JAGGED PEAK ENERGY INC. (JAG) Q1 2018 Earnings Conference Call Transcript
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JAGGED PEAK ENERGY INC. (NYSE: JAG)
Q1 2018 Earnings Conference Call
May. 11, 2018 11:00 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Thank you for standing by. This is the conference operator. Welcome to the Jagged Peak Energy first-quarter 2018 conference call. As a reminder, all participants are in listen-only mode, and the conference is being recorded.
[Operator instructions] I would now like to turn the conference over to Robert W. Howard, executive vice president and chief financial officer. Please go ahead.
Robert W. Howard -- Chief Financial Officer
Thank you, Steve. Good morning. Welcome to Jagged Peak Energy's conference call to discuss first-quarter 2018 earnings and to provide an operations update. Participating on the call will be Jim Kleckner, our CEO and president; Craig Walters, EVP and chief operating officer; John Roesink, VP, development planning and geoscience; Ian Piper, VP finance and corporate planning; and David Eckelberger, VP land.
Yesterday, we issued our earnings news release and our first-quarter 2018 Form 10-Q. Both are available on our website at www.jaggedpeakenergy.com. During our discussion, we'll refer to an earnings call presentation that can be found on the Presentations page on 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 operation, plans, objectives, future performance and business activities.
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We caution that our actual results could differ materially from other 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 in Slide 2 of today's earnings call presentation. Our 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.
The reconciliation of the appropriate GAAP financial measures to the non-GAAP financial measures can be found on the last page of the earnings release and the last page of the earnings call presentation. I'll now turn the call over to Jim. I'll return later for a financial update.
James J. Kleckner -- Chief Executive Officer and President
Thank you, Bob, and good morning, everyone. We're off to a great start in 2018, and I want to thank all of Jagged Peak employees for delivering a solid quarter by advancing our development program and delivering production volumes that came in above first-quarter guidance. This was a transitional period for our company, and the team did an outstanding job at delivering our key business objectives. I'd like to start with a few highlights from Jagged Peak's first-quarter results. First, production of approximately 27,600 BOE per day came on the high side of the guidance range.
This resulted from the total of 11 wells placed on production during the quarter, and it's worth noting that these 11 wells at an average length of 9,300 feet represented some of the longest laterals we've completed as a company. Second, our total net acreage during the quarter was 77,700. This represents an increase of 2,500 acres compared to year-end 2017 and is a testament to our land department's ability to continue leasing in an active area added to our contiguous acreage position. Third, on May 8, we closed our debut bond issuance where we successfully raised $500 million at an attractive rate of 5.875%.
Net proceeds from the offering were approximately $489 million. This money has been used to pay down all outstanding borrowings on the company's revolving credit facility, and the remainder will be used to fund our program. And lastly, we continue to focus on strategic initiatives that I laid out on our fourth-quarter 2017 earnings call. We'll talk more about this later, but the seismic data acquisition is ahead of schedule and we're already beginning to see the benefits of incorporating 3D into our development planning across all our Cochise project area and parts of our Whiskey River project area.
Turning to Slide 3. You can see that we continue to sequentially grow our production quarter over quarter with growth of 15% over fourth quarter 2017 and a near tripling of production year over year. In the second quarter, we expect to continue this trend with total production of 31,000 to 32,000 BOE per day, which would represent a 14% increase at the midpoint versus first-quarter results. Our capital program is front-end-loaded in the first half this year, driven by increased activity levels resulting from both absolute frack crew counts and realized efficiencies as compared to Q4 '17.
With drilling fleet rig released from 16 wells in Q1 versus 13 in Q4. And we initiated frac operations on 17 wells in Q1 versus 14 wells in Q4 of '17. As such, we will moderate the pace of drilling and completion activity in the second half of the year to achieve our budget and well count and manage an activity in concert with our data acquisition and interpretation efforts. By incorporating this spend into our overall development program, we will more effectively deploy capital across our portfolio.
Turning to Slide 4, our key strategic initiatives for 2018 is to increase technical understanding of the reservoir systems by integrating 3D seismic, core, fluid and log data into the development program. 3D seismic -- 3D survey work is completed and processed in the Cochise area. Fast-tracked data is arriving now in the Whiskey River area, with full survey data anticipated in August. We're concentrating most of our activity level in these two areas where data collection and analysis is most advanced.
