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Jagged Peak Energy Inc. (JAG) Q2 2019 Earnings Call Transcript

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Jagged Peak Energy Inc. (NYSE: JAG)
Q2 2019 Earnings Call
Aug 9, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning. My name is Mike, and I will be your conference operator today. At this time, I would like to welcome everyone to the Jagged Peak Energy Second Quarter Earnings and Operational Update. [Operator Instructions] I will now turn the call over to James Edwards, you may begin your conference.

James Edwards -- Director

Thank you, Mike. Good morning, everyone, and welcome to Jagged Peak Energy's Second Quarter 2019 Earnings Conference Call. With us on the call today are Jim Kleckner, our CEO and President; Craig Walters, EVP and COO; Bob Walters -- Bob Howard, our EVP and CFO; Ian Piper, VP of Finance and Corporate Planning; and Dave Eckelberger, VP of Land. Last evening, we issued our second quarter earnings release and our 10-Q, both of which are available on our website at jaggedpeakenergy.com. During our discussion this morning, we'll be referencing slides from our August investor presentation, which can be found on the Presentations page under our 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 the 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 two of our August investor presentation in 2018 10-K. The materials also include certain non-GAAP financial measures such as adjusted EBITDAX, adjusted net income and adjusted EBITDAX margin. We believe these non-GAAP measures provide a comparison across the periods of activity and with other oil and gas operators. Reconciliation of the appropriate 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.

James J. Kleckner -- President, Chief Executive Officer and Director

Good morning, everyone, and thank you for joining us for our second quarter conference call. I'm going to start the call this morning with brief comments on the quarter and then hand it over to Craig to dive into some of the operating details. Overall, our second quarter performance was strong as we continue to successfully execute on our 2019 plan. Our capital expenditures are right on pace to meet with the midpoint of our guidance and our production volumes were above the midpoint of our guidance range for the quarter. It's a team effort, and I want to thank our organization for their hard work in achieving these results. From a capital efficiency aspect, we remain firmly on pace to meet our annual goal for DC&E cost of $1,250 per lateral foot. In the first half of the year, our DC&E cost per foot decreased by 12% from 2018 levels to $1,270. This decrease was achieved by optimizing the capital efficiency of our well design, leveraging operating efficiencies and utilizing the strategic sourcing materials to reduce the cost of consumables.

In the second half of the year, we expect to continue to capture incremental value as we have leveraged additional operating efficiencies on our development projects. By cashing on these gains, we've been able to stay on pace to meet our capital guidance midpoint for the year, with half of our annual investment made in the first 2 quarters as shown on slide 11 of our August investor presentation. In the second half of the year, we expect our quarterly expense to peak in the third quarter as we utilize 2 completion crews throughout the quarter to complete the Coriander and Venom projects. Production is forecasted to increase by 3% in the third quarter as Coriander is turned online in late August and 15% in the fourth quarter as Venom's turned online in late October. From an operating margin standpoint, we remain intently focused on maintaining top-tier margins, driven by some of the basin's highest oil cuts and lowest LOE per BOE.

While our LOE per BOE is increased as the fuel relies more on the artificial lift, we've reduced our G&A guidance on an absolute and per unit basis, which has neutralized the impact on our EBITDAX margin. In all, Jagged Peak remains focused on relying on its core competencies of operational execution by running this business as effectively as possible and our second quarter results are continued examples of that execution. By focusing on items within our control, we plan to continue to grow our asset base, keep leverage in check and get to a point where we'll be in a position to provide free cash flow back to our investors.

And with that, I'll turn the call over to Craig for his operational review of the quarter.

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

Thanks, Jim, and good morning, everyone. Before diving into the operational update, I, too, want to commend our team on putting us in a great position to fully execute on our 2019 program by making great progress on our stated goals. I will start my comments this morning by going through an update of our Coriander project, which is the first multi-well co-development project for Jagged Peak. On slide 14 of our investor presentation, we have provided an overview and update of the project, and I am pleased to report that our progress so far is right on track with our expectations. As you can see from the picture on the slide, this project was set up as a large pad with 3 separate drilling rigs, each drilling 2 wells. By utilizing 3 rigs, we reduced the amount of time from spud to sales, increasing the project rate of return. With all 6 wells successful drilled, the pace of drilling on this project was slightly above the company average for the quarter with a project average drilling rate of approximately 860 feet per day, with 95% of the laterals optimally placed.

