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Edited Transcript of JAG.N earnings conference call or presentation 10-May-19 3:00pm GMT

Q1 2019 Jagged Peak Energy Inc Earnings Call

DENVER May 20, 2019 (Thomson StreetEvents) -- Edited Transcript of Jagged Peak Energy Inc earnings conference call or presentation Friday, May 10, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Craig R. Walters

Jagged Peak Energy Inc. - COO & Executive VP

* Ian T. Piper

Jagged Peak Energy Inc. - VP of Finance & Corporate Planning

* James J. Kleckner

Jagged Peak Energy Inc. - President, CEO & Director

* James R. Edwards

Jagged Peak Energy Inc. - Director of IR

* Robert W. Howard

Jagged Peak Energy Inc. - Executive VP & CFO

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Conference Call Participants

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* Biju Z. Perincheril

Susquehanna Financial Group, LLLP, Research Division - Analyst

* Brian Kevin Downey

Citigroup Inc, Research Division - Director

* Jiuying Ye

Imperial Capital, LLC, Research Division - Associate

* Leo Paul Mariani

KeyBanc Capital Markets Inc., Research Division - Analyst

* Michael Stephen Scialla

Stifel, Nicolaus & Company, Incorporated, Research Division - MD

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Paul William Grigel

Macquarie Research - Analyst

* Scott Michael Hanold

RBC Capital Markets, LLC, Research Division - Analyst

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Presentation

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Operator [1]

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Good morning. My name is Christina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Jagged Peak Energy First Quarter 2019 Earnings Conference Call. (Operator Instructions) James Edwards, Director of Investor Relations, you may begin your conference.

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James R. Edwards, Jagged Peak Energy Inc. - Director of IR [2]

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Thank you, Christina. Good morning, everyone, and welcome to Jagged Peak Energy's First Quarter 2019 Earnings and Operational Update Conference Call.

With us on the call today are Jim Kleckner, CEO and President; Greg Walters, EVP and Chief Operating Officer; Bob Howard, EVP and Chief Financial Officer; Ian Piper, VP of Finance and Corporate Planning; and David Eckelberger, VP of Land. Last evening, we issued our first quarter earnings release and our 10-Q, both of which are available on our website at www.jaggedpeakenergy.com.

During our discussion this morning, we'll be referencing slides from our May investor presentation, which can be found on the Presentation page, under the Investor Relations section of our website.

During this call, we'll make certain forward-looking statements about the company's financial condition, results of operations, plans, objectives, future performance and business activities. We caution that our actual results could differ materially from the results that are indicated in these forward-looking statements due to a variety of factors. Information about these factors can be found in the company's SEC filings and on Slide 2 of our May investor presentation. Our materials include certain non-GAAP financial measures, such as adjusted EBITDAX, adjusted income and adjusted EBITDAX margin. We believe these non-GAAP measures provide a comparison across periods of activity and with other oil and gas operators. Reconciliation of the corporate GAAP financial measures to the non-GAAP financial measures can be found in our earnings release and earnings call presentation.

I'll now turn the call over to Jim for his review of the quarter.

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [3]

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Good morning, everyone, and thank you for joining us on our first quarter 2019 earnings call. Our prepared remarks this morning will focus on progress we've made in well cost reductions and changes to our 2019 program, which now focuses more on large-scale pad development.

First, I'd like to go through the strides we have made from a capital efficiency standpoint, as we are well on our way to meeting our goal of reducing DC&E cost for the year by 15%. By the end of the first quarter, we've seen a 10% reduction in those costs, which are now approximately $1,300 per lateral foot. Our goal for 2019 is $1,250 per lateral foot, down from $1,450 in 2018.

The savings we have captured this year are largely a result of decreases in service cost and changes to our well design, which have allowed us to capture efficiencies and decrease cycle times.

Over the past several months, we've entered into new agreements with some of our service providers that reduced costs on goods and services. In addition to these savings, we have made changes to certain aspects of our completion design at the beginning of the year, which were based off of multiple field tests conducted in 2018 designed to improve well results and capital efficiency.

Some of these changes included adjusting sand and fluid volumes, modifying stage length per clusters per stage and pump rates to reduce overall pump times and completion costs.