Seismic acquisition is under way in Big Tex and will available late in the fourth quarter. Our lower Wolfcamp A wells continue to show improved performance, and wells brought online both in the fourth quarter and the first quarter outperforming type curves. Eighty percent of our planned 2018 completions will be in the Lower Wolfcamp A, and 90% of the drilling activity will be in the Whiskey River and Cochise areas where we benefit from 3D. Another strategic initiative is continuous improvement in both drilling and completion cycle times.
Slide 5 shows that we achieved a 13% increase on footage drilled per day quarter on quarter. The frack stages pump per day have also increased by 13% quarter on quarter, and we are on track to exceed over three stages a day at our current – at our quarter pace. I'm excited about the team's relentless pursuit of operating efficiencies in all aspects of our business and efforts to drive down costs, enhance EURs and improve the overall economics of our development program. And with that, I'll turn the call back over to Bob.
Robert W. Howard -- Chief Financial Officer
OK. Thank you, Jim. As shown on Slide 6, we continue to generate excellent financial results with increasing production combined with top-tier margins. Oil production increased 164% over the prior year and increased 14% over the prior -- previous quarter.
Oil production was 79% of total production as we continue to benefit from the high oil cut of the Wolfcamp A wells. Total equivalent production was 182% higher than the prior year, reflecting the increased oil production along with increased gas production from certain formations and as a result of additional wells being on ESP work. LOE for the quarter continues to be top-tier at $3.91 per BOE, which includes additional cost for ESP work and an unusual work over [ph] expense of approximately $900,000 in the quarter, which added about $0.36 per BOE. We are still expecting full-year LOE to range between $3.25 and $4 per BOE.
Capital expenditures of $218.9 million for the quarter includes spudding 12 operated wells and placing 11 operated wells on production. I should mention, first-quarter activity was at a higher pace than we are planning for the full year as we deliberately pace our activity for the remainder of the year to be coordinated with the acquisition and interpretation of the additional technical data. We are very comfortable with economic returns from the development of our properties. We'll continue to evaluate our activity throughout the year, but for now, we are executing a disciplined development program in 2018 and is focused on Wolfcamp A formation.
As shown on Slide 7, substantially all of our production is on pipe, is being transported to key regional market hubs in Crane and Midland via the Oryx gathering system. We have 60,000 barrels a day of committed capacity on the Oryx system, which provides us with ample takeaway capacity out of the Delaware Basin for the foreseeable future. Our agreement with Oryx structured as a multiyear acreage dedication, which provides the benefits of committed capacity that comes with the traditional take-or-pay arrangements without the related financial liability. With substantially all of our crude oil volumes being on pipe, we're able to ensure flow and remove the pricing and operational risks that may come with trucking and rail transport.
Additionally, we have a sales agreement in place with a large-scale multinational marketer with whom we have a long-term working relationship. To reduce our financial exposure to fluctuations that have been based on oil pricing, we have hedged a substantial amount of our Midland Basin's exposure in 2018. We currently have over 15,000 barrels a day of Midland basis hedges with the weighted average price of $0.97 per barrel off Nymex prices, representing approximately 66% of our 2018 oil production guidance. For 2019, we have 8,000 barrels a day of basis hedges in place at a weighted average price of $1.10 per barrel off Nymex.
Additionally, we are actively exploring opportunities to diversify exposure to Midland pricing to maximize our exposure to Gulf Coast prices. We believe our committed capacity on the Oryx gathering system, existing sales arrangements, and basis hedges put us in an advanced position to ensure flow and to maximize our realized pricing. On Slide 8, we are reaffirming full-year costs and production guidance and providing second-quarter oil production guidance of 24,500 to 25,500 barrels per day and total production guidance of 31,000 to 32,000 BOE per day. This production level is 12% to 16% of our first-quarter production, reflecting performance from wells that are placed on production late in the first quarter and early in the second quarter.
Turning to Slide 9. On Tuesday, we closed the private placement of $500 million eight-year senior unsecured notes of our debut bond offering. The proceeds from the offering will use to pay off the $320 million balance that was drawn under our credit facility. And next, with the bond offering, we voluntarily reduced the lender commitments under the credit facility to $475 million, while the borrowing base of the credit facility remains at $540 million.
After the closing the bonds sale, our financial liquidity is approximately $635 million, including the undrawn credit facility, which leaves us well-positioned to execute our development program. This concludes our prepared remarks. We are now open -- ready to take questions.
