 additional wells pulling back now or being put online over the next few months, we will have de risked 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.
We modifying our drilling fluid program and implementing new bid designs in the intermediate 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 $14,000,000 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 Hackery Draw in the Q2 2018. The most recent of these wells, the Bobby 1H, is on our type curve. The 2 wells will go further south in our region and while we remain slightly below the type curve estimates there, so we expect to put 5 additional wells on line here for the remainder of 2018, and all these wells are focused on areas where we expect to meet or exceed type curve expectations. In West Quito, we recently began our drilling program of 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 are illustrated on Slide 9 of our investor deck. Performance thus far has been on track. The total drilling day is looking to be around 30 days. Accordingly, we will have adjusted accordingly, we have adjusted our D and C costs in West Quito downward to around $10,600,000 versus $11,500,000 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, John. John 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 best providers. We hire the best providers in the way that we work.
As to growth, as we reported, we dropped the rig a while back, bringing our rig count to 3 rigs for the rest of the year and for at least the 1st 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. The right time to press for higher production. I'd like to see realized prices back over $60 a barrel before I add them again. Time will tell on that.
Having said that we've dropped a rig and lowered production, we're still guiding to a 33% growth rate Q4 of 2018. And that becomes more than a 300% production increase year 2017 to 2018. These are very strong that we're drilling out here. We're running 1 dedicated crew today, and we'll bring in a spot crew as needed. We continue as I mentioned, we continue to use only the best service providers and the high end of all equipment as we build our 60,000 Acre 2,000 location, position them into a durable, profitable, tight asset base.
We have lower production 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 2019, again, as I mentioned, and that is dependent on crude netback pricing. If we do that, that will allow us to continue growth to 1,000 barrels a day average for next year, a very strong day. On that basin logjam, we've announced executed comprehensive takeaway agreement with Salt Creek Midstream, a great partner for us in the Delaware River. Our agreements with them lead to a 5,000 barrel of oil per day capacity on new construction, taking our oil 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. It's hard to say it's done, but it has definitely slowed down, maybe even flattened. Drilling the completion costs were approximately $400,000,000 for 2018, down about $35,000,000 from before we update. Infrastructure and seismic spending will be about $20,000,000 or more higher than before at approximately 100,000,000 dollars This is driven primarily due to additional expenses related to building out a high spec gathering and treating system at Monument Draw, where we are seeing elevated levels of H2S.
Off field services is remains a focus of our business. It's a very valuable asset. The addition of the acquisition of the business is part of this additional to deal with the issues that Monument Draw as part of hotfield services. We're going to provide an even more highly valuable asset encompassed within our subsidiaries. We reported the launch of a self leased path of this awesome asset, Hartfield Services.
We've received a
very high interest of strategic and financial parties. I expect
to have nearly 40 CAs executed soon as we go down the path that we have gone down before successfully. We expect the marketing process to be complete within a month or 1.5 months and a close month or 1.5 months after that. We're also seeing both a partial sale and outright sale of this valuable asset. Any proceeds from this divestiture will enhance our liquidity as we move towards cash flow sufficiency. We have 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, a great end result for all of our investments. Operator, we're ready for questions.
First to Jeffrey Campbell, Jefferies.
Good morning.
Good morning. I thought the slide
was interesting. I was looking at your economic comparison of 5000 to 10000 foot laterals and it appears to show a one to 1 production ratio between the lateral lengths. In other words, the production is doubling when you're doubling the length of the lateral. So I was just wondering, is it consistently in your current well performance?
What you're looking at there, it shows that during the first five years, it's exactly linear. You don't expect to 100% just double based on lateral length of 5 versus 10. But certainly, the early days is very dramatic increase.
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 notion of derisked zones and others that would be appraisal zones. At 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 actual base.
And so based on what you see with peers, is there particular zones that seem to be pretty promising and might be the first one you go after?
Well, we've done a couple of bone spreading 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 of these. The possibilities are a little bit different than the certainly a couple of the springs on the Bone Spring, the Wolfcamp zones. But probably more important than that, the economics is the spacing test that John mentioned.
If we find that we can drill wells in this Chevron or line rack pattern, they're over 200 feet apart and still maintain the integrity of our frac jobs, that meaning keeping the frac jobs really tight to the drill. That has much more value than anything we can with finding some Wildcat zone. We do have plans. We're not going to do it this year, but we have plans to drill deeper tests at both Monument Draw and Hackberry. And we also selected to drill deeper into the Wolfcamp, for simplicity, call it Wolfcamp, and we'll see more in the future up at West Quito.