After the rigs are released from the project, we brought in 2 completion crews, which similar to the rigs, were brought in to shorten cycle times and also leverage positive frac interference designed to increase overall stimulated rock volume. To date, we have successfully completed 4 of the 6 wells and are currently finishing and completing the remaining 2 next week. We expect these wells to be turned online in the second half of August through the new production facility you see in the picture just on the map on slide 14. This central facility is designed to handle production from all six wells, a further improvement to capital efficiency as we transition away from single and two-well facilities. As you can see in the gun barrel slide on the top left corner of the slide, we have planned these wells to be spaced quite conservatively with lateral spacing of approximately 1,320 feet apart. And this is our first test of a bounded multi-horizon well package.

We wanted to make sure we were conservatively stepping into these development projects and not over capitalizing the rock. Our next 2 development scale projects, the Venom and UTL projects, will both utilize 880-foot spacing which we would consider a more realistic go-forward development spacing and is equivalent to what our inventory count is based on. Moving to Slide 15, we have provided some information on our delineation program in Big Tex. In the first half of the year, we had brought online 2 delineation wells, the first of which was placed in the west central area of Big Tex, targeting the Wolfcamp A formation, in a hydrated geologic fairway that was then formed by the 3D seismic and other geologic data acquired at the end of last year. The second of these wells was placed in the southeast corner of our acreage, targeting the Woodford formation. As you can see on the slide, both wells have had encouraging early results.

The first well, the State Big Tex 7673-8-11-H, targeted the Wolfcamp A and was placed 99% in zone with a 10,250-foot lateral. This well's early time cumulative production has been strong, outperforming our average historical Big Tex results by a wide margin. The well was recently put on electrical submersible pump and has the most recent 7-day average oil rate of 1,077 barrels per day, notable as the well has been on production for over 130 days. The second well in the slide is the Chimera well, which targeted the Woodford formation. This is the company's second Woodford test, the first being a short lateral which was completed back in 2017. The Chimera well is a 6,400-foot lateral placed entirely in zone, with encouraging early time production, which surpassed the normalized IP rate of the company's first Woodford well.

Though it is too early for an assessment of overall well performance or even a 90-day IP rate, the wells normalized peak IP30 of 294 BOE per day per 1,000 lateral feet is certainly impressive. We will continue to monitor the results of these wells and look forward to the results from the 2 remaining hydrated Big Tex wells targeting the Wolfcamp A, which are expected to come online in the third quarter. Evaluation of these wells will take place over the remainder of the year and will be used to inform capital allocation decisions for Big Tex in 2020 as we do not currently have plans to reallocate capital from Whiskey River to Big Tex in our 2019 program.

With that, I'll turn the call over to the operator for us to answer any questions.

Questions and Answers:

Operator

[Operator Instructions] Your first question comes from Brian Downey from Citigroup.

Brian Downey -- Citigroup

Good morning. Thanks everyone for taking the questions, I realize it's probably too early for formal thoughts on 2020, but just wondering given the expected strong fourth quarter production exit rate and momentum into next year, the results announced today in Big Tex and the inherent free cash flow debate in the E&P space, not to mention commodity price also, how you're thinking about approaching 2020 planning from a higher level. Any particularly strong governors we should think about?

James J. Kleckner -- President, Chief Executive Officer and Director

Brian, thanks for the call. This is Jim. Yes, Brian, we start our formal budget process this fall, and we'll be looking at capital allocation based on results of what we just discussed at Big Tex, but also based on some of the results that we see from flowback on the pads, the Coriander and possibly the Venom. So I think it's all premature to talk specifically about 2020. However, I would say that our message has been to stay the course. Obviously we'll respond to commodity market cycles. But our budget is based on the conservative debt at $50 and we plan our capital allocation based on maximizing well IRRs on a $50 deck and our capital spend. We get -- we would be governed by our debt-to-equity ratio. So we'll stay very consistent with how we've operated in the past.

Brian Downey -- Citigroup

Got it. And then maybe a follow-up. Just given your DC&E cost targets, how should we think about, as you move to larger projects within the portfolio, how do -- how are costs trending at the Coriander pad on a lateral-foot basis versus what you're seeing in the rest of the average portfolio?

James J. Kleckner -- President, Chief Executive Officer and Director

I'll let Craig handle some of the early results that we're seeing on pad performance.