Questions and Answers:
Operator
We will now begin the question-and-answer session. [Operator instructions] The first question is from Mike Kelly of Seaport Global. Please go ahead.
Michael Kelly -- Seaport Global -- Analyst
Good morning. Jim, really encouraging to see the progress being made in the efficiency front. And I just wanted to get your thoughts as you kind of move forward here, these variables you've shown on Slide 5, just the drilling and frac efficiency, are these going to be the key metrics that you're really going to want to manage to? Or if there -- curious, if there's some other kind of efficiency and productivity metrics that you have your eyes on where you could -- you think you could do kind of a similar type almost step change improvement going forward?
James J. Kleckner -- Chief Executive Officer and President
Mike, that's a great question and one that we look at very hard. We look at in the industry, it's a benchmark how we're doing. I think there are multiple metrics out there that we'll continue to use. Those were -- two of them that we chose, that we thought were substantial for us.
I think on the drilling footage per day is key as certainly as we're starting to look at extended reach laterals. But on frac stages per day, it's a little bit difficult because as you move into multi-well pads, you can get large variations in frac stages per day. So I wouldn't say we get anchored to those two, but where we're at right now, those are two relevant ones to our progress, and we're challenging our team to continue to improve on those as we look at our program here in 2018.
Michael Kelly -- Seaport Global -- Analyst
Great. Appreciate it. My follow-up is on the differential front, obviously been very topical this quarter. You guys looked fairly well-protected in '18 with the basis hedges.
Just I'd be curious on your longer-term strategy, the marketing front and how you potentially prepare for first half of '19 and beyond?
James J. Kleckner -- Chief Executive Officer and President
Mike, we continue -- we look at the market, and our strategy is to have about 50% to 70% of our volumes hedged on a rolling 12-month period. We're continuing to look at the basis out of the basin, and we'll look for opportune times to price into that. Obviously, they're very high right now. We feel comfortable about the position we have in 2018, and we'd like to lay some more on 2019 when the opportunity arises.
Michael Kelly -- Seaport Global -- Analyst
Got it. Thanks. Great output.
Operator
The next question is from Mike Scialla of Stifel. Please go ahead.
Michael Scialla -- Stifel Financial Corp. -- Analyst
Good morning, guys. I wanted to ask about your guidance a little bit. So the second-half production guidance is pretty flat with your second-quarter guidance. I guess, implied second half '18 production guidance.
You mentioned you're going to slow down. Just wondering if you can give any more detail around that piece of development. You'd forecasted 42 to 46 operated wells would come online this year. I guess, should we anticipate that that jumps up a bit in second quarter before slowing down in the second half? Or just any more detail you could provide there.
James J. Kleckner -- Chief Executive Officer and President
It's a good question on what we look like toward the next three quarters. I'm going to have Craig Walters, our COO, describe to you a little bit about our work programs so you can get an idea about of the pace of our drilling and completion activity.
Craig R. Walters -- Chief Operating Officer
Yes, this is Craig Walters. I think what we experienced in the first quarter is that we increased our completion crew count. We came into the year with one crew. We ramped to four, and we had more crews arriving from February through April.
Obviously, front-end-weighted program and really accelerating kind of the value in the production with those two that came on. And in our press release, we talked about the 20 year to date. And so we will continue to monitor that as we move forward obviously. We're looking at strong second-quarter drills.
And again, as we slow down in the second of the year, really that purpose is to allow us to integrate some of the 3D seismic and some of the additional sites that we have to make sure that our development program and pace it is on par with kind of our technical understanding of these reservoirs.
Michael Scialla -- Stifel Financial Corp. -- Analyst
OK. And I think you had forecasted, if I remember correctly, eight non-op wells for the -- or excuse me, six non-op wells for the full year, and I think you did eight in the first quarter. So was that somewhat of a surprise? And any update on what you'd anticipate there for the full year now?
James J. Kleckner -- Chief Executive Officer and President
Yeah. So a little bit of a surprise. Really some of those were carry in from 2017 activity and so the sales actually happened early in the first quarter. And we have not seen many more elections come through so far.
But that's always something that could hit us, I guess, as the year rolls on.
