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Jagged Peak Energy Inc. (JAG) Q1 2019 Earnings Call Transcript

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Jagged Peak Energy Inc. (NYSE: JAG)
Q1 2019 Earnings Call
May. 10, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning. My name is Christina and I will be your conference operator today. At this time, I would like to welcome everyone to the Jagged Peak Energy First Quarter 2019 Earnings Conference Call. 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)

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

James Edwards -- Director, Investor Relations

Thank you, Christina. Good morning everyone and welcome Jagged Peak Energy's first quarter 2019 earnings and operational updates conference call. With us on the call today are Jim Kleckner, CEO and President; Craig Walters, EVP and Chief Operating Officer; Bob Howard, EVP and Chief Financial Officer; Ian Piper, VP of Finance and Corporate Planning; and David Eckelberger VP,Land.

Last evening, we issued our first 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 May investor 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 on the company's SEC filings and on Slide 2 of our May Investor presentation.

Our materials also include certain non-GAAP financial measures such as adjusted EBITDAX, adjusted net income, and adjusted EBITDAX margins. We believe these non-GAAP measures provide a comparison across the periods of activity and with other oil and gas operators. The reconciliation of the appropriate GAAP financial measures to the non-GAAP financial measures can be found on 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 -- Chief Executive Officer and President

Good morning everyone and thank you for joining us for our first quarter 2019 earnings call. My prepared remarks this morning will focus on progress we've made in well cost reductions and changes to our 2018 program, which now focuses more on large-scale pad development. First, I'd like to go through the strides, we've made from a capital efficiency standpoint as we are well on our way to meeting our goal of reducing DC&E cost for the year by 15%. By the end of the first quarter, we've seen a 10% reduction in those costs, which are now approximately $1,300 per lateral foot. Our goal for 2019 is $1,250 per lateral foot, down from $1,450 in 2018.

The savings we've captured this year are largely a result of decreases in service costs and changes to our well design which allowed us to capture efficiencies and decrease cycle times. Over the past several months, we have entered into new agreements with some of our service providers that reduced costs of goods and services.

In addition to these savings, we've made changes to certain aspects of our completion design at the beginning of the year, which were based on multiple field tests conducted in 2018, designed to improve well results and capital efficiency. Some of these changes included adjusting sand and fluid volumes modifying stage length per clusters per stage and pump rates to reduce overall pump times and completion costs. As we continue our 2019 program, we remain diligent on driving these costs down further and remain confident in our ability to meet our 2019 activity program within our guided capital range.

Next, I'd like to go through our production profile for the year and changes in our forecast since our last update. While our first quarter oil volumes came within 100 barrels a day of guided midpoint. Our oil equivalent production ended up being at the lower end of the guide. This is due to changes in our NGL recoveries. While we are in ethane recovery throughout most of the quarter, a larger portion of our gas to a different gas plant that saw lower NGL recoveries, changing our production mix and reducing our oil equivalent production. Going forward, we have factored these low recoveries into our guidance. As we move to the second quarter, we are forecasting a modest increase in production volumes in the first quarter due to a change in the timing from larger pads brought online, which I will detail in a moment, but also due to some greater than expected power outages that we had in April caused by high winds.

We take into account weather-related downtime in our production forecast, but the power outages experienced during April exceeded the forecast, creating a headwind for second quarter growth. While the timing of the volume growth throughout the year is shifted, we remain confident in our fourth quarter and full-year production guidance range.

On the cost side, we saw an increase to our LOE per Boe from the fourth quarter of 2018, which came in on the high side of our full-year guided range of 365 to 415 per Boe. This increase was caused by workovers in the field, which had extended jobs, associated costs of over $100 million, excuse me, $1 million. Since these are normally nonrecurring events, we are confident that our operating cost for the year will be well within our guidance range.

As I mentioned earlier, we have made some changes to our drill schedule to increase the number of larger pads in our program in 2019. On the fourth quarter call, we announced that we would be executing our first large-scale co-development pad with nine wells in Cochise during the second half of the year. Since then we've reworked the program and moved well locations that were originally scheduled to be two well pads to create larger scale co-development pads. By condensing some of these pads that were originally planned throughout the acreage, we will now be executing two large pads in Whiskey River and one in Cochise.

Locations and plots of these projects are included on page 16 of our May Investor presentation. The first of these are Coriander pad will include six wells and we'll will be targeting the 3rd Bone Spring upper and lower Wolfcamp A and Wolfcamp B in the southern part of Whiskey River. We recently started work on this pad and expect it to come online in the third quarter. From a logistical standpoint, we're putting three rigs to work each drilling two well pairs and anticipate bringing into completion crews to zipper frac these six wells. By drilling and completing these wells with multiple rigs and completion crews, we can effectively reduce the spud to sales time project, decreasing operational delay risk and increasing the project IRR.

