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Edited Transcript of JAG.N earnings conference call or presentation 1-Mar-19 4:00pm GMT

Q4 2018 Jagged Peak Energy Inc Earnings Call

DENVER Mar 7, 2019 (Thomson StreetEvents) -- Edited Transcript of Jagged Peak Energy Inc earnings conference call or presentation Friday, March 1, 2019 at 4:00:00pm 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

* David f. Eckelberger

Jagged Peak Energy Inc. - VP of Land

* James J. Kleckner

Jagged Peak Energy Inc. - President & CEO

* James R. Edwards

Jagged Peak Energy Inc. - Director of IR

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Conference Call Participants

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* Brian Kevin Downey

Citigroup Inc, Research Division - Director

* Gabriel J. Daoud

Cowen and Company, LLC, Research Division - Senior Analyst

* Irene Oiyin Haas

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* John C. Nelson

Goldman Sachs Group Inc., Research Division - Equity Analyst

* Leo Paul Mariani

KeyBanc Capital Markets Inc., Research Division - Analyst

* Michael Dugan Kelly

Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research

* Michael Stephen Scialla

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

* Paul William Grigel

Macquarie Research - Analyst

* Wei Jiang

Crédit Suisse AG, Research Division - Research Analyst

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Presentation

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Operator [1]

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Good morning. My name is Emily, and I will be your conference operator today. At this time, I would like to welcome everyone to the Jagged Peak Energy Fourth Quarter 2018 Earnings Call. (Operator Instructions) Thank you.

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, Emily. Good morning, everyone, and welcome to Jagged Peak Energy's Fourth Quarter and Full Year 2018 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, our EVP and Chief Financial Officer; Ian Piper, VP of Finance and Corporate Planning; and Dave Eckelberger, VP of Land.

Last evening, we issued our fourth quarter earnings release and our 10-K, both of which are available on our website at jaggedpeakenergy.com.

During our discussion this morning, we'll be referencing slides from the fourth quarter earnings presentation, which can be found on the Presentations 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 these 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 today's earnings call presentation. Our materials also include certain non-GAAP financial measures, such as adjusted EBITDAX, adjusted net income, adjusted EBITDAX margin, PV10 and organic PD F&D. We believe those non-GAAP measures provide comparison across periods of activity with other oil and gas operators. Discussion and reconciliation of these non-GAAP financial measures can be found at the end of our earnings release and our earnings call presentation.

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

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

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Good morning, everyone, and thank you for joining us on our fourth quarter and full year 2018 earnings call. I want to start this morning by thanking the entire Jagged Peak team for all their efforts in 2018. It was a successful year with increases in cash flow and significant repeatable operating improvements. The year started with transition as the company pivoted to a new leadership team, and as we took the reins from the filing team, and I'm thankful for tremendous set of assets they've together by capturing large contiguous blocks of acreage in the southern oily core of the Delaware Basin.

As we take their -- these assets into their next stage of development, we have worked hard to expand the technical talent and organizational capacity. By building out our team, we have the skill sets and staffing levels to further focus on building processes and best practices to better manage and drive efficiencies as we further move into the development mode. Throughout the year, the team has remained focused on our 2018's strategic initiatives. And by year-end, I'm pleased to say that we've ticked the box on each initiative. It truly was a team effort.

On Slide 3 of the earnings deck, we have laid out these initiatives and the progress or completion of the objectives during the year. I won't go through each of them individually, but I do want to touch on a few of the key accomplishments. From a technical standpoint, we successfully completed our acquisition and the integration of our 3D seismic data set throughout our acreage areas. This data will continue to be a key tool to inform optimal lateral placement in the program going forward. In addition to the 3D, we've acquired log and core data throughout the year, which has been essential in enhancing our understanding of the subsurface and how to best monetize the significant resource potential contained within our acreage. From an operational standpoint, both our drilling and completion scheme created efficiencies that reduced cycle times and allowed the company to do more with less.