As we continue our 2019 program, we remain diligent on driving these costs down further and remain confident in our ability to meet our 2019 activity program within our guided capital range.

Next, I'd like to go through our production profile for the year and changes in our forecast since our last update. Our first quarter oil volumes came in within 100 barrels a day of guided midpoint. Our oil equivalent production ended up being at the lower end of the guide. This was due to changes in our NGL recoveries. While we are in ethane recovery throughout most of the quarter, a larger portion of our gas [to] a different gas plant saw lower NGL recoveries, changing our production mix and reducing our oil equivalent production. Going forward, we [affected] this lower coverage into our guidance.

As we move to the second quarter, we're forecasting a modest increase in production volumes in the first quarter due to change in the timing from larger pads brought online, which I will detail in a moment, but also due to some greater than expected power outages that we had in April, caused by high winds.

We take into account weather-related downtime in our production forecast but the power outages experienced during April exceeded the forecast, creating a headwind for second quarter growth.

While the timing of the volume growth throughout the year has shifted, we remain confident in our fourth quarter and full year production guidance range.

On the cost side, we saw an increase to our LOE per BOE from the fourth quarter of 2018, which came in on the high side of our full year guided range of $3.65 to $4.15 per BOE. This increase was caused by workovers in the field, which had extended [fishing] jobs with associated cost of over $100 million -- excuse me, $1 million. Since these were normally non-reoccurring events, we are confident that our operating costs for the year will be well within our guidance range. As I mentioned earlier, we have made some change to our drill schedule to increase the number of larger pads in our program in 2019.

On the fourth quarter call, we announced that we would be executing our first large-scale codevelopment pad with 9 wells in Cochise during the second half of the year.

Since then, we have reworked the program and moved well locations that were originally scheduled to be 2 well pads to create larger scale codevelopment pads.

By condensing some of these pads originally planned throughout the acreage, we will now be executing on 2 large pads in Whiskey River and 1 in Cochise.

Locations and gun barrel [plots] of these projects are included on Page 16 of our May investor presentation.

The first of these, our Coriander pad, will include 6 wells and will be targeting the third Bone Spring, Upper and Lower Wolfcamp A and Wolfcamp B in the southern part of Whiskey River. We recently started work on this pad and expect it to come online in the third quarter. From a logistical standpoint, we're putting 3 rigs to work, each drilling 2 well pairs and anticipate bringing in 2 completion crews to refract these 6 wells.

By drilling and completing these wells with multiple rigs and completion crews, we can effectively reduce the spud to sales time of the project, decreasing operation delay, risk and increasing the project IRR.

After completion of Coriander pad, we will move north to our Venom pad in the heart of Whiskey River. This pad will have 8 wells targeting the third Bone Spring, Upper and Lower Wolfcamp A and Wolfcamp B. This pad is expected to be spud in the third quarter and come online in the fourth quarter, utilizing multiple rigs and crews, similar to the Coriander project.

To finish up the year, we plan to spud a 9-well pad in Cochise, targeting the third Bone Spring and Upper and Lower Wolfcamp A in the fourth quarter, which is expected to come online during the first quarter of 2020. We're excited to get back to Cochise to drill a follow-up third Bone Spring well [to developing] 5HX well that was completed during the first quarter. As you can see on Page 15 of our May investor presentation, this will have a peak IP30 per 1,000 feet at 244 BOE per day and assume 163,000 BOE on a 2-stream basis after 110 days, which 44% outperforms the type curve.

This well also recorded the highest IP30 flow rate for our company of 2,517 BOE equivalent per day, with an 81% oil cap.

By consolidating some of our 2-well pads into larger pads this year, we'll be able to fast track our learnings on well interaction [in bounded] test, both horizontally within the same zone, but also vertically between multiple horizons. This data will be invaluable as we continue to refine our assumptions for full field development.

In addition, we will develop a larger section of the resource all at the same time, improving our capital efficiency, section recoveries and long-term valuation of the assets.