Michael Scialla -- Stifel Financial Corp. -- Analyst
OK. And wanted to ask about -- you talked a fair bit last quarter but want to investigate a little bit more on the integration of the 3D seismic, I guess, at Cochise and what you've seen so far at Whiskey River. Does that cause you to change any of your development plans? Or I guess, can you see anything you would have done differently previously if you've had that data? I guess I'm really wondering, does the benefit of the 3D primarily come down to just improved geosteering? Or is there any broader application you're realizing from that data?
John Roesink -- Vice President, Development Planning, and Geoscience
Hi, Mike. This is John Roesink, and you hit the nail on the head. It's just improved geosteering for the most part. The other upside, the other benefit that we're getting out of 3D is appraisal of some of the other zones, some of the deeper zones, like the Wolfcamp C, the Pennsylvanian all the way down through the Woodford, which obviously we've messaged that we're waiting for the 3D and Big Tex before proceeding with the Woodford development and appraisal.
So right now in Cochise and Whiskey River it's percent of lateral in zone targeting the highest quality shales. But as we go forward and as we think about the future and the development, it's being able to assess upside zones.
Michael Scialla -- Stifel Financial Corp. -- Analyst
OK, great. And just last one for me. Your first-quarter average on the 9,300-foot lateral, is that a good number for the remainder of the year? Or can you give us some sense as to how you think that might trend over the rest of the year?
James J. Kleckner -- Chief Executive Officer and President
Well, I think that's relatively high compared to what we've guided to when we came out with our 2018 guidance ranges. We were targeting 8,200 feet in our planning process. Obviously, depending on our integration seismic and data gathering initiatives, that could change through the year depending on how we change our target paths and some of our well plans.
Michael Scialla -- Stifel Financial Corp. -- Analyst
OK. So maybe a little bit higher than what we should anticipate for the rest of the year, it sounds like?
James J. Kleckner -- Chief Executive Officer and President
It could be.
Michael Scialla -- Stifel Financial Corp. -- Analyst
OK. Thank you.
Operator
The next question is from Jeoffrey Lambujon of Tudor, Pickering, Holt and Company.
Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Analyst
Good morning. Thanks for taking my questions. Just back on the efficiencies and the big quarter-over-quarter improvement. Can you talk more about what you're doing differently and describing at least from what you've seen so far?
Craig R. Walters -- Chief Operating Officer
Yes. On the -- this is Craig Walters. On the drilling side and as John Roesink just alluded to. I mean, really from a geosteering standpoint, it helps us to be proactive on that steering front.
And so that's driving some of the 13% quarter-over-quarter improvement on drilling as well as we've tested some different mud systems late last year. And we've now incorporated that new mud system across all five rigs that we've got running in the fleet. We've also made some bottomhole assembly changes on the drilling side. On the completion side, I mean, the efficiency increases we see there are really driven largely by being able to move onto these multi-well pads.
And so that's a big driver of the increase that you see, not just quarter over quarter but even the 3.1 stages per day that we talked about kind of in second-quarter-to-date numbers.
James J. Kleckner -- Chief Executive Officer and President
Jeoffrey, I'd like to -- I'd add to that, too. One of the benefits of having a base-loaded program is to be able to provide long-term contract arrangements with the service providers. And we're able to do that more and more as we develop our forward plan. We're seeing very good performance out of these service providers, both on the rigs and on the frac fleets as well.
Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Analyst
Appreciate that. And then in the slide, you highlight fully utilizing local sand by June. Can you comment on the savings expectations there? And also, if that's already baked in the guidance?
Craig R. Walters -- Chief Operating Officer
Yeah. This is Craig Walters again. On -- the savings would be about $400,000 on 9,000-foot lateral. We expect it to be 100% local sand in June.
We're currently about 70%, and that is baked into our numbers.
Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Analyst
Great. Thanks a lot.
Operator
The next question is from Scott Hanold of RBC Capital Markets.
Scott Hanold -- RBC Capital Markets -- Analyst
Thank you. Good morning. Could you talk a little bit about extending those lateral lengths a little bit more? And is that initiative really been aided by some of these acreage adds you've had? Or is that just a reconfiguration of where you are drilling?
James J. Kleckner -- Chief Executive Officer and President
No, I think we've had, all throughout the last year, a very solid contiguous acreage position. The land team has done an outstanding job on trades and blocking out. So we've been able to drill longer lengths. But part of it's been optimization of our drilling program, confidence and the ability to get out at longer depths.