Drill feet per day has increased by 9%, shortening the spud to release times and completed feet per day has increased by an impressive 44%. Our cycle times have decreased, the productivity of our wells did not. In 2018, our core development Whiskey River, Wolfcamp A wells continue to outperform similar wells drilled in 2017, in our provided type curve, which is shown on Slide 7. These items combined resulted in a reduction of our organic crude development F&D cost by 22% year-over-year.

Moving from 2018 results, we focused our attention to our 2019 program, which leverages many of our prior year gains to drive results in the coming year. On Slides 9 and 10, we've shown our 2019 guidance and the activity program highlights. As you can see from the slides, we plan to continue to keep our balance sheet strong, focus on capital efficiency and grow the asset base. We know that investor focus has shifted to a model of free cash flow generation, and that is one of our goals, but at the same time, recognize we're an early stage growth company that has a large inventory in high-quality locations that produce significant full cycle returns, even in low commodity price environment. With that in mind, we intend to rationally grow and develop these high-quality assets while keeping a sharp eye on the balance sheet.

Through many remunerations and slurry analysis over the past few months, we have presented a program that provides the best fit of growth, maintain balance sheet strength and focus on capital efficiency. Our operating teams spent significant effort in 2018 to enhance this capital efficiency and was tasked at the beginning of the year to go back and reevaluate everything, from process to well designs to service company selection, to ensure that we were doing everything within our control to provide more capital-efficient wells.

Net process, we identified and executed on line changes that provided efficiency gains and cost savings with our service providers and are already seeing significant enhancements in drilling and completion cycle times, as shown on Slide 11. As a result, we're projecting an average all-in per foot single well cost in 2019 of $1,250 per lateral foot, which includes drilling, completion and pad level equipment, a 15% decrease from the prior year. This reduction in developed capital allows us to complete more wells during the year with less capital than in '18, and still provide a 19% exit growth rate for oil in 2019, setting us up for a strong year in 2020.

As for capital allocation within our 3 areas, activity will be primarily focused in our Whiskey River area, which will provide 42 of the 54 expected operated wells fall in line during the year, all but 1 of our Whiskey River wells are planned on multi-well pads. In the Cochise area, we plan to bring on 7 wells during the year. And in the second half of the year, we will commence drilling a 9-well codevelopment pilot that is expected to come online in the first quarter of 2020.

Lastly, our Big Tex area, we plan to bring online 5 wells in a high-graded fairway of the acreage that was informed through our recently acquired 3D seismic data. Of these 5 Big Tex wells, 1 will target Woodford interval, which we are excited to go back and test that for our first successful test in 2017.

We will closely monitor the results of these 5 wells and we'll remain flexible in the back half of the year to reallocate capital for up to additional 7 wells to further hold the delineated fairway. These additional 7 wells will only be planned if the results from the initial prove to be competitive in our portfolio.

So in closing, our 2019 program hones in on the core competencies of our team to successfully execute operationally and create efficiency in all aspects of our business. By leveraging these competencies, our planned program provides rational growth, protects our financial strength, increase value even in the low commodity price environment. If and when commodity prices increase, we will be able to retain these efficiencies to bring forward the point of cash flow neutrality.

As we continue to grow our early-stage company, we will strive to consistently prove capital-efficient growth while keeping the balance sheet strong at under 2x leverage in a $50 per barrel commodity price environment. By executing on these goals, we believe that we can efficiently get the size and scale where we can provide organic, sustainable free cash flow to our investors. By keeping our focus on financial strength and capital efficiency, I have the utmost confidence that our team and our acreage will provide competitive long-term growth and value to its shareholders.

And with that, I'll open the call up for questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Your first question comes from the line of Gabe Daoud with Cowen.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [2]

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Maybe just starting with 2019. I think one of your rigs rolls off contract at the middle of this year. So I'm assuming the budget, I guess, does assume the rig is retained throughout 2019. But how should we think about, I guess, rig and crew activity beyond '19? Jim, as you mentioned, you kind of want to balance debt with growth and ultimately free cash flow generation. So how do we think about that moving into 2020?

