Please stand by. Good day, everyone, and welcome to the Halcón Resources second quarter 2018 earnings call. This 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 disclaimers, see the press 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 a few comments about our financial for the second quarter, and then I'll turn the call over to Jon C. Roff to talk about operations, and then Floyd will take the call to discuss guidance and strategy. Production for the second quarter averaged 12,169 barrels of oil equivalent per day, comprised of 60% oil. This production rate was approximately 500 BOE a day less than we had projected due to some unexpected downtime that was caused by a power interruption, also some weather-related issues.
Our second quarter oil differential of 90% in NYMEX was less than the 99% differential seen in the first quarter. It was really just driven by weaker Midland pricing. Our second quarter natural gas differential came in at 52% in 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 41%. Our LOE and workover expense was $7.3 million for the quarter, or $6.25 per BOE versus $6.06 per BOE in the first quarter. Our second quarter LOE and workover rate per BOE would have been right at about $6 per BOE if we wouldn't have experienced the unexpected downtime.
We expect to continue to trend down in the second quarter for the second half of 2018 as we continue to gain scale and ramp production. Gather 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 quarter capital spending, we incurred $132 million in DMC, $29 million for seismic and other, and $214 million on acquisitions. The majority of that was the West Quito Draw acres.
Hedging, we did realize the net gain on settled 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 six months of 2018, and we have 15,504 barrels per day hedged in 2019 at an average price of $56.27. We also have 8,000 barrels of Mid-Cush basin swaps in place for the remainder of 2018 at an average price of $11.69. We have 12,000 a day of Mid-Cush swaps in place for the first half of 2019 at $3.02. We have 4,000 barrels a day in place for the second half of 2019 at $3.95. Gas hedges, we have 7,500 MMBtu of gas hedged for the last six months of 2018 at an average price of $3.16.
We have 2,000 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 purchase hedges in place for the second half of 2018 at $1.10. 25,500 a day of Waha purchase hedges in place for 2019 at $1.15. As of June 30th, 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. With that, I'll turn the call over to Jon C. Roff.
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 power 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. We anticipate that we will have the remaining wells connected within the next few weeks on our second feeder line. Additionally, we will continue to build out 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 running the draw, we continue to be very happy with our drilling results.
The Sealy Ranch 61H, again cutting oil in late June, has very strong results with a current 20-day average of 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. It began flowing back through Sealy Ranch 7702H in Monument Draw. This morning, flows are producing over 1,600 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 at spacing of 330 feet apart horizontally and 250 feet apart vertically in rack positioning. We ran microseismic on this project, and we have confirmed that the frac was with little to no interference.
These wells confirm our spacing assumptions of up to 13 upper wells per 12-acre drilling spacing unit in Monument Draw. There's a great illustration of this work on slide eight of our investor deck. With six additional wells flowing back now or being put online over the next few months, we will have derisked most of Monument Draw for the Wolfcamp by year-end, as shown on slide seven. We also have improved our drilling performance in Monument Draw. We modifying our drilling fluid program and implementing new bit designs in intermediate which has resulted in reduced drilling days. I will also note that we have eight 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 three Wolfcamp wells online in Hackberry Draw in the second quarter of 2018. The most recent of these wells, the Bobby 1H, is our type curve. Two wells were drilled further south in our [audio distortion] and while slightly below type curve estimates, they are still [audio distortion] . We expect to put five additional wells online 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 with two rigs on a two-well pad and a three-well pad. These five 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 nine of our investor deck. Performance thus far has been on track. The total drilling days looking to be around 30 days. Accordingly, we have adjusted our DMC costs in West Quito downward to around $10.6 million versus $11.5 as previously reported. 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 lowest providers. We hire the best providers. As to growth, reported we dropped a rig back, bringing our rig count to three rigs for the rest of and for at least the first part of next year. This moderation in cadence is driven by the basis blowout with that differential standing above $15 a barrel today. Not the right time to press for higher production. I'd like to see realized prices back over $60 a barrel. 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 over Q3 of 2018, and that becomes more than a 300% production increase year-over-year, 2017 to 2018. These are very strong that we're drilling out here. We're running one dedicated crew today, and we'll bring in a spot crew as needed. 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 into a durable, profitable, tight asset base. We have lowered production due to the one rig, our rig count reduction. As I mentioned, we'll deliver strong growth. We hope to add a rig in 2019, again, as I mentioned, and that is dependent on crude netback pricing.