And as John mentioned, more knowledge about the stratigraphy and our mapping horizons, so that we can stay in zone for longer reaches. It was one of the big emphasis to shoot 3D seismic and participate in the survey so as we took advantage of our contiguous acreage blocks, we want to be able to extend the lateral lengths and develop some economies of scale. So I would label it as drilling efficiency improvements, better understanding of the reservoir systems and the 3D seismic's ability to target that longer.
Scott Hanold -- RBC Capital Markets -- Analyst
OK. That's good color. And can you talk about some of the early learnings what you've been seeing from these longer laterals? And when you look at optimizing drilling, obviously, it's much more cost-effective, but how is it -- how is the, I guess, recoveries per lateral foot as you go to a three- to six-month period of time? Have you seen any change as you extend those laterals?
James J. Kleckner -- Chief Executive Officer and President
Well, it's still a little too early to fully weigh in on that. What we do see is that as you scale up a longer lateral, you should get close to a one-to-one build up on EUR per lateral length per 1,000 feet. What we don't see, as you would expect, as we manage flowbacks and bottomhole pressures during post flowback operations is that the IP24 and IP30 scale up one-to-one. So you're seeing a little more moderation in the initial flow rates, but we don't see any issues with EURs per 1,000 feet on the ratio of scaling up.
Scott Hanold -- RBC Capital Markets -- Analyst
OK. So you're – so effectively, you're seeing some good frac networks going on at this hole is what I'm hearing. Is that right?
James J. Kleckner -- Chief Executive Officer and President
Absolutely, yes. We're seeing good results on some roll-on-like laterals.
Scott Hanold -- RBC Capital Markets -- Analyst
OK. And on that Oryx acreage dedication and commitment, can you give a little color on what the -- what kind of the rate you all -- or generally it's range of rate you could -- that you would pay to get it from the field to the market point? And when you say it's a commitment, can you give a little color on that? I know it's an acreage commitment, but have they allocated a certain amount of that pipeline to Jagged Peak as you go into the 2019 time frame?
Ian Piper -- Vice President, Finance and Corporate Planning
Scott, this is Ian Piper. Yeah, you're exactly right. It is committed capacity and that space. It's reserved for us.
So it's guaranteed capacity that we have up over to Crane and on up to Midland. Our gathering rate on that system is around $1.90 a barrel.
Scott Hanold -- RBC Capital Markets -- Analyst
OK. Appreciate that. Thank you.
Operator
The next question is from Irene Haas of Imperial Capital.
Irene Haas -- Imperial Capital -- Analyst
Hey. Good morning, everybody. My question is on the 3D seismic. Now that you've got some data coming in from the Cochise area, can you actually see the bounding fault? Maybe drilling heads is popping out.
And then regarding the older section, closer to the basin margin, can you identify the Woodford? And also maybe a little color on the Bone Springs. Do they work? Is it lower priorities as of now because you're pursuing the Wolfcamp A?
John Roesink -- Vice President, Development Planning, and Geoscience
Irene, this is John Roesink. And starting at the back and answering your last question first. Yeah, the Bone Spring still looks really good, but we are kind of in leasehold mode still, so we're drilling Wolfcamp wells to hold the most areal extent and vertical stratigraphic extent of our acreage. The question about seeing the Woodford on the 3D, we can image the deeper section very well.
There's a great acoustic impedance contrast between the missed line and the Woodford. So we're very able to image and get good high-quality interpretation of the Woodford and the deeper interval. And then we don't actually see the basin-bounding faults in our acreage in Cochise. There are some deeper structures.
The Wolfcamp, Permian age rocks filled the basin that had a lot of dissymmetry and a lot of relief on the subsea on the floor of the Paleo ocean there. So we don't see the edge of the basin in that acreage, but you can image deeper faults and deeper structures quite well.
Irene Haas -- Imperial Capital -- Analyst
OK. Thank you.
Operator
The next question is from John Nelson of Goldman Sachs.
John Nelson -- Goldman Sachs -- Analyst
Good morning, and thank you for taking my questions. I'm sorry if this is a bit repetitive. I think we're all probably going to be aiming toward your activity pace in the back half. But I understand the 3D integration will make future wells more productive, but I guess I'm just trying to understand what you would need to see to maybe not drop activity as sharply in 3Q and 4Q given that current well return still seems to be quite strong? And yes, I'll leave it at that.