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

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Thanks for the question. Our program in 2019 contemplates a 5-rig program throughout the year and essentially 1 frac crew. We may add additional spot frac crews to keep up with the pace of the (inaudible). What we're seeing is, as you see in some of the graphs, cycle time reductions across just about every rig and program we're running, whether it be drilling or completing. So our current plan is to run that rig set and frac fleet into '19. And then, we anticipate additional cycle time improvement throughout the year. And depending on how many wells per year that rig or frac fleet was generating, we would look forward at either 5-rig or 4-rig program or whatever we would optimize based off the amount of drilling and completion activity that could be accomplished with that fleet.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [4]

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That's helpful. So the goal, I guess, in '20 is maybe you get to -- as close as free cash neutrality or maybe even free cash positive as close as you could or?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [5]

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Yes, the goal is to balance moderate growth and deliver free cash flow as soon as we can. And the point in time that, that occurs is somewhat variant in price points. And we're looking at a time period that could be between 18 or 30 months, depending on what type of price stack we're looking at.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [6]

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Understood. And then, just as a follow-up. So in '19, you'll be testing a larger pad concept of 9 wells at Cochise. Could you just talk a little bit about the spacing and the codevelopment initiatives with the pad? And then, if larger pad sizes is something we should think about as Jag doing more on a go-forward basis?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [7]

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Yes, absolutely. We see the absolute requirement to start shifting to more concentrated development mode with pad development. So I'm going to turn the question over to Craig Walters, our COO, to dive into a bit about what the codevelopment would look like.

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [8]

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Yes. Thanks for the question, Gabe. This Craig Walters. Yes, at Cochise, what we're looking at is a 9-well development program. And that's going to consist of basically 3 well pads. We're going to test 3 different landing zones in that particular area, so we'll have the third Bone Spring and then 2 landing zones within the Wolfcamp A. We'll start executing on that program in the third quarter. With the drilling requirements there, we'll be drilling all the way into the fourth quarter where we'll start completions and have talks late fourth quarter or first part of 2020.

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Operator [9]

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Your next question comes from the line of Brian Downey with Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [10]

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One of the elements that obviously stood out in the release and the presentation, in particular, were the 2019 capital efficiencies with the CapEx down 11%, but turn of line is up 10%. Can you talk through the drivers, perhaps quantify how much of that is underlying service cost assumptions versus efficiency gains and some of the changes in the well designs?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [11]

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This is Craig Walters again. I'll turn your attention, Brian, I guess, to Slide 11 in the deck. Our execution team has done a fantastic job, not just in 2018, but the first part of 2019. As Jim alluded to, we sat that team down and gave them the exercise of looking at all of our lessons learned in 2018, especially on the completion side of our business and incorporating that into our go-forward program. As you look at the significant increase that we've had in completion efficiency, jumping from our 758 completed lateral feet in 2018 to the 1,400 feet that we've seen across the first 6 wells in 2019, again, that's largely due to some design changes. And those are some really big efficiency gains. You can imagine that those flow right through into our capital program. When you look at the $1,250 per foot number that we expect to spend in 2019, I would say the savings that we're seeing as compared to 2018, about 30% of that is vendor or service cost-related. And it's really difficult to break out the other 70% between design and efficiency. Those kind of go hand-in-hand. So that's kind of the split that I'd put on our $200 worth of savings from '18 to '19.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [12]

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Got it. And it looks like some of that is regional sand that you're now utilizing 100% of any other major line items on the service cost side?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [13]

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Yes, I mean, regional sand, we've been talking regional sand since May of last year. Again, the -- some of the big drivers are, we've changed up some working of the program, really the design rate that we're pumping out now is larger than what it was in 2018, and that's driving some of the cycle time efficiencies that you see there as well.

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Operator [14]

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Your next question comes from the line of Leo Mariani with KeyBanc.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [15]

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I was hoping you could give us a little bit more of your thoughts around the 2019 production guidance. Couldn't help but to notice that you got more wells that are being tied in line in '19 versus '18. But it looks like your production, certainly from a BOE per day perspective, is growing a lot less. Mix seem a little bit conservative. What are you guys modeling in there for Big Tex? Obviously, you've got your 5 operated wells plus a couple of others that are sort of non-op. Just trying to get a sense of kind of what's in there for Big Tex at this point.

