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Jagged Peak Energy Inc.  (NYSE:JAG)
Q4 2018 Earnings Conference Call
March 01, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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's Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) Thank you.

James Edwards, Director of Investor Relations, you may begin your conference.

James Edwards -- Director of Investor Relations

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, our CEO and President; Craig Walters, EVP and Chief Operating Officer; Bob Howard, our EVP and Chief Financial Officer; Ian Piper, VP of Finance and Corporate Planning; and Dave Eckelbarger, 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 will 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, PV-10 and organic PDF&D. We believe those non-GAAP measures provide a 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.

James J. Kleckner -- President and Chief Executive Officer

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 big leadership team, and as we took the reins from our selling (ph) team, I'm thankful for the tremendous set of assets they've put together by capturing large contiguous blocks of acreage in the Southern oily core of the Delaware Basin. As we take 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 strategic initiatives and by year end, I'm pleased to say that we can check the box of each initiative, it truly was a team effort.

On Slide 3 of the earnings deck, we have laid out these initiatives in 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 integration of our 3D seismic data set throughout our acreage areas. This data will continue to be a key tool to form optimal lateral placement and 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 completions team gain created efficiencies that reduce cycle times and allow the Company to do more with less. Drilled feet per day has increased by 9%, shortening the spud, the lease (ph) times and completed feet per day has increased by an impressive 44%.

Our cycle times have decreased, the productivity of our well has not (ph). In 2018, our core development Whiskey River, Wolfcamp A wells continued to outperform similar wells drilled in 2017 and have provided type curve, which is shown on Slide 7. These items combined resulted in a reduction of our organic proved developed F&D cost by 23% year-over-year.

Moving from 2018 results, we focus our attention to our 2019 program, which leverages many of our prior year gains to drive results in the coming year. On Slide 9 and 10, we've shown our 2019 guidance and 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 of 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 iterations and slurry (ph) analysis over the past few months, we have presented a program that provides the best bit of growth, maintain balance sheet strength and focus on capital efficiency. Our operating team spent significant effort in 2018 to enhance this capital efficiency and were tasked at the beginning of the year to go back and reevaluate everything from process, to well designs, to (inaudible), ensure that we were doing everything within our control to provide more capital efficient wells. In that process, we identified and executed on the 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 into 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 development 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, there are three areas. Activity will be primarily focused in our Whiskey River area, which will provide 42 of the 54 expected operated wells brought on line during the year, although one of our Whiskey River wells are planned on multi-well pads. In the Cochise area, we plan to bring on seven wells during the year and in the second half of the year, we will commence drilling a nine-well co-development pilot that is expected to come online in the first quarter of 2020.

Lastly, our Big Tex area, we plan to bring online five wells in a high graded fairway of the acreage that was informed through our recently acquired 3D seismic data. Of these five Big Tex wells, one will target Woodford interval, which we are excited to go back and test that after our first successful test in 2017. We will closely monitor the results of these five wells and we'll remain flexible in the back half of the year to reallocate capital for up to seven additional wells to further (inaudible) fairway. These additional seven wells will only be planned if the results from initial prove to be competitive in our portfolio.

So in closing, our 2019 program (inaudible) on the core competencies of our team to successfully execute operation 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 a low commodity price environment. If and when commodity prices increase, we will be able to retain these efficiencies to bring forward point of cash flow neutrality.

As we continue to grow our early stage Company, we will strive to consistently provide capital efficient growth, while keeping the balance sheet strong at under two times leverage in a $50 per barrel commodity price environment. By executing on these goals, we believe that we can efficiently get to 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 teams and our acreage will provide competitive long-term growth and value to its shareholders.

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

Questions and Answers:

Operator

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

Gabriel Daoud -- Cowen & Co -- Analyst

Hey, good morning, Jim and good morning everyone. Maybe just starting with 2019, I think one of your rigs rolls off a contract at the middle of this year. I'm assuming the budget -- I guess let's 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 that with growth and ultimately free cash flow generation. So how do we think about that moving into 2020?

James J. Kleckner -- President and Chief Executive Officer

Good morning, Gabe, and thanks for the question. Our program in 2019 contemplates a five rig program throughout the year, and essentially one frac crew. We may add additional spot for frac crews to keep up the pace of the (inaudible). What we're seeing is, as you're see in some of the graphs, cycle time reductions, across just about every rig and program we're running, whether it'd be drilling or completing. So our current plan is to run that rig set and frac fleet into '19.