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

Yes. This is Craig Walters. So yes, on the DC&E front, we've made great strides so far in 2019. As you recall, our average last year on a per lateral foot basis of drill complete, plus the equip or the facilities, was $1,450 per foot. We're currently a year-to-date average $1,270. The last quarter, it was $1,250 on a per foot basis. So as we look at the Coriander and now Venom, we are realizing some incremental efficiencies, definitely on the drilling side. It's been very beneficial for us to have multiple rigs sitting on the same pad to learn kind of how the rock drills and be able to share best practices near real time across the rig fleet. And so I would expect our capital efficiency numbers to continue to fall slightly through the rest of the year. It's really hard to predict exactly what we'll see, I think, on the Coriander and Venom until we get those projects completed and wrapped up.

Brian Downey -- Citigroup

All right. Thanks for taking the questions

Operator

Your next question comes from

.

Gabe Daoud -- Cowen -- Analyst

Hey good morning guys, Just given the efficiency that you have seen so far and kind of on track with the DC&E -- or D&C target per foot, just kind of wondering at the very least for 2020, if you were to think about maintaining the same pace as you have been in 2019, do you think that, at the very least, the budget for next year could potentially be lower than what we're seeing in 2019?

James J. Kleckner -- President, Chief Executive Officer and Director

Well, again, we haven't formalized what our thoughts are on 2020, so I think it's a little too early to comment. However, as we continue to move through the year, and as Craig mentioned, more and more about pad development efficiency gains, we're seeing continuous improvement coming not only from our drilling teams, but on completion teams. And we're also seeing improvement cost for infrastructure as we bring wells into larger central facilities. So as we continue to move in that direction, we would anticipate improving capital efficiency. It's too early to comment at this point.

Gabe Daoud -- Cowen -- Analyst

Jim, that's helpful. And then just as a follow-up, obviously, you guys have a pretty attractive and robust quarter in infrastructure assets. So I was just kind of thinking, and I know you just kind of talked about previously, but how you balance the benefits of that from the OpEx side versus maybe potentially divesting it just given a lot of interest in assets like this in the market.

James J. Kleckner -- President, Chief Executive Officer and Director

Yes. From a perspective of managing an unconventional play dilemma, water is absolutely critical to have it at the readiness of operations because of all the integration of will it be drilling or completion. And in the production side of it, as far as the incremental benefits, I'll let Craig talk to that, that we see of operating and owning our own water business.

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

Yes. This is Craig. As we looked at kind of the unconventional development, Jagged Peak was very strategic with regard to going out and acquiring surface acreage and putting in their own water infrastructure. Water really is the lifeblood of the Delaware Basin operations, not just for Jagged Peak, but for anybody. As we look to source water for fracs, and then on a produced water basis, we have roughly a 2.5 water well ratio. So that water production is going to be with us for the life of the well. As we look at having kind of that operational and logistical control early in the project, it's been very critical for us to be able to achieve and hit our targets. And I think as our asset base matures and we get more of that base or trunk line infrastructure in place, I think we may look at what other opportunities we might have for us on the water system.

Operator

Your next question comes from Neal Dingmann from SunTrust.

Neal Dingmann -- SunTrust -- Analyst

Hey guys, can you just talk about what options you think you have in sort of Big Tex, all the different options?

James J. Kleckner -- President, Chief Executive Officer and Director

Good morning Neal, it's a good question. From a large perspective, I think it's pretty consistent with what we messaged in the past. Big Tex provides lot of optionality to our portfolio, and starting last year, as Craig mentioned, we integrated subsurface data, G&G information to improve our understanding of Big Tex and focused on 5 wells going forward. We got 3 of those wells that we've seen a flowback and the other 2 will be coming up. So that'll inform us more about the path that we want to take. But that being said, the last 2 wells that we've had on test are very encouraging, and we're excited about that. As far as options, there are many. We can allocate drilling capital if the wells better compete with a Whiskey River and our Cochise portfolio. We can release -- we can front them out and our multiple other commercial solutions, including DrillCo JVs that we could look at in terms of optionality.

Neal Dingmann -- SunTrust -- Analyst

Great to hear. I agree. I think there's a lot of options there. And then just lastly, and a good part, it's notable your capital efficiencies that you continue to see both from an operational and financial standpoint. I'm just wondering, how do you view, I guess, when you think about the larger pad development from 2 aspects: One, just given, albeit, your smaller size; and two, just the sort of lumpiness in cash flow that causes. I mean Jim, maybe for you, about how you just, I guess, sort of view that from an operational perspective?

James J. Kleckner -- President, Chief Executive Officer and Director

Yes. I'll let Craig talk about, to use the baseball analogy, what inning are you in, in unconventional play development. Certainly, as we move into pad developments and complexities of the Delaware Basin, which are multi-stacked doubled horizons, they're very complex and we think there are a lot of efficiency gains out in front of us. So Craig, perhaps you could talk a little more to what you think those are?