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [16]

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Well, I think there are several factors that affect our production forecast for 2019. As we start shifting to larger pads, there will be some production delays that occur, and certainly, we'll be seeing in the second half of this year. As Craig mentioned, the 9-well codevelopment pad in Cochise, while the delay that won't see first production until the first quarter of 2020. And in Big Tex, the impact should be relatively small since we're not drilling many of our wells there, but we anticipate that the quality of those wells should be very strong. The Big Tex program is still around high-grading the fairway, integrating our 3D data set, multiple trades with offset operators to improve our understanding of the subsurface. And we're encouraged by moving to this area of Big Tex. So we'll anticipate decent wells there, hence the reason for allocating capital to that part of the program.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [17]

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Okay. That's good color. And I guess, you took this impairment in the fourth quarter around Big Tex. Just trying to get a sense of how many acres that you guys sort of wrote off that you're not going to get to here? And kind of what's the -- what's kind of the post-impairment total on the acreage that you have? And what do you think could expire here in 2019 and '20?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [18]

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Well, as we mentioned before, we did a lot of technical work and integrated all the seismic data set to identify that fairway. And we've identified and high-graded those specific areas that we want to go drill. This high-graded area is the focus for our Big Tex program. And the acreage associated with the impairment were essentially outside of that high-graded area with very near-term lease expiration. So we see what could potentially roll off by end of the year, several thousand acres approximately.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [19]

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Okay. And I guess, around that several thousand, does that just contemplate the 5-operated wells that you guys are going to drill and then a couple of these farmout wells, and that's going to be sufficient to only let another several thousand roll off this year?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [20]

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Yes, that's correct.

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Leo Paul Mariani, KeyBanc Capital Markets Inc., Research Division - Analyst [21]

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Okay. And I guess, just with respect to your 15% well cost improvement that you guys talked about, are you guys kind of there today on that improvement? Or is that expected to kind of get there on average kind of throughout the year?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [22]

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Okay. Thanks for the question. This is Craig Walters again. We're seeing really good performance here, the first 2 months into the year. And the $1,250 represents an average. But again, we're well on our way to hitting that target.

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Operator [23]

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Your next question comes from line of Irene Haas with Imperial Capital.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [24]

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I would like to have a little more clarity on your farmout. But firstly, can you give us a little estimate on how big the fairway is at Big Tex that you have isolated? And maybe a little more description on the farm-in arrangement. Is it going to cover the best of the area that you're going to end up giving away a little bit? So those are my basic questions.

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [25]

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Thanks for the question. Regarding the fairway, we've got it matched with the data that I've mentioned earlier. And we still have some verification work to do with the wells that we'll be drilling. So I'd rather not talk about what the size of the fairway is right now, other than -- we think it has great potential, especially as we move north, and the Big Tex acreage as you see on the map. Regarding the farmout, I'm going to have David Eckelberger talk to that as he was the one that worked that deal through the last several months.

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David f. Eckelberger, Jagged Peak Energy Inc. - VP of Land [26]

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Irene, Dave Eckelberger. The farmout encompasses a project area of about 3,200 gross net acres. And at the end of the day, after all the carried wells are drilled, the farmee would earn approximately 2,200 net acres. And there's some mechanisms that would reassign 50% of one of the DSUs back to Jagged Peak, and we would operate it. And then, we're also, as part of the farmout, we see the -- just around 400 net acres in that fairway from the farmee. So -- about 2,200 net acres is going out the door from Jagged Peak to this farmee.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [27]

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Okay. So 400 of your high-graded area will be given to the farmee?

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David f. Eckelberger, Jagged Peak Energy Inc. - VP of Land [28]

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No, we'll be receiving 400 net acres from the farmee.