After completion of Coriander pad, we will move north to our Venom pad in the heart of Whiskey River this pad will have eight wells targeting the 3rd Bone Spring, upper and lower Wolfcamp A and Wolfcamp B. This pad is expected to be spud in the third quarter and come online in the fourth quarter, utilizing multiple rigs and crews similar to the Coriander project. To finish up the year, we're trying to spud a nine-well pad in Cochise targeting 3rd Bone Spring and upper and lower Wolfcamp A in fourth quarter, which is expected to come online during the first quarter of 2020. We're excited to get back to Cochise to grow a followup 3rd Bone Spring well to the Beldin 5HX well that was completed during the first quarter.

As you can see on page 15 of our May Investor presentation, this well had a peak IP30 per thousand feet of 244 Boe per day and can assume the 163,000 Boe on a two-stream basis after 110 days, which is 44% outperformance the type curve. This well also recorded the highest IP30 flow rate for our company 2,517 Boe equivalent per day with an 81% of oil cap. By consolidating some of or two well pads into larger pads this year, we'll be able to fast track our learnings on well interaction inbounded test both horizontally with same zone, but also vertically between multiple horizons.

This data will be invaluable as we continue to refine our assumptions for full-field development. In addition, we will develop a larger section to resource all at the same time improving our capital efficiency, section recoveries, and long-term valuation of the assets. So we look forward to executing on this revised program in 2019 and providing results to you as we get them.

I'll now turn the call over to the operator for Q&A portion of our call.

Questions and Answers:

Operator

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

Scott Hanold -- RBC Capital Markets

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

James J. Kleckner -- Chief Executive Officer and President

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

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

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

Good morning. This is Craig Walters. Regarding the cycle times, really as we look at these initial pads that we're going to do, they still are two well pads. So even though on the coriander, it's a six-well project or pilot, we're going to have three rigs that are working their concurrently on three separate pads and there are two wells a piece and so from a cycle time standpoint, it takes us approximately 30 days per well to do the drilling operations and so, we'll do all that concurrently across those three pads to get those six wells knocked out and then, we'll have just a short gap in there before we begin completion operations and as Jim alluded to it in his opening remarks kind of around the coriander pad, we actually spud that recently and we'll have that -- those six wells toss in the third quarter, as we move into the Venom, those will toss in fourth quarter and then our Cochise project actually, we have three well pads, so nine total wells and those toss will happen in the first quarter of 2020.

Scott Hanold -- RBC Capital Markets

Okay. Thanks, I appreciate that color. And just a follow -- next question on NGL recoveries, you mentioned they were a bit lower there and I think that's the expectation going forward. Can you specifically say why that is -- it was a facility, it sounded like you might have switched to a different facility that wasn't -- didn't have a strong recoveries, can you give a little color on what the change there was?

James J. Kleckner -- Chief Executive Officer and President

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

Ian Piper -- Vice President, Finance and Corporate Planning

Yeah. Good morning, Scott. As Jim mentioned, there is a number of plants out in the field that we deliver into -- we don't have a lot of control on which plant our gas goes into, that's a decision made by target, but we saw we were selling more gas to some of the older, less efficient plants out there that lighted the lower recoveries in the quarter.

Scott Hanold -- RBC Capital Markets

Okay. So what -- I know you can't speak on Target's behalf, but what made -- why did your bonds go to less efficient clients before the others, is it that other operators have some priorities that get them into the better plans or what is -- what goes on there?

Ian Piper -- Vice President, Finance and Corporate Planning

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

Scott Hanold -- RBC Capital Markets

Okay. Understood. Thank you.

Operator

Our next question comes from Brian Downey from Citigroup. Please go ahead.

Brian Downey -- Citigroup

Good morning everyone and thanks for taking the question. Just a follow-up there on the NGLs and specifically on the realizations. I know 1Q wasn't great in general for industry NGL pricing, but was curious with ethane, a larger portion of the stream, is there anything, anything going on there on the NGL realization?

Bob Howard -- Executive Vice President and Chief Financial Officer

This is Bob Howard. The ethane recovery is probably unchanged much fourth quarter, first quarter, margins that it's being presented in the financials under the new revenue standard, if you look at the components in the first quarter, we actually received about 1,744, our NGLs netted against at about $7.90 GGP costs because we saw with the well head that it gets all back up to the sales price that we have in the 1,740 is about 18%, 20% down from the fourth quarter of last year.