If we do that'll allow us to continue growth to the 30,000 barrels a day average for next year. A very strong. On that, Basin Logjam, we've announced executed comprehensive takeaway agreement with Salt Creek Midstream, a great partner for us in the Delaware Basin. Our agreements with them lead to a 5,000 barrel of oil per day 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. It's hard to say a point and say it's done, but it has definitely slowed down, maybe even flattened. Drilling and completion expense approximately $400 million for 2018, down about $35 million from before we re-rigged.
Infrastructure and site expending will be about $20 million more 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. Halcón Field Services remains a focus. It's a very important and valuable asset. The additional to deal with the issues at Monument Draw as part of Halcón Field Services, 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, Halcón 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 month and a half, and a close 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 additional liquidity and leverage-enhancing projects under consideration at this time. We are not pursuing any significant acquisition ideas today. As far as strategy, it's really pretty simple. Great rock, great execution lead to a great end result for all of our investments. Operator, we're ready for questions if anyone.
Certainly. If anyone would like to ask a question, please press the star key followed by the digit 1 on your touchtone telephone. Once again, that's star 1 if you have a question, and we'll pause for just a moment to assemble the queue. First to Jeffrey Campbell, Tuohy Brothers.
Good morning.
Morning.
I thought the slide was interesting. I was looking at your economic comparison of 5,000- and 10,000-foot laterals, and it appears to show a one-to-one production ratio between the lateral lengths. In other words, the production's doubling when you're doubling the length of the lateral. I was just wondering, is that 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 five versus 10. Certainly the early days is a very dramatic increase.
The early years are the ones that count, that's good. I also thought I would ask you, slide 16 has a nice version of de-risked 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? Second, I'm sure you're watching all the activity in the basin, based on what you see with peers, is there a few particular zones that seem to be pretty promising and might be the first one you would go after?
Well, we've done a couple 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 . The possibilities are a little bit but certainly a couple of Springs on the Bone Spring, the Wolfcamp zone. 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 wine rack pattern, they're only 100 feet apart, and still maintain the integrity of our frac jobs, that meaning keeping the frac jobs really tight to the drill that adds much more value than anything we do with finding some wildcat zone. We do have plans. We're not going to do it this year, we have plans to drill deeper tests at both Monument Draw and Hackberry.
We also plan to drill deeper into the Wolfcamp. For simplicity, call it Wolfcamp C, more in the future up at West Quito. There's a lot of ammunition out here for continued growth. With 60,000 acres and a couple thousand locations now, how many do we want to count? We could count a lot more.
Right. That sort of reinforces the notion that you're not making any more acquisitions at this time. Well, thanks Floyd. I appreciate the call.
We'll go next to Tarek Hamid with J.P. Morgan.
Good morning. Can you talk, the deal with Salt Creek, specifically, kind of some color you can give us on how to think about 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 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 modeling 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 [Gulf Coast] Houston pricing in late 2019 or early 2020, when we expect to get on that pipe, it's a $3-$4 premium to WTI. We expect to cross the premium to WTI for that premium that you're seeing in the market. Our fee is rather not.
Got it. That's really helpful. You wrote in the release that you have the ability to increase the capacity on it each year annually. Can you just talk a little bit about how high that could go and what the mechanism would be?