And then we would anticipate additional cycle time improvement throughout the year. And depending on how many wells per year that rig or a frac fleet was generating, we would look forward to a five rig or four rig program or whatever we would optimize, based off the amount of drilling and completion activity that can be accomplished with that fleet.

Gabriel Daoud -- Cowen & Co -- Analyst

Thanks and 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...

James J. Kleckner -- President and Chief Executive Officer

Yeah, the goal is to balance moderate growth and deliver free cash flow as soon as we can. And the point of time 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 that we're looking at.

Gabriel Daoud -- Cowen & Co -- Analyst

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

James J. Kleckner -- President and Chief Executive Officer

Yeah, 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 co-development would look like.

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, thanks for the question, Gabe. This is Craig Walters. Yeah, at Cochise what we're looking at is a nine well development program, and that's going to consist of basically three well pads. We're going to test three different landing zones in that particular area. So, we'll have the 3rd Bone Spring in and two 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 (inaudible) late fourth quarter or at the first part of 2020.

Gabriel Daoud -- Cowen & Co -- Analyst

Great. That's helpful Craig, thanks a lot. Thanks everyone.

Operator

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

Brian Downey -- Citigroup -- Analyst

Great, thanks for taking my questions. 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%, wells turned online 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?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah. So I'll turn your attention, 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 set 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 six 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 efficiencies, those kind of go hand-in-hand. So that's kind of the split that I put on our $200 worth of savings from '18 and '19 (ph).

Brian Downey -- Citigroup -- Analyst

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?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, I mean regional sand, we've been talking about 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 and that 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.

Brian Downey -- Citigroup -- Analyst

Got it. That's helpful. Thanks for taking my question.

Operator

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

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Hey guys, 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 getting tied inline in '19 versus '18. But it looks like your production, and certainly from a Boe per day perspective, it's growing a lot less, makes it seem a little bit conservative. What are you guys modeling in there for Big Tex? Obviously, you've got your five operated wells plus a couple others that are sort of not up. Just trying to get a sense of kind of what's in there for Big Tex at this point?

James J. Kleckner -- President and Chief Executive Officer

Well, I think there are several factors that affect our production forecast for 2019. As we start shifting to larger pads, there'll be some production delays that occurs, certainly we'll be seeing in the second half of this year. As Craig mentioned, the nine well co-development pad in Cochise, while the delay they won't see first production until the first quarter of 2020. And in Big Tex, the impact should be relatively small, since we are not drilling many of our wells there. But we anticipate that the quality of those wells should be very stronger.

Big Tex program is built around high-grading of fairway, integrating our 3D dataset, 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 anticipate decent wells there, hence the reason for allocating capital to that part of the program.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

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 kind of the post-impairment total on the acreage that you have? And, what do you think could expire here in 2019 and '20?

James J. Kleckner -- President and Chief Executive Officer

Well, as we'd mentioned before, we did a lot of technical work, we integrated all the seismic dataset to identify that fairway. And we've identified and the high-graded those specific (inaudible) and 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 is several thousand acres approximately.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

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

James J. Kleckner -- President and Chief Executive Officer

Yes, that's correct.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

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?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, thanks for the questions, this is Craig Walters again. We're seeing really good performance here, the first two months into the year and the $1,250 represents an average, but again, we are well on our way to hitting that target.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Okay, thanks guys.

Operator

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

Irene Haas -- Imperial Capital -- Analyst

Yes, hi. I would like to have a little more clarity on your farm-out. 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.

James J. Kleckner -- President and Chief Executive Officer

Yeah, good morning, Irene, and thanks for the question. Regarding the fairway, we've got it mapped with the data that I've mentioned earlier. 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. That's been -- we think it has great potential, especially as we move north in the Big Tex acreage as you can see on the map. Regarding the format, I'm going to have David Eckelberger talk to that, as he was the one that brought (ph) that deal through the last several months.

David F. Eckelberger -- Vice President of Land

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

Irene Haas -- Imperial Capital -- Analyst

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

David F. Eckelberger -- Vice President of Land

No, we'll be receiving 400 net acres from the farm-in.

Irene Haas -- Imperial Capital -- Analyst

Okay. Got you.

David F. Eckelberger -- Vice President of Land

And -- yeah.

Operator

Our next question comes from the line of Betty Jiang with Credit Suisse. Your line is open.