So it's kind of what we saw kind of an overall decline in NGL prices in the market. And the $7.90 per barrel of GGP costs that we kind of add charge against that for the quarter is kind of in line with what we had last year of $7.30 per barrel. It is up a little bit more from what we would have incurred in the fourth quarter about $5.70. Some of these kind break parts the components into kind of in line. They're just -- because of the netting or the leverage we have on the fixed costs, where the sales price comes down, it kind of shows a price that changes more on the absolute net price we get that we actually are seeing in the realization cost that we get record back to the well.

Brian Downey -- Citigroup

Got it. Makes sense. And then maybe one on Big Tex in the Woodford the Woodford test, I know I believe you TD'd the well about a month ago. So understandably too early for any production results or data, but curious if you saw anything that surprised you as are drilling maybe anything versus a 3D data or any commentary as you drill and complete the well?

James J. Kleckner -- Chief Executive Officer and President

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

Brian Downey -- Citigroup

Excellent. Appreciate. Thanks.

Operator

Our next question comes from Neal Dingmann from SunTrust. Please go ahead.

Neal Dingmann -- SunTrust

Morning all. Jim, you guys did a nice job of laying out the stable plan. I guess my question with cognizant not having 2020 guidance out and maybe just talk about how you go into the end of the year and sort of progress to next year, do you sort of see the same stable plan as you have set in place, which I think makes lot of sense. Do you see that continuing into next year, I guess that or maybe how you end the year with that, I'm just trying to get a sense of maybe trajectory or something like that toward the year-end. Thank you.

James J. Kleckner -- Chief Executive Officer and President

Right. No. Thank you. Appreciate that question, and you're exactly right. We think of it as a long-term stable or we sometimes called base loaded plan that really allows us to develop the partnerships and relationships with the service providers that we can give consistent repeatable results and deliver among the lowest cost capital efficient investment in the resources that we can. From that standpoint, our plan is to maintain our capital program that we have highlighted this year with the rig schedule that we have. And we adopted a conservative budget based off at $50 TI and we'll use that going forward and obviously the market changes dramatically in 2020. So with that being said, we're focusing on that break over point of cash flow neutral here and within 16 to probably 30 months depending on what the price is in the out-year, but we maintain our 2019 program and we'll plan on carrying that forward in 2020 very similar.

Neal Dingmann -- SunTrust

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

James J. Kleckner -- Chief Executive Officer and President

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

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

Yeah. You're probably referring to slide 11, I guess in the slide deck that we put out there -- it really,

Neal Dingmann -- SunTrust

Yes, yes.

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

As we talk about drilling and completion efficiencies that we have, we've been significant through kind of year-to-date, especially as compared to where we were in 2018. On the drilling side, our footage per day per rig is up 13%, but more substantially, really on the completion side, from footage per day basis, we're up 86% from where we were in 2018. Those efficiencies that we're seeing are largely driven by the changes in our completion design that I think we've talked about in the prior quarter. We did a lot of field tests and pilots in 2018 and really rolled all of our learnings from those particular field pilots into our 2019 frac design, which I'll say is a continual evolution but that's really what's driving the increased footage per day on the completions and you can just imagine that that translates directly to the cost side. And so as we look at the 2019 program and we put a -- our target out there that we think is very achievable, this $1,250 per lateral foot for DC&E, again we've made some significant progress on that through the first quarter. As we look at those total savings, I think we've chalked it up to about 30% is service cost related and 70% is efficiencies and again we've gained a lot of those efficiencies in the first quarter, but we expect to build on those throughout the rest of the year.

Operator

Our next question comes from Michael Scialla from Stifel. Your line is open. Go ahead.

Michael Scialla -- Stifel

Hi. Good morning. With the co-development, it sounds like you're going to do a lot of testing, but as you head into that, wanted to get your perspective on how you're looking at these different zones. Do you see those one system or are there discrete reservoirs here and if they are discrete, where do you see the barriers?

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

Michael, great question. This is Craig Walters again. As we look at across a large portion of our acreage position, we view outside 3rd Bone Spring through Wolfcamp B as a single system for the most part, we have done a lot of testing again throughout 2018, as we did in our two well pads that were 660 paced, some of those were staggered. We've learned a lot through that program. We've incorporated a lot of those learnings into these development pilots that we are going to move forward with, starting with the Coriander then the Venom and Cochise and so, yeah, we view those as kind of a single reservoir system, which is why you see kind of that gun barrel plus that we demonstrated in the slide there.