So we look forward to executing on this revised program in 2019 and providing results to you as we get them. I will now turn the call over to the operator for the Q&A portion of our call.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Scott Hanold from RBC Capital Markets.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [2]

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A question on the decision to sort of pivot to some of these larger pads sooner. Was there something that you all saw during the quarter that made you wanted to do the shift sooner than later? And could you give us a little more color on specifically with, say, what's the cycle time from a sort of 2-well pad would be to what you're going to need in more like 4, 6 kind of well pads?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [3]

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Right. Good morning, Scott, and thanks for the question. I'll take first part of it and then I'll pass it over to Craig to answer the second part of the question. The first part of your question, what was the decision for us to shift over to pads. We had been running a lot of field trials tests in 2018 on paired well tests and had been forming opinions about shifting over to pad developments. And as we progressed throughout the second half of 2018 and in 2019, saw really the success of some of those paired testings and wanted to accelerate and combine more concentrated development on larger scale pads to capture more capital efficiency, cost savings by shared infrastructure. And so it was really a plan that started last year that we were working to, and it was a question of timing and when do we have enough technical information from resource test that we've been running that gave us confidence to move in that direction.

So regarding the cycle times on the pads, I'll let Craig handle that portion.

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [4]

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This is Craig Walters. Regarding the cycle times, really, as we look at these initial pads that we're going to do, they still are 2-well pads. So even though on the Coriander, it's a 6-well project or pilot, we're going to have 3 rigs that are working there concurrently on 3 separate pads that are 2 wells a piece.

And so from a cycle time standpoint, it takes us approximately 30 days for a well to do the drilling operations, and so we'll do all that concurrently across those 3 pads, get those 6 wells knocked out. And then we'll have just a short gap in there before we begin completion operations. And Jim alluded to it in his opening remarks, kind of around the Coriander pad, we actually spud that. And here recently, we'll have that -- those 6 wells topped in the third quarter. We'll be moving to the Venom. Those will top in fourth quarter. And then, our Cochise project, actually, we have 3-well pads, so 9 total wells, and those tops will happen in first quarter of 2020.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [5]

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Okay. And just to follow on next question. On the NGL recoveries, you mentioned that we're a bit lower there, and I think that's the expectation going forward. Can you specifically say why that is? Was it a -- was the facility -- it sounds like you might have switched to a different facility that wasn't -- didn't have a stronger recovery. So can you give a little color on what the changes there were?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [6]

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Yes. We [sail] into the target gathering. We may have multiple plants that they allocate that gas production to. Ian Piper, our Head of Marketing, can comment further on those allocations teams and what happens once the target collects the gas.

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Ian T. Piper, Jagged Peak Energy Inc. - VP of Finance & Corporate Planning [7]

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As Jim mentioned, there's a number of plants out in the field that we deliver into. And we don't have a lot of control on which plant our gas goes into, that's (inaudible) target. But we saw -- we were [spending] more gas to some of the older, less efficient plants out there that led to the lower recoveries in the quarter.

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Scott Michael Hanold, RBC Capital Markets, LLC, Research Division - Analyst [8]

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Okay. So with the -- and I know you can't speak on the target's behalf, but what made -- why did your volumes go to less efficient [plants] before the others? Is it the other operators have some priorities that get them into the better plants? Or what is -- what goes on there?

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Ian T. Piper, Jagged Peak Energy Inc. - VP of Finance & Corporate Planning [9]

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No. I don't think it's really related to other operators with more priorities, it's just how they manage the system and move the volumes around, ensure that everyone can move their gas out there.

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Operator [10]

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Our next question comes from Brian Downey from Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [11]

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Just a follow-up there on the NGL and specifically on the realizations. I know 1Q wasn't great in general for industry NGL pricing. But was curious, was ethane a larger portion of the stream? Is there anything going on there on the NGL realization?

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Robert W. Howard, Jagged Peak Energy Inc. - Executive VP & CFO [12]

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This is Bob Howard. Ethane recoveries probably hadn't changed fourth quarter to the first quarter. More of this is related to what's being presented in the financials under the new revenue standard. If you look at the components on the first quarter, we actually received about 17 40 for our NGLs, but netted against that, about $7.90 is GTP cost and because we sell at the wellhead and it gets all backed up to the sales price that we have. The 17 40 is about 18%, 20% down from the fourth quarter of last year.