So there's a lot of ammunition out here for continued growth. But with 60,000 acres in a couple of 1,000 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. Well, thanks, Floyd. I appreciate the call.
And we'll go next to Tarek Hamid with JPMorgan.
Good morning. We talked
the deal with Salt Creek, just if we can give us on how to think about the sort of the cost of some of the long haul take? Any color would be appreciated.
Well, we're probably not at liberty to say put some exact numbers up on the competitive situation out there for our partner. I will say that the transport costs are basically pretty nominal given the log jam. I don't know if we've given out any modest advice on that or, Quentin, maybe you have something to say.
I would say, if you look at the forward of Houston or LLS or down in Houston pricing in late 'nineteen or early 'twenty, and we expect to get on that pipe. On that pipe, it's a $3 or $4 premium to WTI. We expect that we have a net cost of premium to WTI for that premium that you're seeing in the market. So our fee is rather not 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 how the mechanism would be?
Either Anthony or Quentin will address that we found that we've been involved in, which has been pretty much every year, these log jams 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 possibility of going to the coast. I think Steve's on the phone. Steve, you want to add to that?
No, Floyd, I think that sums it up. The flexibility is key, as you say, in every how we think are going out over time. And so we wanted to
make sure that we weren't
as you work 2 or 3, 4 years, that would be somewhere that might not be as attractive then as it might be or a year from now. And we've built in stability in agreement to our capacity on the line over time at the end of the call if we choose to.
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 the 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 costs. Can you just talk a little bit about what you're seeing, sand or some more marks as well as increase?
John? With regards to
the investment, really, we're starting to see a lot of in basin stand come online. It's primarily in that 100 mesh. We'll say that we are using in basin sand for the 100 mesh. Metal. As far as pumping crews, we've seen some softening in the market, some availability to pick up a saw through when needed.
So I think we're pretty set from that perspective. Great. That's it for me. Thank you very much.
And next we'll go to Jason Wangler with Imperial Capital.
Good morning.
On the infrastructure sale, could 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 interest in the assets?
Well, as contemplated today, the sale of this is across the basin to include every aspect of infrastructure, be it water, gas, oil, treating, compression, disposal, everything, power. It would be our initial intention is to sell off about half that business. And on a go forward basis, that partner would be our partner in the growth of that business. I don't know if that's what you're looking for there, Jason.
That's helpful. Thank you, Floyd. And then just as we think beyond this 2018 program with 3 or if you could go to 4, do you have a sense of kind of where you focus those? Obviously, you've got some really good results in Monument and we'll see about West Quito, but it's in 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 discussion. We are in all new areas, you work pretty hard to define your area within each of our holding areas. And so we have 3 main ones. We've actually defined some really good rock on the Hector We'll continue drilling down there. And we've had a few areas where the results are a little less than we won't drill in those areas at Hackberry, but the largest part of our acreage down there, we've had some really good results.
And with this moderation in inflation, we think that we can put some upside in pricing and our cost down there. So we're not going to discontinue that by any means. I wouldn't say there would be an even third just changes over time. As we move to 100% pad drilling, your rig or your well count is driven by a well cap. So if we can get ourselves into position for multi well pads, your long run area, then you might have been to drill in singles.
So you might find yourself 1 year drilling, 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% of Hackberry and the rest kind of evenly split between Monument Draw and the Mosquito. But again, we just brought on a couple of great wells down at Tac Barry. We see no reason to deemphasize that except in just the default nature of the rate of return of a well that's going to make 2,000,000 BOE compared to a well that's going to make 1,000,000 in a quarter BOE or whatever.
Appreciate the color. Thank you.
Our next question will come from Mike Kelly, Park Global.
Great. Thanks. I was hoping maybe
you could expand upon your thoughts for 2019. You mentioned you'd like to get a
rig active early in the year, but
you also said that you'd like to see $60 to make it happen, which is
like a little more tough. And then maybe if you guys
have a decent base case, maybe a scenario and what that could look like for the capital spend for next year and what would be the number on it?
Yes. The $60 that I would be kind of a net rationalized differential, things have softened or evened out.