James J. Kleckner -- Chief Executive Officer and President
Well, one of the things that we feel is paramount to a successful development program is to have a pace of activity that invests capital wisely and not outpace that technical learning curve. We think it's critical not only from the 3D seismic, but other information we'll be gathering from core and fluid property data that we'll be able to make better and more informed decisions as that data comes to us and we put it to work, we analyze it and we make decisions off of it. I think we -- you can see us adjust our capital spend rate. One of the things that we're very proud of, we have over 2,000 well locations we're producing from eight target horizons.
We've got a concentrated acreage position with 100% company-operated water delivery and disposal. And so the challenge for us is to pull that inventory forward and drive value forward. We're continually looking at how to do that. And I think as we move through the year, we'll evaluate and correct as we need to base off the information received.
Operator
The next question is from Biju Perincheril of Susquehanna.
Biju Perincheril -- Susquehanna International Group -- Analyst
Hi, good morning. When you're drilling primarily the lower A formation, can you talk about when you -- how are you thinking about the upper A locations when you come back and drill those in the future? Do these two landing zones have to be co-developed? And does the sort of a slowdown in the second half have anything to do with integrating that information and moving that into a more, into a full-scale development?
James J. Kleckner -- Chief Executive Officer and President
Good morning, Biju, and thanks for the question. We missed the very first part of your question. Could you repeat it, please?
Biju Perincheril -- Susquehanna International Group -- Analyst
Yeah, sure. You mentioned that you're primarily focusing on the lower A of -- and how should we think about the upper A locations adjacent when you come back and drill those in the future? Can these two develop independently? Or are those have to be developed -- codeveloped? Sort of a parent-child concern.
John Roesink -- Vice President, Development Planning, and Geoscience
Right. I think I get the gist of your question, Biju. And yes, it is a very important piece of the data gathering and integration process. What's going on this year is figuring out optimal development of all the targets and all the reservoirs and what the impact of timing is on development of wells and subsequent drills.
At this point, we're encouraged by what we've seen from our co-development on our simultaneous zipper fracking of upper and lower As. This year, we're going to look at designing some experiments to test infill drilling around an existing parent well. So I would hesitate to give you any specifics about what we think. We're encouraged by what we've seen so far in the co-development, and we're encouraged in the instances where we have drilled in the same bench, say, the lower Wolfcamp A offsetting an existing producer.
So we think that there is the proper application of well management, production management and pressuring up existing producing wells prior to offset completions that will allow us to preserve the maximum amount of resource in place and have the minimum negative impacts from parent-child development.
Biju Perincheril -- Susquehanna International Group -- Analyst
Got it. That's helpful. And my follow-up was on the -- I think you had Bone Spring well that came on in the first quarter. I know you talked about it being lower priority now.
But can you give us any color on how that second Bone Spring well compared to the first one you have talked about previously?
John Roesink -- Vice President, Development Planning, and Geoscience
Yeah, Biju. It did come on in late in the first quarter. It's cleaning up. We saw some interesting structure when we drilled that well, so we saw some faults we think we're going to refracturing it.
And so it's taking a little longer to clean up than the previous well, but we're encouraged by initial production and initial rates. And as it continues to clean up and as we get more data, I'm sure we'll come back with some information about it.
Biju Perincheril -- Susquehanna International Group -- Analyst
OK. Helpful. Thank you.
Operator
This concludes the question-and-answer session. I would like to turn the conference back over to Jim Kleckner for any closing remarks.
James J. Kleckner -- Chief Executive Officer and President
Thank you for your time on the call this morning. As I said earlier, we're off to a good start in 2018. I'm very excited about joining Jagged Peak and being part of this elated team, which has created tremendous value as a pure-play Delaware Basin company. Thank you very much again.
and have a good day.
Operator
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
Duration: 33 minutes
Call Participants:
Robert W. Howard -- Chief Financial Officer
James J. Kleckner -- Chief Executive Officer and President
Michael Kelly -- Seaport Global -- Analyst
Michael Scialla -- Stifel Financial Corp. -- Analyst
Craig R. Walters -- Chief Operating Officer
John Roesink -- Vice President, Development Planning, and Geoscience
Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Analyst
Scott Hanold -- RBC Capital Markets -- Analyst
Ian Piper -- Vice President, Finance and Corporate Planning
Irene Haas -- Imperial Capital -- Analyst
John Nelson -- Goldman Sachs -- Analyst
Biju Perincheril -- Susquehanna International Group -- Analyst
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