So it's kind of what we saw, kind of an overall general decline in NGL prices in the market. And the $7.90 per barrel of GTP cost that we kind of have charged against after the quarter is kind of aligned with what we had last year of $7.30 per barrel. It is up a little bit more from what we would have incurred in the fourth quarter of about $5.70. So break the parts of the components into they -- kind of align. They're just -- because of the netting or the leverage you have on the fixed cost where the sales price comes down, again, it shows a price that changes more on the absolute net price that we get than we actually are seeing in realization of the cost that we get recorded back to the volume.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [13]

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Got it. Makes sense. And then maybe one on Big Tex and the Woodford test. I know -- I believe you TD-ed the well about a month ago, so I understand it will be too early for any production results or data. But curious if you saw anything that surprised you as you were drilling. Maybe anything versus the 3D data, or any comments you can share? You drilled and completed the well?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [14]

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That's right. We TD-ed the Big Tex well and everything went fine from a drilling standpoint. Obviously, having our 3D seismic in-house and fully [interpreted] gave us confidence on the placement of that well, and the well drilled in zone and we're very excited about the fact that we're seeing the full section of the Woodford. The well has been completed and it will be in the process of [flowing] back here and we'd be happy to update you on the results of that well probably at the next quarter's call.

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Operator [15]

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Our next question comes from Neal Dingmann from SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [16]

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Jim, you guys have done a nice job of lining up this stable plan. I guess my question, cognizant of not having 2020 guidance out, maybe just talk about how you go into the end of the year and sort of progress in next year. Do you sort of see the same stable plan as you have set in place, which I think makes a lot of sense? Do you see that continuing into next year. I guess that, or maybe how you end the year with (inaudible). I'm just trying to get a sense of maybe trajectory or something like that towards year-end?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [17]

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Right. No, thank you, I appreciate the question. And you're exactly right, we think of it is a long-term stable or we sometimes call base-loaded plan that really allows us to develop the partnerships and relationships with the service providers so that we can get consistent repeatable results and deliver the most lowest cost, capital-efficient investment in the resource that we can.

From that standpoint, our plan is to maintain our capital program that we have highlighted this year with the rig schedule that we have. And we adopted a conservative budget based off of $50 TI, and we'll use that going forward, unless obviously the market changes dramatically in 2020. So with that being said, we're focusing on that breakover point of cash flow [neutral] here within 16 to probably 30 months, depending on what the price is in the out year. But we maintain our 2019 program and we'll plan on carrying that forward in 2020 very similarly.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [18]

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Got it. Great answer. And then one last one, just -- I forgot what slide, if it's Slide 6 or one of these I'm looking at. It just shows your improved efficiencies. I guess what I'm getting at, you continue to do that now, I guess, as you're in this more development mode. Is that through more just B and C efficiencies or operating efficiencies or is it a combination of that plus service cost, I'm just wondering -- and where the bulk of that improvement is coming from and do you see that continuing?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [19]

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Right. I'm going to let Craig answer that. His group's done a fantastic job on our drilling and completions team and really driving these costs down and improving some of our overall well results. So Craig can comment more precisely on that.

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [20]

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Yes, Neal, you're probably referring to Slide 11, I guess, in the slide deck that we put out there. And really, the talk to the drilling and completion efficiencies that we have, they've been significant through kind of year-to-date, especially as compared to where we were in 2018. On the drilling side, our footage per day per rig is up 13%. But more substantially, really, on the completion side, from a footage per day basis, we're up 86% from where we were in 2018. Those efficiencies that we're seeing are largely driven by the changes in our completion design. I think we've talked about it in the prior quarter. We did a lot of field tests and pilots in 2018 and really rolled all of our learning from those particular field pilots into our 2019 frac design, which I'll say is a continual evolution. But that's really what's driving the increased footage per day on the completions. And you can just imagine if that translates directly to the cost side.

And so as we look at the 2019 program and we put our target out there that we think is very achievable, this $1,250 per lateral foot for DC&E, again, we made some significant progress on that through the first quarter. As we look at those total savings, I think we've chalked it up to about 30% is service cost-related and 70% is efficiencies. And again, we've gained a lot of those efficiencies in the first quarter, but we expect to build on those throughout the rest of the year.