And we
don't know when that might happen. If you were running 3 rigs in 2019, you'd look to spend a bit more than $300,000,000 maybe $25,000,000 or so, give yourself a spread around that, say $300,000,000 $350,000,000 If you brought it partway through the year, that would increase about $50,000,000 So if it was 3.5 rigs, it would be about $350,000,000 to $400,000,000 something like that.
Okay. That's great. And I want to take a stab at potential growth for
3 or 3.5 rig program?
Well, of course, I mentioned that we would expect under our current expectation to lead us to think that we'd be average about 30% for the year. And if it was fewer rigs, it'd be about now 10% less or 10% or 11% less than that. Those are steps, by the way. As we've seen, we need to pursue the appropriate development of these assets. We don't have to 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 25,000,000 to 30,000,000 BOE per day and 3.5 rigs would yield about another 3,000,000 or 4,000,000 net barrels per day on top of that.
All right. Great. Appreciate that.
1,000. Understood. Okay. Then one more for me.
You mentioned in the press release several options to fund outspend, talked pretty extensively about the midstream component of that. But you also mentioned in the press release JVs and other
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 we might relieve some of the market conditions that we hear. If you think about a company our size, basically a start up, we started we bought our first property last year in March out here, sold everything else, Over 60,000 acres, several thousand couple of 1,000 locations or more.
We can't drill that many no matter how many rigs. So the 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, reducing our growth trajectory. So several things that we're looking at along the 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 when of course, that's a center we're trading at dark times EBITDA and we can get 10x more than that for us.
So we'll it's an asset that we shouldn't own all the time. It's pretty simple there. That's what we should think, but we have other 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, getting the drilling costs down. We're working really hard to continue the frac jobs, working really hard on the build out regardless of the sale because these will be 50 or 100 years or whatever, these leases will for sure.
And you got to build a durable platform kind of activity. So we're focused on all of that, at the same time, quite focused on balance sheet
Got it. Appreciate it. Thank you.
And next we'll go to Ron Mills with Johnson
Good morning. Floyd, the release under the salt question 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 the truck and in the pipeline? And what can that have on the
pressure? 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 or 5x as much as the pipeline cost, 5x as much. So that's a significant factor.
It's also a big factor. You get muddy, trucks break down, drivers don't show up, whatever. We're going to get all of the oil to a rink. And from there, as soon as these other pipes open up, we'll pour oil out of the basin, all that we choose to. What else?
Yes. And also, as far as the deal include the purchase option
to move all of the oil from hemp. So I'll improve your takeaway.
And so
we should be operational at some point in the 4th quarter?
I think within 2 months as far as being off of trucks.
That's right, Ron. We expect the Monument Draw Oil to be on-site and that's, of course, 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 by particularly monitoring the forward of all of the year. It helps us a lot. It's that trucking, it's a perfect way to move that much product.
Okay, great. And Floyd, maybe just maybe for John. You think about strategy where you the volume withdrawal where you've seen some of your metal rigs and took it down to,
Gary, 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 we're going to see increased capacity and improved midland production?
Let me ask John to add to this, but we moved a rig back to Hackberry because we have several quarries to drill down there. Simple. At the cost that we expect to experience, they're 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 there drilling down to the curve, I think to the curve is the way it is.
And I think John's got 5 of those already drilled. So he's got a maybe it was 8 exactly, a good list of wells that are going to be fracked anyway. So we're not going to experience a big production growth from Monument Draw. You've got limited ability to spend time in. You take those rigs where they should be in terms of the best investment.
It should be in terms of technical coverage. Sometimes you might be waiting on sites, sometimes you might be waiting on a marketing or some pipe or some infrastructure. So John, what else
would be there? Floyd, we mentioned earlier in the call about the installation of a gathering system for the wellhead for sour surface applications. 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 spin for us.
We got a bit ahead of ourselves with that. And so that contributes to the capital spend in 2018, but we'll have a positive impact for 2019. We're working on all fronts here. The results of Monument Draw have been great. I think certainly exceeded our expectations.
But we're working on the cost side as well. So there's the two sides of that. We've been pumping some of our frac more refracs both in Hackberry Draw and Monument Draw. We've been pumping a smaller job, approximately £2,000 per foot. And as indicated by these results, those fractionated initial rates.
I mentioned that we're using our 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 cluster efficiency while increasing our age length. So what the end result there is the lower cost. So making great wells and lower our costs through our complete efficiencies, drilling in multi well pads throughout the rest of 2018, which further adds efficiency to our operations and decreases costs.