Michael Scialla -- Stifel

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

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

Yeah. Really what drives the Coriander being set up on kind of the 1320 inter-zone or inter-landing in the 660 stack-stagger. It's really driven by the area of the field. It's really just a half of a DSU that we have down there available to us, it's our acreage and as we looked at some of the existing wells that are on our acreage and offset to us, we felt that 1320 and in-zone spacing was most appropriate. Again, as we move into the Venom, then the Cochise will be doing those at 880/440 stack-stagger. And so I think it just was kind of where we're at on the Coriander, kind of what we felt comfortable with from spacing down there and obviously get some learnings before we roll that into kind of the 880 programs the rest of the year.

Michael Scialla -- Stifel

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

James J. Kleckner -- Chief Executive Officer and President

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

Michael Scialla -- Stifel

Great. Thank you.

Operator

Our next question is from Leo Mariani from KeyBanc. Please go ahead.

Leo Mariani -- KeyBanc -- Analyst

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

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

Yeah. This is Craig Walters. Great question, Leo. As we looked at some of the decks are actually that came out for this quarter. I know partially talked about some wells that are fairly close to our Big Tex acreage as you look at those two particular wells, they're very close to kind of our high-graded area, where we put one of our Wolfcamp A wells that has been on production for about 30 days now. It's too early to kind of predict what that's really going to look like, but yeah. So we're excited by what we see from some of the offset operators. I think what drives some of the production performance in Big Tex is obviously how much pay that you have, but also pressure is a key component overall performance and again that's some of the technical work that we put together and how we got to our high-graded area for the Wolfcamp A that we're testing this year.

Leo Mariani -- KeyBanc -- Analyst

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

James J. Kleckner -- Chief Executive Officer and President

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

Leo Mariani -- KeyBanc -- Analyst

Okay. Thanks guys.

Operator

Our next question comes from Paul Greg Hill from Macquarie. Your line is open.

Paul Greg Hill -- Macquarie

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

James J. Kleckner -- Chief Executive Officer and President

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

Paul Greg Hill -- Macquarie

Okay. That's it from me.Thanks.

Operator

(Operator Instructions) Our next question comes from Biju Perincheril from Susquehanna. Your line is open. Please go ahead.

Biju Perincheril -- Susquehanna

Hi. Good morning all. Just a couple of questions. Going back to this, the multi-zone developments and this might be a little too early with not having most year, but if you sort of looking to 2020, if the results come in as you expect, any early read into what percent of your program in '20 next year could be this type of multi-zone development projects?

James J. Kleckner -- Chief Executive Officer and President

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

Biju Perincheril -- Susquehanna

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

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

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

Biju Perincheril -- Susquehanna

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

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

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

Biju Perincheril -- Susquehanna

The fourth quarter exit rate?

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

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

Biju Perincheril -- Susquehanna

Got it. All right. Thank you.

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

Thank you.

Operator

Our next question comes from Michael Scialla from Stifel. Your line is open. Please go ahead.

Michael Scialla -- Stifel -- Analyst

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

James J. Kleckner -- Chief Executive Officer and President

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

Michael Scialla -- Stifel -- Analyst

Makes sense. Thank you.

Operator

Our next question comes from Irene Haas from Imperial Capital. Please go ahead.

Claire Ye -- Imperial Capital

Good morning. This is Claire Ye from Imperial Capital. And the first question is the follow-on NGL. So should we expect the same sort of revenue recognition method going forward as well as the GP&T deduction?

Ian Piper -- Vice President, Finance and Corporate Planning

Yeah, because for planning purposes, assume -- what we've seen this quarter is kind of aligned with what we had to the full year last year.

Claire Ye -- Imperial Capital

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

James J. Kleckner -- Chief Executive Officer and President

Yeah. Those well costs, I mean they're baked into that $1,250 per lateral foot. So as you look at that on a 9,000 foot average wells, roughly $11.3 million.

Operator

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

James J. Kleckner -- Chief Executive Officer and President

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

Operator

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

Duration: 32 minutes

Call participants:

James Edwards -- Director, Investor Relations

James J. Kleckner -- Chief Executive Officer and President

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

Ian Piper -- Vice President, Finance and Corporate Planning

Bob Howard -- Executive Vice President and Chief Financial Officer

Scott Hanold -- RBC Capital Markets

Brian Downey -- Citigroup

Neal Dingmann -- SunTrust

Michael Scialla -- Stifel

Leo Mariani -- KeyBanc -- Analyst

Paul Greg Hill -- Macquarie

Biju Perincheril -- Susquehanna

Michael Scialla -- Stifel -- Analyst

Claire Ye -- Imperial Capital

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