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Operator [21]

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Our next question comes from Michael Scialla from Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [22]

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With the codevelopment, it sounds like you're going to do a lot of testing, but as you head into that, I wanted to get your perspective on how you're looking at these different zones? Do you see there's one system or are discrete reservoirs here? And if they are discrete, where do you see the barriers?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [23]

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Michael, great question. This is Craig Walters again. As we look across a large portion of our acreage position, we do view, I'll say, third Bone Spring through Wolfcamp B as a single system for the most part. We have done a lot of testing again throughout 2018, as we did 2-well pads that were 660 spaced, some of those were staggered. We've learned a lot through that program. We've incorporated a lot of those learnings into these development pilots that we are going to move forward with starting with the Coriander, then the Venom and the Cochise. And so yes, we view those as kind of a single reservoir system, which is why you see kind of that gun barrel plot that we demonstrated in the slide deck.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [24]

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Yes, and looking at that slide, the fact that you're going to 440 stack-stagger in the Venom and 660 in the Coriander, does that mean that's what you think is appropriate for those areas? Does the geology change to where it necessitates wider spacing further south? Or is that just still something that's in a testing phase?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [25]

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Yes, really, what drives the Coriander being set up on kind of the 1,320 interzone or interlanding and the 660 stack-stagger, it's really driven by that area of the field. It's really just a half of a DSU that we have down there available to us with our acreage. And as we looked at some of the existing wells that are on our acreage and [offset] to us, we felt that, that 1,320 in-zone spacing was most appropriate. Again, as we move into Venom and the Cochise, we'll be doing those at 880, 440 stack-stagger. And so I think it just was kind of where we were at on the Coriander, kind of what we felt comfortable with from the spacing down there. And obviously, get some learnings before we roll that into kind of the 880 programs the rest of the year.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [26]

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Got you. Okay. And then you had previously talked about the flexibility with Big Tex where you could add another 7 wells this year if you like what you saw in the first 5. I'm wondering, is that still possible? Or is that less likely now that you've committed to these larger projects? And if that did that happen, I guess, would you still reallocate from -- most likely from Whiskey River?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [27]

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That's a question. We're also looking at other methodologies, for instance, if we decide that the results of the 5 wells warrant further drilling, we could look at further farm-out or further funding opportunities for those wells down there. Preferably, we'd like to stay within our capital allocation, that's the plan that we're working on. So we'd probably require some movement of wells out of the program. I don't think we'd interrupt any of our pad developments we have planned.

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Operator [28]

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Our next question is from Leo Mariani from KeyBanc.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [29]

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So just to follow up a little bit on Big Tex. Have you guys seen any kind of recent offset operator activity, maybe in and around your acreage which might give you some more confidence on the plan here in 2019?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [30]

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Yes. This is Craig Walters. It's a great question, Leo. As we look at some of the decks actually that came out for this quarter, I know we partially talked about some wells that are fairly close to our Big Tex acreage. As you look at those 2 particular wells, they're very close to kind of our high graded area where we put one of our Wolfcamp A wells that has been on production for about 30 days now. It's too early to kind of predict what that's really going to look like.

But yes, so we're excited about what we see from some of the offset operators. I think what drives some of the production performance in Big Tex is obviously how much [pay] that you have, but also pressure is a key component of overall performance. And again, that's some of the technical work that we put together and how we got to our high graded area for the Wolfcamp A that we're testing this year.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [31]

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Okay. That's helpful. And I guess, just looking over at the cost side of things, I mean, it surely sounds like you folks have come in a little ahead of expectations there. I know you got to target it at $1,250. Do you see potential to maybe move lower than that $1,250 either late this year or into 2020? Maybe you see potential for some more efficiencies to reduce those costs?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [32]

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I think as we look at where we're at today and some of the stuff that we have in front of us, it's hard to predict that we might come in on average less than the $1,250. Obviously, our teams are focused every day on continuous improvement and trying to drive additional cost out of the system and improve our overall capital efficiency. So that's our goal, but it's hard to put a number on that today.

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Operator [33]

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Our next question comes from Paul Grigel from Macquarie.

