Current JAG Stock Info

Completions operations becoming increasingly efficient

Jagged Peak (ticker: JAG) announced first quarter results today, showing a net loss of $39.4 million, or $(0.18) per common share.

Jagged Peak has come a long way since going public in early 2017, with tremendous production growth over the last year. The company produced 27.6 MBOEPD in Q1 2018, an increase of 182% year-over-year and 15% quarterly.

Jagged Peak brought a total of 11 wells online this quarter, and spud 12. The company is making good use of its relatively consolidated acreage position, drilling ever longer wells. The average completed well this quarter had a lateral length of 9,300 feet, a record for Jagged Peak. The company is also completing wells ever faster, averaging 2.6 stages per crew per day in Q1, an increase of 13% compared to Q4. These improvements have continued beyond Q1, as the company reports it is averaging 3.1 stages per crew per day so far in Q2.

Jagged Peak is beginning to receive the results of its previously announced 3D seismic data shoot, and interpretation of the Whiskey River section is in progress. In the Big Tex area acquisition is currently underway, with processed data expected in the second half of 2018. Jagged Peak plans to develop its acreage gradually in the next few months, waiting until after the company is able to analyze these results to accelerate operations.

Jagged Peak Looks to 3D Seismic to Improve Drilling

66% of 2018 production hedged at just under Cushing prices

Jagged Peak President and CEO Jim Kleckner also discussed the company’s takeaway commitments, as differentials have become a major concern for Permian companies in recent months. “Addressing the current and anticipated midstream tightness within the Permian Basin,” he said, “we have 60,000 Bo/d of committed capacity on the Oryx system providing access to key regional market hubs in Crane and Midland. Further, we have basis hedges in place for approximately 66% of our anticipated 2018 oil production at a differential of less than $1 below Cushing prices.

This gives us confidence in our forecasted realized pricing throughout 2018. Looking into 2019, we have 8,000 barrels per day of basis hedges in place at a differential of just over $1 less than Cushing prices. We believe our committed capacity on the Oryx gathering system, existing sales agreements and basis hedges put us in an advantaged position to ensure our barrels flow out of the basin at attractive realized prices.”

Jagged Peak Looks to 3D Seismic to Improve Drilling

Considering the company’s overall plan for 2018, Kleckner said “We remain committed to increasing our technical understanding of the reservoir systems by integrating 3D seismic and other data initiatives, and the first quarter represented an elevated activity level relative to the remainder of 2018 as we still plan to manage our activity in coordination with these technical data initiatives. Data acquisition and interpretation is advancing ahead of schedule, with Cochise and Whiskey River data already being integrated into our development planning and workflow.

“We believe this disciplined approach to development will help us generate improved well results and returns by reducing drilling cycle times, drilling longer laterals and optimizing completions. In 2018, the majority of our activity will be focused in the lower Wolfcamp A formation in Cochise and Whiskey River, and we expect to spud 40 to 45 gross operated wells and place on production 42 to 46 gross operated wells. We forecast this activity level to result in total average production of 28,000 to 31,000 Boe/d for 2018. We remain confident that our planned 2018 activity level properly balances the long-term development of our assets with a focus on generating attractive corporate-level returns, while maintaining financial discipline and a conservative leverage profile.”

Q&A from JAG conference call

Q: Wanted to investigate a little bit more on the integration of 3D seismic, I guess at Cochise and what you’ve seen so far at Whiskey River. Has that caused you to change any of your development plans? Or I guess, can you see anything you would have done differently previously if you’d had that data? I guess I’m really wondering, does the benefit of the 3D primarily come down to just improved geo-steering or is there any broader application you’re realizing from that data?

Jag: You hit the nail on the head. It’s just improved geo-steering for the most part. The other upside – the other benefit that we’re getting out of the 3D is the appraisal of some of the other zones – some of the deeper zones like 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, its percent of lateral in zone, targeting the highest quality shales. But as we go forward and as we think about the future in the development, it’s being able to assess upside zones.

Q: Just back on the efficiencies and the big quarter-over-quarter improvement, can you talk more about what you’re doing differently that’s driving that, at least from what you’ve seen so far?

JAG: On the drilling side and as John Roesink has alluded to, from a geo-steering standpoint, it helps us to be proactive on that steering process, and so that’s driving some of the 13% quarter-over-quarter improvement on drilling as well as we had tested some different mud systems late last year and we’ve now incorporated that new mud system across all five rigs that we got running in the fleet. We’ve also made some bottom hole 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 on to 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 talk about kind of in second quarter to date numbers.

JAG: 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 and we’re seeing very good performance out of these service providers, both on the rigs and on the frac fleets as well.

Q: I’m sorry if this is a bit repetitive. I think we’re all probably going to be aiming towards 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 returns still seem to be quite strong, and – yeah, I’ll leave it at that.

JAG: Well, one of the things that we feel is paramount to a successful development program is to have a piece of activity that invests capital wisely and not outpace that technical learning curve. We think it’s critical that not only from a 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 could 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, based off the information we’re seeing.

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