Betty Jiang -- Credit Suisse -- Analyst

Hi, good morning. 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 gave you the comfort that they won't have much impact on well productivity?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, thanks for the question, Betty. This is Craig Walters again. Throughout 2018, our completions group, especially did a lot of testing on the 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 looked back at a lot of that data, we were able to come up with the new completion design that we talk to, again, on Slide 11, and that's 2,000 pounds per foot sand loading and 50 barrels of water a foot in a 225 foot stage spacing.

I think it's important to recognize the 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 -- six of these we pumped so far first part of the year and we're seeing good performance from there.

Betty Jiang -- Credit Suisse -- Analyst

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

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah. So in 2018, again, that 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 changed as we looked at the production performance of those particular wells is how we homed in on the current design (inaudible).

Betty Jiang -- Credit Suisse -- Analyst

All right. Thanks. And second question, what do you need to see from the first five wells in Big Tex to make the decision on whether to move forward with the remaining seven? And where would you reallocate capital from?

James J. Kleckner -- President and Chief Executive Officer

Well, what we're going to first see is what is the production performance from the wells. Obviously, well rates will be very important. But another key parameter of that is what we've learnt from drilling, logged that information in our completion response. So we look at all of the information that we receive from the operations, integrate that in and map or change accordingly to try and continue to inform our decisions. So it won't be just one specific thing, it will be a multitude of feedback that we get as we drill in this area of the field.

Betty Jiang -- Credit Suisse -- Analyst

Great. Thanks.

Operator

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

Michael Scialla -- Stifel -- Analyst

Good morning. 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 nine 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 lot of delineation to be done in 2020 as well?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, Michael, this is Craig. Great question. I think we've 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 3rd Bone Spring and even the 2nd Bone Spring in 2018. So, yeah, as we fold off 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 the nine well pilot in Cochise, we are also planning additional pilots in Whiskey River to be executed on. Some of those might go (ph) later this year, but definitely the first part of 2020 and as we fully move into that full development mode.

Michael Scialla -- Stifel -- Analyst

Okay. And 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 does that -- how is 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?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, so as we've gotten in the 3D seismic at Big Tex, the team has worked out 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 two 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 be able to land and steer that well within the specific portion of the Woodford that we want to. And so, yeah, we're really excited to see production performance on that well, probably late second quarter.

Michael Scialla -- Stifel -- Analyst

With the farm-out, I guess, are you going to -- are all those farm-out 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?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, so our partner plans to drill Wolfcamp A and we reserved our Woodford rights.

Michael Scialla -- Stifel -- Analyst

Very good. Thank you.

Operator

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

Michael Kelly -- Seaport Global -- Analyst

Hey guys, good morning. 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 guideposts on how you're thinking about that. Thanks.

James J. Kleckner -- President and Chief Executive Officer

Yeah, good morning, Mike, and thanks for calling in with a question. 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 co-develop multiple zones, properly addressing the geomechanics 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 acres of our field within Cochise and Whiskey River, that's a very robust inventory and carries forward at that type of growth rate for many, many years to come.

Michael Kelly -- Seaport Global -- Analyst

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

James J. Kleckner -- President and Chief Executive Officer

We're budgeting at a conservative $50 today, and we used that in prior years, and given the volatility of 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 for multiple and not expand the program probably much more than what we're doing right now.

Michael Kelly -- Seaport Global -- Analyst

Great. Appreciate that color. 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 surmise that it could have been stronger if you didn't opt to do this nine well pad at Cochise, which obviously makes a lot of sense to do. But I wonder, if you look at your Q4 number and '19 and you had elected to just continue with two well pads, how much higher could that have been in your opinion?

James J. Kleckner -- President and Chief Executive Officer

All right, Mike, that's a good question. We didn't model that, so I hate to pull a number out and state we would have actually did a number x percent higher. But I think if you imagine that we'll be putting nine wells in the ground and not seeing the first production from those wells till first quarter of '20 and those nine 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 a co-develop 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.

Michael Kelly -- Seaport Global -- Analyst

Great. Appreciate that. Really good update guys, thanks.

James J. Kleckner -- President and Chief Executive Officer

Okay. Thanks, Mike.

Operator

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

Paul Grigel -- Macquarie -- Analyst

Hi, good morning. Could you provide some color and details on your current corporate decline rate?

James J. Kleckner -- President and Chief Executive Officer

Good morning, Paul. Yes, you've 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%.

Paul Grigel -- Macquarie -- Analyst

Okay. Great, thanks.