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Paul William Grigel, Macquarie Research - Analyst [34]

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One real quick follow-up just on that point. If you're coming in better than you expect on the capital efficiency at the end of the year, could we expect kind of frac holidays and sticking on to the plan to the earlier completions you mentioned in 1Q '20 kind of sticking to that point? Or is there any appetite of kind of trying to keep operational momentum going in that balance?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [35]

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I think that's something that we'll just kind of monitor our performance on as the year progresses and kind of make that call in fourth quarter.

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Operator [36]

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(Operator Instructions) Our next question comes from Biju Perincheril from Susquehanna.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [37]

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Just a couple of questions. Going back to the multi-zone developments, and this might be a little too early without having any results yet. But as you sort of look into 2020, if the results come in as you expect, any early reading to what percent of your program in next year could be this type of multi-zone development projects?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [38]

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That's a good question. I think it's perhaps a little too early right now to make a forecast on what percent would be multi-well pad development in 2020. But I will say this, we see the pad development, Q development as referred to by some operators, as a are more efficient way to go to full field development. And certainly, our objective would be to migrate towards a majority of our program in a full field development pad mode. That being said, we do have some alternative horizons that have not been tested yet in our reservoir system, and we may have some further appraisal that occurs. So not all of the wells in the out years would be targeted for large pad developments.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [39]

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Got it. And maybe as a follow-up to that. Do you expect additional cost savings? It sounded like you're still drilling mostly 2-well pads in this multi-zone projects also? But just do you expect some more efficiency gains and any way to quantify that?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [40]

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Biju, this is Craig Walters. I think as we look at these development projects we've got coming up on the Coriander, Venom and Cochise because they are still relatively small pads, 2-well pads and/or 3, we don't expect to see a lot of those cost savings until we get through something that has maybe 4 to 6 wells per pad, and we really don't have any of those in our outlook at this point in time.

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [41]

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Got it. That's helpful. And then one last question for me was your fourth quarter guidance that you gave on the last call, any update to that given some of the schedule has been reshuffled?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [42]

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I think your question was, any update to the full year guidance for 2019?

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Biju Z. Perincheril, Susquehanna Financial Group, LLLP, Research Division - Analyst [43]

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The fourth quarter exit rate.

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [44]

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No. We still believe we're on track to achieve the fourth quarter exit rate that we talked about in our last quarter update.

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Operator [45]

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Our next question comes from Michael Scialla from Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [46]

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Yes, just want to follow up on, Jimmy mentioned, if you were to expand Big Tex this year because of positive results, you'd look at farm-outs or other sorts of funding. I'm wondering, where would monetizing a portion of the water midstream rank as a possible source of funding?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [47]

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That's a good question. We're getting asked that quite a bit, Michael, I appreciate that. We've looked at the valuation of that business and believe, at some point in time, it may be worth considering the portion of the sale of that or the potential moving out of that. But right now, it's so integral to our operations. The efficient movement and logistics of both water sourcing and water disposal is absolutely critical need to the operation. We think it provides a tremendous amount of value enhancement to what we're doing right now. So we would not have any plans directly to monetize the water business.

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Operator [48]

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Our next question comes from Irene Haas for Imperial Capital.

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Jiuying Ye, Imperial Capital, LLC, Research Division - Associate [49]

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This is Claire Ye from Imperial Capital. The first question is a follow-up on NGL. So should we expect the same sort of revenue recognition measure going forward as well as the GPMT deduction?

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [50]

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[Strictly in terms of] planning purposes, simply, that's the -- we've seen this quarter kind of align with what we had to the full year last year.

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Unidentified Analyst, [51]

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And the second question is, could you update us on the well cost for the -- on the pads you're planning for Whiskey River and Cochise?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [52]

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Yes, those well costs, I mean, they are based into that $1,250 per lateral foot. So as you look at that on a 9,000 foot average well, it's roughly $11.3 million.

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Operator [53]

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There are no further questions at this time. I turn the call back over to Jim Kleckner for closing remarks.

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James J. Kleckner, Jagged Peak Energy Inc. - President, CEO & Director [54]

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Thank you again for joining us on the call this morning. And we look forward to answering your questions and taking your feedback at one of the many conferences we have in the upcoming months.

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Operator [55]

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This concludes today's conference call. You may now disconnect.