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

Yes. On the drilling side especially, I think we're still early innings. I'll say third or fourth, we have a significant amount of runway in front of us. We've been able to learn a lot actually over the past six months. If you recall, we've brought some higher-spec rigs into the fleet in late fourth quarter of 2018 and starting to see the fruits of those particular rigs and some of the technology applications. So, yes, still think we're early on the drilling side. Completions, we piloted and tested several different concepts in 2018 and rolled that into our new completion design that we've been utilizing all of 2019. Seeing good benefits and efficiencies there. And so I think probably in later innings on the completion side. It'll be key for us, I think, as we move into the development of these bounded multi-well co-development to really dial in a little bit more kind of completion size and really the effectiveness of our stimulations as we have multiple wells that we can kind of play with the timing and, again, how we have that positive frac interference to create increased stimulated rock volume.

James J. Kleckner -- President, Chief Executive Officer and Director

And then, Neal, the second part of your question was relating to the lumpiness of the cash cycle. Bob, you want to comment on that?

Robert W. Howard -- Executive Vice President and Chief Financial Officer

Yes, we did. I think one the things we're doing -- we will push the pads after this more of trouble out, reduce the cycle time to bring those wells on quicker. So -- but we will need to work with and we'll see some of the lumpiness with the capital being spent and then the production coming on line. And it's kind of the work that we have to do as we transfer from single and 2-well pads into multi-well pads. And as the borrowing capacity that sort of manage output, to expect that to get the efficiencies from bringing our production out all at the same time to get those respective wells paid back and pads paid back quickly.

Neal Dingmann -- SunTrust -- Analyst

Hi guys. Thanks so much for the answers.

Operator

Your next question comes from Leo Mariani from KeyBanc.

Leo Mariani -- KeyBanc. -- Analyst

Hey guys, I was hoping to get a little bit more color on Big Tex in terms of how many of those 29,000 acres are going to be expiring at the end of this year and how many may expire at the end of 2020. And certainly, it seems like you've had some encouraging results there. I mean is that -- have those results kind of prompted more discussions on other farm-outs or DrillCos? Do you feel like those results are kind of good enough to get one of those deals done?

James J. Kleckner -- President, Chief Executive Officer and Director

Well, I think there are a lot of commercial avenues open for Big Tex, as I mentioned earlier. And certainly, when you have positive and encouraging well results, those opportunities become much, much better. And I think it's too early to comment on the inside of acre expiry that could occur in Big Tex this year or next year other than we're studying it very carefully with an eye on capital allocation and our overall portfolio on optionality of acreage that we have in Big Tex.

Leo Mariani -- KeyBanc. -- Analyst

Okay. And I guess just additionally, kind of sticking with Big Tex here. So just trying to get a sense what the cost was of that recent Wolfcamp A well as well as your Woodford well there.

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

Yes. This is Craig Walters. So as far as the cost associated with those 2 particular wells down in Big Tex, a little bit higher than our $1,250 per foot average. Those are single wells, so we had to build a single-well facility and we also didn't get the benefit of zipper completion or same locks type operations there. So it's a little bit higher than our $1,250 number.

Leo Mariani -- KeyBanc. -- Analyst

Okay. That's helpful. And I guess just with respect to G&A, looks like you guys certainly cut a pretty good chunk out of that -- out of the guidance this year. Can you just kind of talk through a little bit how you guys are able to do that and might you see further reductions going forward?

James J. Kleckner -- President, Chief Executive Officer and Director

Yes. Absolutely. We look at our G&A costs as -- on the cash cost side of it. And last year, we put in place processes and systems and steps that we took to more efficiently manage the business and our -- improved our organizational capacity through new technology in some of these processes. So as we looked at our pace of activity in 2019 and beyond, we simply readdressed organizational needs and focused on driving cost down to protect margins. At the end of the day, this is all a margin game, and we've got to improve on cost and certainly strive to offset any leakage of loss of margin.

Leo Mariani -- KeyBanc. -- Analyst

Okay. Thanks.

Operator

Your next question comes from Michael Scialla from Stifel.

Michael Scialla -- Stifel -- Analyst

Hey good morning everybody, Looking at your inventory and what you've drilled so far, I just wondered are there any more zones you'd like to test at this point or do you feel like you've pretty well delineated the vertical column at this point?