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Operator [29]

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Our next question comes from the line of Betty Jiang with Crédit Suisse.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [30]

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Could you talk about what type of changes you're making in well design? And do you expect that to change how wells produce? And if not, what gives you the comfort that they won't have much impact on well productivity?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [31]

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Yes. Thanks for the question, Betty, this is Craig Walters again. As throughout 2018, our completions group especially did a lot of testing on multiple variables around the completion, whether that was cluster spacing, stage spacing, perforating strategy, sand and fluid loadings, really, to better understand kind of the key drivers and what drives well performance. As we wrapped up kind of the 2018 and we look back at a lot of that data, we were able to come up with a new completion design that we talked to again on Slide 11, and that's 2,000 pounds per foot sand loading, 50 barrels of water a foot, and 225-foot stage spacing. I think it's important to recognize that completion design is a continuous evolution, and we feel that we've landed on a good one, again, based on the data that we collected in 2018. But know that, that might change on a go-forward basis. But the team is really excited. And again, we've got 6 of these new pumps so far first part of the year, and we're seeing good performance from that.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [32]

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If I can ask, just following up to that, how many wells of such design did you do in 2018?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [33]

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Yes. So in 2018, again, it was a combination of multiple different design parameters, and so we didn't have any that were specific to this particular design that we're pumping today. But again, all those variables that we've changed, as we looked at the production performance of those particular wells is how we homed in on the current design that we're comfortable with.

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Wei Jiang, Crédit Suisse AG, Research Division - Research Analyst [34]

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Right. And second question, what do you need to see from the first 5 wells in Big Tex to make the decision on whether to move forward with the remaining 7? And where would you reallocate capital from?

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

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Well, what we're going to first see is what is the production performance from the wells, obviously. Flow rates will be very important. But another key parameter of that is what we will learn from drilling, log that information and our completion response. So we look at all of the information that we've received from the operations, integrate that in and map or change accordingly to try and continue to inform our decision. So it won't be just one specific thing, it will be a multitude of feedback that we did in drilling this area in the field.

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Operator [36]

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Your next question comes from the line of Michael Scialla with Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [37]

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I want to see if you have a rough estimate of how much acreage in Whiskey River and Cochise you feel like you've delineated at this point? And you mentioned you're doing the 9-well pad moving toward development-type drilling at the end of this year. Is 2020 going to be more of a development year? Or is there still a lot of delineation to be done in 2020 as well?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [38]

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Yes. Michael, this is Craig. Great question. I think we delineated a large portion of our acreage in both Whiskey River and Cochise, especially with regard to the Wolfcamp A. We did some additional testing of the Wolfcamp B and the third Bone Spring and even second Bone Spring in 2018. And so yes, as we fold all of those learnings into our go-forward program and as we transition into full development mode, we will fold those additional horizons in. And so even though we've talked about 9-well pilot in Cochise, we're also planning additional pilots in Whiskey River to be executed on. Some of those might occur later this year, but definitely first part of 2020, and as we fully move into that full development mode.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [39]

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Okay. And I want to see if you could talk a little bit more about the Woodford, maybe what you learned from that first well? What was the productivity? I know that was a real short lateral, but how did the production there look over time? And what you might do differently with the second well? Where the second well is going to be positioned relative to the first?

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

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Yes, so as we've gotten in the 3D seismic at Big Tex, the team has worked that really hard in conjunction with the first well that we drilled in 2017, and put together a really good location. It's a little bit to the east of the first well, and we actually spudded about 2 weeks ago. I believe it's almost on Valentine's Day. So really excited to see the performance on that. If you scale up the first test that we had in 2017 with regard to what portion of that lateral was in zone, it looks very encouraging. And with the 3D seismic that we have, we're going to be able to land and steer that well within the specific portion of the Woodford that we want to. And so we're really excited to see production performance on that well, probably late second quarter.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [41]

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With the farmout, I guess, are you going to -- are all those farmout wells going to be Wolfcamp A wells most likely? Or would the -- your partner there earn Woodford as well if it turns out to be successful?

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

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Yes, so our partner plans to drill Wolfcamp A and we've reserved all Woodford rights.