Either Anthony or Quentin address that. We found we've been involved in, which has been pretty much every that these log jams occur, they endure for a year or more, and then they move. I think that you don't ever want to have all of your product going in one spot. We intend to keep our options open for some of our crude to be sold in the basin in the future, and with the of it going to the coast. I think Steve's on the phone. Steve, you got anything to add to that?
No, Floyd, I think that sums it up. The flexibility is key, as you say, in every how these things play out over time. I wanted to make sure that we weren't work two or three or four years now would be somewhere and not be as attractive then as it might be a year from now. We've built in stability and agreement to our capacity on the over time, as an option if we choose to.
I believe that written in part of that agreement is about 50% increase under the existing agreement.
Yeah, I believe that's about right. Over time, that's right. We have the ability to change it each year once we get going.
Got it. That's helpful. Just the last one from me. You made a brief comment in the slides about completion cost. A little bit about what you're seeing with sand or some of the as well as increase?
Sure. With regard to that really we're starting to see a lot of in-basin sand come 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, some softening in the market, some availability to pick up a swap crew when needed. I think we're pretty set from that perspective.
Great. That's it for me. Thank you very much.
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 the 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. Our initial intention is to sell off about half that business. On a go-forward basis, that party 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. As we think beyond just 2018 to program with three or if you go to four, do you have a sense of where you'd focus those? Obviously, you've seen 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 gonna float around as we think longer term.
Well, it probably doesn't come through very well in our presentation or our discussion. In all new areas, you work pretty hard to define your area within each of our holding areas. We have three main ones. We've actually defined some really good rock down in Hackberry Draw. We'll continue drilling down there. We've had a few areas where the results are a little less effective. 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. With this moderation in inflation, we think that we can get some upside in our cost down there. We're not going to discontinue that by any means. I wouldn't say it would be an even one-third, one-third, one-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. If we can get ourselves into the position of more multi-well pads, you're longer in the area than you might have been if you're drilling singles. You might find yourself one year drilling more 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% of Hackberry and the rest evenly split between Monument Draw and West Quito. Again, we just brought on a couple of great wells down at Hackberry.
We see no reason to de-emphasize 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 a million and a quarter BOE or whatever.
Appreciate the color. Thank you.
Our next question will come from Mike Kelly, Seaport 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, you also said that you'd like to see $60 to make it happen. Just a little more thought, then maybe if you guys could give a decent base case, maybe a scenario of what that could look like for the capital spend for next year and what the number on a run rate would be. Thanks.
Yeah. The $60 that I referenced would be a net visualization around the differential thing as cost ends are evened out. We don't know when that might happen. If you were running three rigs in 2019, you'd look to spend a bit more than $300 million, maybe $325 or so. Give yourself a spread around that, say $300, $350. If you brought a rig partway through the year, that would increase about $50 million. If it was three and a half rigs, it'd be about $350-$400, something like that.
Okay. That's great. Want to take a stab at potential growth there? A three or three and a half rig program?
Well, of course, I mentioned that we would expect under our current expectations that lead us to think that we'd be averaging about 30 for the year. If it was fewer rigs, it'd be about 10% less or 10% or 11% less than that. Those are stats, by the way. As we've seen, we need to pursue the appropriate development of these assets. It's hard to do that if you have a lot of uncertainty on commodity pricing. Right now, three rigs would be about what I said and yield about $25 million-$30 million, 30,000 BOE per day, and three and a half rigs would yield about another three or four million net barrels per day on top of that.
All right, great. Appreciate that.
Per thousand.
Per thousand. Understood. Okay. One more for me. You mentioned in the press release several options to fund near-term outspends. You talked pretty extensively about the midstream component of that, but you also mentioned in the press release JVs and other options. I was hoping you could give maybe a little more context around those second two. Thanks.