James J. Kleckner -- President, Chief Executive Officer and Director

Craig, why don't you speak to what we've got as far as the ongoing appraisal exercise? We're focused on our core areas, but we are testing and continue to test various zones throughout [indecipherable]

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

Yes, Michael, this is Craig. Great question. As we look at kind of the full column that we have available to us, I mean, obviously, our focus has been, I'll say, a third Bone Spring through Wolfcamp B. I know we demonstrated kind of the percent of wells that we're going to have this year in those various horizons, and it's over -- a bit over 50% Wolfcamp A and then I think it was equal 22% each in the third Bone and Wolfcamp B. We do have some -- in fact, we have a well drilling right now that is a second Bone Spring well. Excited to -- this will be our third Bone Spring well across Jagged Peak's portfolio, so excited to see what that one will do. Our G&G and subsurface team continues to evaluate for those other horizons, but they don't have any plans currently to go out and test them.

Michael Scialla -- Stifel -- Analyst

Okay. And that second Bone Spring well, Craig, where is that located?

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

Sorry, it's in Whiskey River.

Michael Scialla -- Stifel -- Analyst

Whiskey River. Okay. And then just looking at slide 15, your Wolfcamp A well in Big Tex. It looks like it had an uptick in productivity after about 100 days. I assume that's -- corresponds to when you put it on pump. And if so, any thoughts on putting wells down there on pump even earlier in the life?

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

Yes, Michael, this is Craig again. So yes, you noticed it very well. I mean basically, it's 110. You see that slight inflection, that's exactly when we installed the electrical submersible pump. I will say, we were able to flow this well longer than we have some historical Big Tex wells down there, which was -- saves you from an operating cost standpoint. And again, the well was performing nicely up until that point. After we put the sub on, I talked about it in the prepared remarks, but we're almost 1,100 barrels of oil per day in the past 7 days. So that well is looking very encouraging right now. That's a pretty typical pump installation time as we look across kind of Whiskey River, though. It's kind of that 3 to, I'll say, six month-mark, depending upon the well.

Michael Scialla -- Stifel -- Analyst

Got it. Okay. And then just last one for me. Jim, just kind of philosophical question. You guys have, I think, done a pretty darn good job since you've taken over the helm there and pretty much done everything you said generally beat numbers every quarter. Your stock's down 26% this year, kind of in line with the rest of your midcap peers. Just wondering your thoughts on what do you do differently to make your stock move in the other direction. Does the idea of a merger of vehicles make any sense to you from a philosophical standpoint or anything else that you could add there?

James J. Kleckner -- President, Chief Executive Officer and Director

No. That's an interesting question and certainly one that comes up quite frequently. Our view is with the deep inventory that we have and the runway that we've got in front of us, more operational efficiency and capital efficiency gains that are there, we feel strongly that we can continue to improve the returns on our wells as we shift into co-development pads. I do firmly believe that by focusing on increasing economic value through very thoughtful allocation of capital and improving individual well returns that will organically grow the company and return cash to shareholders. And that's our focus right now. So as far as philosophical discussions on MOEs or other type activities, we're very focused on our core business right now and we see that as the best route for growing value. Demonstrating that and our ability to do that over the next several quarters as we ship the pads is going to be critical in showing the market and our investors that we can deliver. And I think our past 5 quarters we delivered on that and we anticipate delivering on that in the future.

Michael Scialla -- Stifel -- Analyst

Thanks

Operator

Your next question comes from Irene Haas for Imperial Capital.

Irene Haas -- Imperial Capital -- Analyst

Yes. Congratulations on the success you have in the Big Tex area. And I was kind of curious, how much did you spend exactly in dollars -- million dollars in the Woodford and also the Wolfcamp wells? And also, how -- you said you have to do some single-well infrastructure construction. I was kind of curious what it looks like down there, specifically in the long term, if this were to be a successful venture, what other plans to take away the Woodford gas?

James J. Kleckner -- President, Chief Executive Officer and Director

Irene, thanks for your question. I think Craig mentioned that we spent over the $1,250. We don't want to give any specific numbers because I don't think we're fully in on what those numbers are, but it's very close to what Craig mentioned. The comment on these big single wells is that you don't have shared infrastructure, so those costs are expectedly higher. If we moved into a development phase, obviously, we would have shared infrastructure and they would come in line with our cost throughout our field development operations. As far as gas takeaway, I'll have Ian comment on what our view is on gas takeaway in the current market.