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Operator [43]

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Your next question comes from the line of Mike Kelly with Seaport Global.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [44]

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Jim, when you're talking about your longer-term vision for the company and kind of talking about moderate growth with free cash flow, I'm just curious to hear what your definition of moderate growth really pertains. And maybe just if -- give us some guidepost on how you're thinking about that?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [45]

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Thanks for calling in with the questions. At this stage, we have received pretty clear line of sight to a moderate growth range of 15% to 20%. That provides us the ability to move into the development mode and codevelop multiple zones, properly addressing the geo mechanics of how we would develop throughout the field and do that in a responsible way going forward. That provides significant amount of inventory in front of us organically. As we continue to appraise and test some of these other intervals, we anticipate in the core areas of our (inaudible) in Cochise and Whiskey River that, that's a very robust inventory and carry us forward with that type of growth rate for many, many years to come.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [46]

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Perfect. Does that -- the commodity price you're assuming in that is around a $55 environment? How should we think about that?

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

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We're budgeting at a conservative $50 today, and we used that in prior years. Given the volatility in the marketplace, we're going to stay conservative and try to grow our business around a $50 take. Obviously, if we see prices move up, we're going to try to capture that increased cash flow and address our multiple and not expand the program probably much more than what we're doing right now.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [48]

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Great. Maybe one more for me. And I don't know if you guys have kind of analyzed it this way. But I think one of the highlights of your report last night was your exit rate for '19, real strong. And I kind of surmised that it could've been stronger if you didn't opt to do this 9-well pad at Cochise, which obviously makes a lot of sense to do. But I wonder if you look at your Q4 number in '19, and you had elected to just continue with 2-well pads, how much higher could that have been, in your opinion?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [49]

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Mike, that's a good question. We didn't model that. So I hate to pull a number out and state that we would have exited at a number x percent higher. But I think if you imagine that we'll be putting 9 wells in the ground and not seeing first production from those wells, so first quarter '20, and those 9 wells begin in the second half of this year, you kind of scale up to a number. But you're exactly right, the conversion to codevelop pads is essential as we move forward to minimize future parent-child relationships. And we see that as being paramount to how we approach the development of these resources going forward.

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Operator [50]

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Your next question comes from the line of Paul Grigel with Macquarie.

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Paul William Grigel, Macquarie Research - Analyst [51]

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Could you provide some color and details on your current corporate decline rate?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [52]

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Paul, yes you asked about our corporate decline rate. So if you're referring to our current year PDP, I think we've illustrated that in the release of 45%, plus or minus 45% if you -- depending on where you're at in the development cycle and how many wells you had in the wedge versus in the base. That can vary depending on the program.

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Paul William Grigel, Macquarie Research - Analyst [53]

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Okay. And maybe a follow-up to one of the questions Mike was asking on. For HBP issues outside of Big Tex, how much of those issues drove some of the program's direction and spending for 2019?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [54]

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Yes, this is Craig Walters. So as we look at our 2019 kind of stuff that we had to drill outside of the Big Tex area, we do have some obligation wells up in Cochise, and we've got an annual requirement up there that it's based on lateral footage. So it works to 10 or 12 -- 10 to 11 wells a year. And then, we had just a handful within Whiskey River.

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Operator [55]

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(Operator Instructions) Our next question comes from the line of John Nelson with Goldman Sachs.

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John C. Nelson, Goldman Sachs Group Inc., Research Division - Equity Analyst [56]

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I wanted to follow up on Betty's question and just the decision around the potential 7 additional wells at Big Tex. Call it a high class problem, but I would imagine an incremental Whiskey River well is going to continue to have a superior IRR. So from a capital allocation standpoint, is there a particular breakeven or other kind of hurdle metric you all would like to see to make the call to go ahead and capture that Big Tex acreage?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [57]

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John, this -- to me, the decision to allocate capital or any further capital to Big Tex is going to be weighed heavily against the results of the rest of our program. And as you can see, demonstrated by our 2019 program, most of our capital is allocated into Whiskey River and Cochise, and very little is in Big Tex. And for Big Tex to compete with that high grade of a portfolio, we're going to have to see some pretty strong results to steer any capital down there. With that being said, we like the area and the field that we've moved to and we think it has the potential for upside, hence, we're allocating some capital to that program this year. So as I mentioned earlier, too, it will not only be the well results, but it will also be a look to see how much acreage in the fairway is extendable based off the results of the well, and does it compete in Jagged Peak's portfolio. So we'll be making those decisions not only based off of pure well performance, but also remaining inventory that may be available to us.