So those are the key points that we're really focused on, Ron.
Great. And then one last one on Westfield.
Are your first five wells you're drilling, what zones
are you
targeting out at Westfield? Road? So those five wells are targeting the Wolfcamp Upper Wolfcamp interval.
Thank you very much.
And our next question comes from David Beard with Coker Palmer.
Hey, good morning, gentlemen.
Most of my questions have been asked.
So I just had a follow-up on the SALT on relative to timing. If it comes in the Q4, will you
be able to move all your oil volumes
to that theoretically? Or are there some restrictions?
When the pipe when it's available, we have a full allotment available to ship.
Okay, great. Thank you. Congratulations.
And next we'll go to Vivek Pal with Seaport Global.
Yes, good afternoon. Good morning, guys. Could you give us a sense of timing and potential value of the midstream asset? Is $300,000,000 realistic for the whole base?
We wouldn't sell it, period. That's a crazy low number.
And in terms of
timing Timing wise, looking at a month or 1.5 months before we winnowed the interested parties down to the real interested parties, another point 5 or so to finalize paperwork and maybe longer to close. So it closed certainly late Q3, early Q4, something like that. Do you believe Yes, go
ahead. 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 burn?
Let me answer a question that we can ask. Absent the intention to place any excess cash, we have no place in 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 comments. First off, take that $300,000,000 thing and erase it off your sheet.
All right.
Okay. Can you elaborate on that? Is $500,000,000 $500,000 a realistic number or you don't want to speculate at this time?
We've had a long experience in infrastructure building and retail. 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 E and P asset in terms of EBITDA multiples. That seems to be the case today. I would be interested in selling it even at $400,000,000 So I mean, you're way low. I mean, it's I don't 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 say. The market will speak as it does with everything. I don't want to follow-up with any expectations, but our expectations are fair price for a great asset and that number will be appropriate to the projected EBITDA. That's terrific.
I would love to be clear.
In terms of limitations on drawing on your revolver to fund cash burn, is that
the balance sheet or is it for
you to do any way you choose?
We have no limitations. We've got a, as you know, a decade long relationship with our banks. Our borrowing base documents have barely changed in 20 years. There's no limitations whatsoever. There's limitations.
Do you want to go and buy a yacht or something or I mean, something silly, but on the course of business, we don't have any limitations. Actually, I've never had one. It sounds kind of good.
That is great. Just in terms of how many banks do you have? Do you need like a majority or do you need everyone to agree with the bank with the amount? How does that work with you guys?
Hey, we have 6 banks in our credit ability and different boats take different levels. We have some boats that are 50%, some twothree and some percent. I can assure you that there's only a few things that require 100 transactions, not one of them. So our banks are well aware of our plan, and there's not going to be any issues at all that you know, with us. The pipe system really it doesn't have any RBL either.
That's purely based on our oil and gas. So we will not have any issues around that.
There's no voting required to draw the $200,000,000 No, not to draw, no.
All right. Thank you very much.
Next we'll go to Steve Stine with Cowen.
Thanks for taking my call. Your commentary on the midstream is very interesting. Obviously, right, $400,000,000 would correct me if I'm wrong probably approach double or more of what you've put into it. How do you think about the value relative to cost? How do you think the market would think about that?
Well, the market would have no idea what to think, to 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 multiple 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. A double on our cost would be attractive.
Okay. Appreciate that. I noticed on our slides, you raised them considerably, particularly for West Quito. I assume a lot of that is a function of the D and C dropping to $10,600,000 for West Quito wells. Are you assuming in terms of differentials, does this assume like a $20,000,000 kind of differential once things are back to a normalized number or what?
Yes. We use a blended differential that is the near term higher differential associated with midland pricing. And then the longer term, we get on those sites, it will be realized the differential above 100%. So most of the economics of a type curve are dictated by the later years, the 1st 6 months versus
the later years. So it's
right around 100% difference on oil type curve, weatherblaming in the near term and the long term.
Appreciate that. And if I could quickly, can you tell us what capitalized G and 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 and A, stock or cash expense? Thanks.
I have no idea what that even is. Does anybody know?
Go ahead, Anthony.
Yes. For the full year, that number should be about $12,000,000 That's looked at every quarter. But as we sit here today, dollars 12,000,000 is a good number for you to use.
Okay.
Thanks very much.
This concludes our question and answer session. I'll turn things back to speakers for additional or closing remarks.
No 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.