Mike, we're uber-focused on leveraging liquidity as always. We've got a tight plan. We're good to go at this moment, but anything we can do to enhance that might relieve some of the market concerns that we hear. If you think about a company our size, basically a startup. We bought our first property last year in March out here, sold everything else. Own 60,000 acres, a couple thousand locations or more. We can't drill that many no matter how many rigs. A JV that involves selling off some of that acreage or selling off some of that drilling would be an attractive way to sort of reduce our inventory without reducing our growth trajectory. There are 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 center we're trading at dark and deep time, we can get 10 times more than that for it. It's an asset that we shouldn't own all the time. It's pretty simple there. That's what we should pay, but we have several ideas, and these things are 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 do the frac jobs, working really hard on the build-out regardless of the sale, because these wells will be 50 or 100 years or whatever, these leases will for sure. You got to build a durable platform kind of activity. We're focused on all of that.
At the same time, quite focused on balance sheet.
Got it. Appreciate it. Thank you.
Next, we'll go to Ron Mills with Johnson Rice.
Morning. Floyd, the release under the sale also mentioned the building of some oil pipelines to get your volumes to Wink. Is that designed to get all of your oil volumes off the truck and in the pipeline? What impact can that have on the [audio distortion]?
Well, I'd like Anthony or Steve to really address the details of that. Within a couple of months, we expect essentially off truck and in pipe. Trucking is, gosh, four or five times as much as the pipeline cost. About five times as much. 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 the oil to Wink. From there, as soon as these other pipes open up, we'll get more oil out of the basin, all that we choose to. What else?
Yeah, Floyd, part of the deal includes a purchase option to move all of our oil from Wink. That improves your takeaway.
It's supposed to be operational at some point in the fourth quarter?
I think within two months as far as being off of trucks.
That's right, Ron. We expect the Monument Draw oil to be on pipe, that's of course the biggest share of the volume in Ward County, by October, the West Quito by December. As Floyd and Anthony mentioned, of course, it helps us a lot, particularly Monument Draw with the volume. It helps us a lot on trucking isn't a perfect way to move that much product.
Okay, great. Floyd, maybe for John, think about strategy where [audio distortion] . 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?
Let me ask John to add to this. We moved a rig back to Hackberry because we have several great to drill down there. Simple. At the cost that we expect to experience, they're going to be reasonably competitive. At Monument, we 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've had intermediate drilling down to the curve, I think to the curve is [audio distortion] . I think Jon's got 5 of those already drilled. He's got, maybe it was 8 exactly, a good list of wells that are going to be fracked anyway. We're not going to experience a big production growth from Monument Draw. You've got limited and you take those rigs where they should be in terms of the best investment, should be in terms of technical coverage.
Sometimes you might be waiting on site. Sometimes you might be waiting on marketing or some pipe or some infrastructure. Jon, what else would be there to say?
Floyd, you mentioned earlier in the call about the installation of a gathering system for the wellhead for sour service applications. Those are some of the things that we're working on over in Monument Draw. As you mentioned, 8 wells that are set with intermediate casing. That was a forward spend for us. We got a bit ahead of ourselves with that. That contributes to the capital spend in 2018, we'll have a positive impact for 2019. We're working on all fronts here. The results in Monument Draw have been great. I think certainly exceeded our expectations. We're working on the cost side as well. There's the two sides of that. We've been pumping some of our frac, both in Hackberry Draw and Monument Draw. We've been pumping a smaller job, approximately 2,000 pounds per foot
As indicated by these results, those fracs [audio distortion] did initial rates. 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 cluster efficiency while increasing our stage length. With the end result there is a lower cost. We're making great wells, lower our cost through our efficiencies, drilling in multi-well pads throughout the rest of 2018 and into next year, which further adds efficiency to our operations and decreases cost. Those are the key points that we're really focused on, Ron.
Great. One last one on West Quito. Are your first five wells you're drilling, what zones are you targeting out in that well?
Those five wells are targeting the Wolfcamp, Upper Wolfcamp interval.
Thank you very much.
Our next question comes from David Beard with Coker & Palmer.