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John C. Nelson, Goldman Sachs Group Inc., Research Division - Equity Analyst [58]

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Okay. And then, just so we're clear, the expectation that you would then raise the budget if you decide to go ahead and do those wells? Or is there a -- yes, I guess, I'll just leave it open-ended.

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [59]

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No, we would not raise the budget. We would move capital from, say, Whiskey River wells to Big Tex. And we're going to be very, very cautious if we do that. Again, I want the reiterate that they're going to have to compete from an allocation standpoint and if we were to elect to drill any follow-on wells.

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Operator [60]

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Our next question comes from the line of Michael Scialla with Stifel.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [61]

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I just want to follow up and ask on -- it sounds like most of the 2019 plan is going to be drilled in Wolfcamp A. You've got the one Woodford well. And then, Craig you mentioned, in Cochise, you're going to do a few third Bone Spring wells. But any other intervals that you will be drilling this year?

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Craig R. Walters, Jagged Peak Energy Inc. - COO & Executive VP [62]

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Yes. Great question, Mike. Well, actually, as we look at our 2019 program, I think, it's important to point out, over 90% is going to be on multiple well pads. We've already talked about the 3-well pads up in Cochise. We've got an additional 3-well pad in Whiskey River that we're actually currently drilling right now. As we look at the zone breakout for 2019, it's about 60% -- 65% Wolfcamp A, 13% third Bone and then 20% or so Wolfcamp B. And we've done some additional delineation work in 2018 and are fairly encouraged with what we see with the Wolfcamp B and the third Bone and Whiskey River. And so we've added some of that to our program as well. And again, that's really just a natural transition into the full-field development. And instead of stacking wells laterally, if you will, or horizontally, I can assure you that we're doing it vertically and preserve our option to come back in and develop from a block or key perspective the rest of the DSU at a later time.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [63]

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Okay. And then, last one for me. Have you settled on spacing now at Whiskey River in Cochise, at least in the Wolfcamp A? And if so, what spacing are you thinking?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [64]

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Yes. Again, we've tested a lot of 660 spacing the past couple of years, not just in Wolfcamp A, but in a couple of the other horizons that we have, as well as stack stagger across the different horizons. I would say, as we look to move into full-field development, and especially this first Cochise product that we've talked about, that spacing is going to be on 880-foot laterally. So a 4 41 wrap between those 3 intervals that I talked about earlier. And so again, we're stepping into it cautiously. I want to make sure that we don't overcapitalize and then take any lessons that we learn here and apply those on our go-forward program.

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Michael Stephen Scialla, Stifel, Nicolaus & Company, Incorporated, Research Division - MD [65]

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Okay. I guess, I lied. I had 1 more. Just kind of curious why you decided on the development in Cochise when you've allocated most of your capital, it looks like Whiskey River is giving you your strongest returns. Any particular reason you decided to start with the development project there rather than Whiskey River?

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [66]

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Yes. Michael, as I alluded to, we have an annual drilling obligation up in our Cochise area, that's 10 to 11 wells. And so, yes, this fit really well. We've been able to take a half DSU that hasn't had any wells in it. The nearest well is about 0.25 mile away. And so, yes, this really fit the bill from kind of meeting our requirements on drilling obligations up there as well as getting our first pilot in on full-field development.

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Operator [67]

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There are no further questions at this time. I will turn the call back to the presenters.

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James J. Kleckner, Jagged Peak Energy Inc. - President & CEO [68]

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Well, thank you for participating in the call. And we look forward to seeing you in the upcoming conference sessions. And thank you again for your time with Jagged Peak.

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Operator [69]

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