Ian T. Piper -- Vice President of Finance and Corporate Planning

Yes, Irene, and I think the question was on the gas in the Big Tex. There are a number of midstream companies down there with options surrounding us to the northeast, northwest and south, and that's something we're actively evaluating with the long-haul lines you see actually coming on here, September-October time frame. So we don't see that being a problem.

Irene Haas -- Imperial Capital -- Analyst

Great. From what I remember, you guys are not far away from regional trunk lines there. Is that right?

Ian T. Piper -- Vice President of Finance and Corporate Planning

That's right. The wall sits directly to West Coast.

Operator

Your next question comes from Paul Grigel from Macquire.

Paul Grigel -- Macquire -- Analyst

Good morning, I was wondering if you could just touch on what might be the HBP requirements in terms of number of rigs into 2024 Whiskey River and Cochise.

James J. Kleckner -- President, Chief Executive Officer and Director

Yes. Paul, we had a hard time hearing you. But I think let me just repeat your question to make sure we understand. What were the HBP requirements for Whiskey River and Cochise?

Paul Grigel -- Macquire -- Analyst

Yes, the HBP requirements. Yes, in terms of number of rigs?

James J. Kleckner -- President, Chief Executive Officer and Director

Craig, do you want to comment on that? Really on the -- or Dave you want to...?

David f. Eckelberger -- Former Vice President of Land

Yes. I can take that. Yes, this is Dave Eckelberger. We're in a really good position in Whiskey River, where about 92% of Whiskey River is HBP are in continuous development. And we've got a really manageable number of obligation wells. In 2020, it's less than 10 obligation wells next year.

Paul Grigel -- Macquire -- Analyst

Okay. Great. And then I guess maybe changing over to the LOE side, could you maybe talk about the slight increase there and some of the challenges that you've seen? And is that causing a production uplift through some of the lifting? And should we kind of view that as a new baseline level moving forward into 2020 and beyond?

James Edwards -- Director

Yes. This is Craig. As our LOE expenses came in for the first in -- the first half of 2019 and just an expectation around kind of our ESP, our electrical submersible pump, what it cost us to run those from a power standpoint as well as some workover expenses. And so I think, yes, as we reset our guidance, I would expect that to definitely near term kind to be our go-forward dollar per BOE.

Paul Grigel -- Macquire -- Analyst

And is that -- is there kind of continuous power issues that are causing that? Or is it something that maybe falls over time as the play continues the demand?

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

Yes. I'm sorry. It's not necessarily related to any power issues. It's truly just the consumption of power as we now have more of our well based on artificial lift, particularly the ESPs.

Paul Grigel -- Macquire -- Analyst

Okay. Thanks for clarifying.

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

Thank you

Operator

Your next question comes from Kashy Harrison from Simmons Energy.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning. Thank you for taking my questions, And apologies if this was asked earlier. I had to drop off for a second. But have you -- what's the size of the core position in Big Tex, of this fairway that you're currently attacking, in acres?

James J. Kleckner -- President, Chief Executive Officer and Director

Well, we're still testing that, Kashy, and we won't really have the results of those tests. And so we finished these last 2 wells because they'll help to find what that core looks like. We've gone through a lot of mapping, integration of 3D seismic data, geological information. And we've got a view of the various area, but we don't have it specified yet as far as core and what that acreage designation looks like.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. And then as we -- understanding that it's too early to think through specifics for 2020, I was just wondering, if you were to -- do you have a sense of what that maintenance capital estimate could be to hold the exit rate for this year flat into the next year?

James J. Kleckner -- President, Chief Executive Officer and Director

No. We've looked at that from a lot of different aspects and around 4 rigs or 3.5 rigs is generally where we see that at. Does that help your question?

Kashy Harrison -- Simmons Energy -- Analyst

Yes, that does.

Operator

[Operator Instructions] We have no further questions at this time. I will turn the call back over to the presenters.

James J. Kleckner -- President, Chief Executive Officer and Director

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

Operator

[Operator Closing Remarks]

Duration: 35 minutes

Call participants:

James Edwards -- Director

James J. Kleckner -- President, Chief Executive Officer and Director

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

Robert W. Howard -- Executive Vice President and Chief Financial Officer

Ian T. Piper -- Vice President of Finance and Corporate Planning

David f. Eckelberger -- Former Vice President of Land

Brian Downey -- Citigroup

Gabe Daoud -- Cowen -- Analyst

Neal Dingmann -- SunTrust -- Analyst

Leo Mariani -- KeyBanc. -- Analyst

Michael Scialla -- Stifel -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Paul Grigel -- Macquire -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

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