Good morning, gentlemen. Most of my questions have been answered, so I just had a follow-up on the Salt Creek timeline relative to timing. If it comes in the fourth quarter, will you be able to move all your oil through that theoretically, or is there some restrictions?
When it's available, we'll have a full allotment available to ship.
Okay, good. Thank you. Congratulations.
All right.
Next, we'll go to Vivek Pal with Seaport Global.
Yeah. Good afternoon. Good morning, guys. Could you give us a sense of timing and potential value of the midstream asset? Is $300 million a realistic for the whole base?
Gee, whiz. We wouldn't sell it for that, period. That's a crazy low number.
in terms of timing-
Timing wise, you're looking at a month or a month and a half before we winnowed the interested parties down to the real interested parties. Another month and a half or so to finalize paperwork and maybe a bit longer to close. It closed certainly late third quarter, early fourth quarter, something like that.
Do you believe-
Yeah, 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? Just to be putting our numbers in, is taking on more debt an option to kind of burn?
Let me answer a question you didn't ask. Ask if we have intention to place any equity. We have no intention to place any debt other than our normal and appropriate use of our revolver, which is undrawn at this time, as you know. Yes, we have a plan that allows us to proceed without that sale, and it just enhances our plan if we make that sale. Got a lot of interested parties. We won't be forced to go to any other alternative. If we choose to, we'll do so because of just common sense. First off, take that $300 million thing and erase it off your sheet.
All right. Okay. [audio distortion] on that is $400, $500 a realistic number, or you don't want to speculate at this time?
We've had a lot of experience in infrastructure building and sales. It's been sort of a fact in our business for years that the toll roads leading from your well bore to the markets are more valuable sometimes than the end piece of the asset in terms of EBITDA multiples. That seems to be the case today. I wouldn't be interested in selling it even at $400 million. You're just way low. I mean, I haven't reported any numbers on EBITDA from that business, but we're certainly not getting any value in our share price for that. It's hard to say. The market will speak as it does with everything. I don't want to sculpt anybody 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 perfect. In terms of limitations on drawing on your revolver to fund cash burn, or is it for you to do any way you choose?
We have no limitations. We've got a, as you know, a 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 and buy a yacht or something, or something silly. In the course of business, we don't have any limitations.
Just-
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 a majority, or do you need everyone to agree with the amount? How does that work with you guys?
Hey, we have six banks in our credit facility, and different votes take different levels. We have some votes that are 50%, some two-thirds, and some 100%. I can assure you, there's only a few things that require 100%. This is not one of them. Our banks are well aware of our plan, and there's not going to be any issues at all with this. The pipe system, really, it doesn't the RBL either. That's purely based on our own set. We will not have any issues around that.
There's no voting required to draw the $200 million.
No, not to draw, no.
All right. Thank you very much.
Next we'll go to Stephen with Cowen.
Thanks for taking my call. Your commentary on the midstream is very interesting. Obviously, $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, 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 good outcome. We would think that some multiple of EBITDA that approaches a triple on how we trade would be a good outcome as well. Those are sort of ballparks ideas there. A double on our costs 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&C dropping to $10.6 million for West Quito Wells. Are you assuming in terms of differentials, does this assume like a 20 kind of differential once things are back to a normalized number or what?
Yeah, we use a blended differential that includes the near term, higher differential associated with Midland pricing, and then the longer term you get on the pipe to the coast, we'll be realizing a differential above 100%. Again, most of the economics of a type curve are dictated by the later years. The first six months versus the later years, it's right around 100% difference on oil. A type curve that's blending the near term and the long term.
Appreciate that. If I could quickly, can you tell us what capitalized G&A is? 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 expensed G&A, stock or cash expense? Thanks.
I have no idea what that even is. Do any of you guys know? Go ahead, answer.
Yeah. 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.
Okay. Thanks very much.
Conclude 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.
That will conclude today's conference call. Thank you everyone for your participation. You may now disconnect.