James J. Kleckner -- President and Chief Executive Officer

Plus or minus 45% if you -- depending on where you're at in the development cycle, how many wells you have in the wedge versus in the base, that can vary depending on the program.

Paul Grigel -- Macquarie -- Analyst

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

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, 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's -- it's based on lateral footage. So works to 10 or 12 -- 10 to 11 wells a year. And then we had just a handful within this period.

Paul Grigel -- Macquarie -- Analyst

Okay, great, thank you.

Operator

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

John Nelson -- Goldman Sachs -- Analyst

Good morning, and congrats on the update.

James J. Kleckner -- President and Chief Executive Officer

Thanks, John, good morning.

John Nelson -- Goldman Sachs -- Analyst

I wanted to follow up on Betty's question and just the decision around the potential seven 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?

James J. Kleckner -- President and Chief Executive Officer

John, to me a decision to allocate capital or ending further capital to Big Tex is going to be weighed heavily, I guess, to the results of the rest of our program. And as you can see, demonstrative of 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 of 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 we'll also be able to see is how much acreage in the fairway is extendable, based of the results of the well, and does it compete in Jagged Peak's portfolio. So we'll be making those decisions based on sheer well performance, but also remaining inventory that may be available to us.

John Nelson -- Goldman Sachs -- Analyst

Okay. And then just so we're clear, is the expectation that you would then raise the budget if you decided to go ahead and do those wells or is there -- yeah, I guess (inaudible)

James J. Kleckner -- President and Chief Executive Officer

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 to reiterate that they're going to have to compete from an allocation standpoint if we were sort of like to drill any follow-on wells.

John Nelson -- Goldman Sachs -- Analyst

Okay, that's very clear. Thanks so much and congrats again on the quarter.

James J. Kleckner -- President and Chief Executive Officer

Thank you.

Operator

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

Michael Scialla -- Stifel -- Analyst

Just want to follow up and ask on, it sounds like most of the 2019 plan is going to be drilled in the Wolfcamp A, you've got the one Woodford well and then Craig, you mentioned in Cochise, you're going to do a few 3rd Bone Spring wells. But any other intervals that you will be drilling this year then?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yes, great question, Michael. 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 three well pads up in Cochise, we've got an additional three well pad in Whiskey River that we're actually trying to drill right now. As we look at the zone breakout for 2019, it's about 60% -- 65% Wolfcamp A, 13% 3rd 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 3rd Bone in 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, making sure that you're doing it vertically and preserve our option to come back in and develop from a block or queue (ph) perspective the rest of the DSU at a later time.

Michael Scialla -- Stifel -- Analyst

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

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, again, we've tested a lot of the 660 spacing in the past couple of years, not just in the 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 the full-field development, and especially this first Cochise product that we talked about, that spacing is going to be on 880 foot laterally, so a 441 rack between those three intervals that I talked about earlier. And so, again, we're stepping into it cautiously, want to make sure that we don't overcapitalize and then take any lessons that we learned here on our five wells on our go-forward program.

Michael Scialla -- Stifel -- Analyst

Okay. I guess I lied, I have one more. Just kind of curious, why you decided on the development in Cochise when you've allocated most of your capital. Looks like Whiskey River has given you your strongest returns. Any particular reason you decided to start with the development project there rather than Whiskey River?

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Yeah, Michael. As I alluded to, we have an annual drilling obligation up in our Cochise area, that's 10 to 11 wells. And so, yeah, this fit really well with being able to take a half DSU that hasn't had any wells in it, the nearest well is about a quarter of a mile away. And so, yeah, 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.

Michael Scialla -- Stifel -- Analyst

That makes sense. Thank you.

Operator

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

James J. Kleckner -- President and Chief Executive Officer

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

Operator

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

Duration: 40 minutes

Call participants:

James Edwards -- Director of Investor Relations

James J. Kleckner -- President and Chief Executive Officer

Gabriel Daoud -- Cowen & Co -- Analyst

Craig R. Walters -- Executive Vice President and Chief Operating Officer

Brian Downey -- Citigroup -- Analyst

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Irene Haas -- Imperial Capital -- Analyst

David F. Eckelberger -- Vice President of Land

Betty Jiang -- Credit Suisse -- Analyst

Michael Scialla -- Stifel -- Analyst

Michael Kelly -- Seaport Global -- Analyst

Paul Grigel -- Macquarie -- Analyst

John Nelson -- Goldman Sachs -- Analyst

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