Q2 2019 Earnings Call
Today.
This time I would like to welcome everyone to the jagged peak energy second quarter earnings and operational update.
All lines have been placed on mute to prevent any background noise.
After the speakers remarks, there will be a question and answer session.
If you would like to ask a question. During this time press Star then the number one on your telephone keypad.
If you would like to withdraw your question press the pound key.
I will now turn the call over to James Edwards, you May begin your conference.
Thank you Mike.
Good morning, everyone and welcome to Jackie Peak Energy's second quarter 2019 earnings Conference call.
With us on the call today are Jim Kleckner, CEO and president.
Craig Walters, MVP and COO Bob Walters.
Well powered our EVP and CFO and Piper VP of finance corporate planning, Daniel Berger VP of land.
That's the evening, we issued our second quarter earnings release, and our 10-Q, both of which are available on our website, a jagged peak energy dotcom.
During our discussion this morning will be referencing flights from our August investor presentation, which can be found on the presentations page under Investor Relations section of our website.
During this call will 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 century.
Materials also includes 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 countries of activity 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 the earnings call presentation, I'll now turn the call over to Jim for his review of the quarter.
Good morning, everyone and thank you for joining us for the second quarter Conference call.
I'm going to start call. This morning's comments on the quarter, and then hand over to Craig to talk to somebody 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 the bluepoint worked guidance production volumes from both the midpoint of our guidance range for the quarter.
It's a team effort and I want to take 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 costs of 1200 $60 per lateral foot.
In the first half of the year or do you see any cost per foot.
Decreased by 12% from 2018 levels to 1200 $70.
This decrease was achieved by optimizing the capital efficiency of a well designed leverage and operating efficiencies utilizing strategic sourcing materials to reduce the cost of consumables.
In the second half the year, we expect to continue to capture incremental leverage additional operating efficiencies all the development projects.
Capturing these gains we've been able to stay on pace to meet our capital guidance midpoint for the year was half of our annual investments made in the first two quarters and shown on slide 11 total August investor presentation.
In the second half the year, we expect our quarterly spending peaked in the third quarter is viewed loans two completion crews throughout the quarter to complete the Korea incentive projects.
Production is forecasted to increase by 3% in the third quarter as Coram has turned online in late August .
And 15% in the fourth quarter as venomous turned online in late October .
From an operating margin standpoint, we remain.
We focused on maintaining talk to your margins driven by some of the basins highest oil cuts and lowest ela, we could be weak.
While our Ela, we preview is increased as a fuel relies more on artificial lift.
Reduced our June guidance on an absolute and per unit basis, which is neutralized the impact on our EBITDAX margin.
That all Chesapeake remains focused on line on its core competencies and operational execution by running this business as effectively as possible and our second quarter results are continued examples of that execution.
By focusing on things within our control we plan to continue to grow our asset base keep leverage in check.
A point, where we were 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.
Quarter.
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 projects projected peak.
On slide 14 of our Investor presentation, we have provided an overview and update of the project and I'm 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 in the large pad with three separate drilling rigs each drilling two wells.
By utilizing three rigs we reduced the amount of time from spud to sales increasing the project rate of return.
With all six well successfully 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 optimized placed.
After the rigs are released from the project we brought in two completion crews. So much of the rigs were brought in to shorten cycle times and also leveraged positive frac interference design to increase overall stimulated rock volume.
To date, we have successfully completed four of the six wells and are currently finishing up completing the remaining two 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 under the map on slide 14.
This central facilities designed to handle production from all six wells a further improvement to capital efficiency as we transition away from single and two will facilities.
As you can see on the gun barrel flat on the top left corner of the slide we have plan. These wells to be space quite conservatively with lateral spacing of approximately 1320 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 overcapitalized and the rock.
Our next two development scale projects, the venom and use yelp projects.
Well, 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 are brought online two delineation wells. The first of which was placed in the west Central area Big text targeting the Wolfcamp a formation and a high graded geologic fairway fairway that was informed by the Threed seismic and other geologic data acquired at the end of last year.
The second of these wells is placed in the southeast corner of our acreage targeting the Woodford formation.
As you can see on the slide both wells and had encouraging early results.
The first well the state Big Tech 70, 673 Dash eight cash 11 age targeted the Wolfcamp, a and was placed 99% in zone with a 10250 foot lateral.
This well early time cumulative production has been strong outperforming our average historical big tax results by a wide margin.
The well was recently put on electrical submersible pump.
And have the most recent seven day average oil rate of 1077 barrels per day notable as well has been on production for over 130 days.
The second well in the slide as the primary well, which targeted the Woodford formation.
This is the company second Woodford test the first being a short lateral which was completed back in 2017.
The primary well as 6400 foot lateral place entirely in zone with encouraging early time production, which surpassed the normalize IP rate of the company's first Woodford well.
No. It is too early for an assessment of overall, well performance or even a 90 day IP rate wells normalized peak IP 30 of 294 BOE per day per 1000 lateral feet is certainly impressive.
We will continue to monitor the results of these wells and look forward to the results from the two remaining high graded 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 tax in 2020, as we do not currently have plans to reallocate capital from Whiskey River to big tax in our 2019 program.
With that I'll turn the call over to the operator for us to answer any questions.
At this time I'd like to remind everyone in order to ask a question press star one on your telephone keypad.
To withdraw your question press the pound key we will pause for a moment to compile the acuity roster.
Your first question comes from Brian Downey from 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 in momentum in to next year. The results announced today, a big tax and the inherent free cash flow debate in the Smitti MP space not to mention commodity price volatility, how you're thinking about approaching 2020 planning from a high level any any particularly strong governors, we should we should think about.
Brian Thanks for the Kohl's Jim.
Yes, Brian we start or a formal budget process. This fall.
And we'll be looking at capital allocation based off the results as we just discussed.
But also based on some of the proposals received from flowback on the pads of Macquarie ever possibly develop so I think it's a little 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 off of a conservative debt at $50 and we plan our capital allocation based off of maximizing.
Well I, our orders on a $50 deck and door capital spend.
Yes.
Governed by.
Our.
To equity ratio. So we'll stay very consistent with how we've operated in the past.
Got it and then maybe a maybe a follow up just given your do you see any cost targets, how should we think about.
If you move to larger projects within the portfolio, how do our cost trending at the coriander pad on on a lateral foot basis versus what you're seeing in the rest of the average portfolio.
I'll, let Greg handle some of the early results that were seeing on past performance is Craig Walters. So yeah on the DC any 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 equipped for the field facilities was 14 50 per foot.
You know we're currently a year to date average 12 70 last quarter was a 12 50 on a per foot basis.
As we look at the the coriander and now venom, we are realizing some incremental efficiencies are definitely on the drilling side, it's been very beneficial for us to have you know 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 the rig fleet and so I would expect to know our capital efficiency members to continue to fall slightly through the rest of the year.
No, it's really hard to predict exactly what we will see I think on the coriander genomes.
Till we get those projects completely wrapped up.
All right nice results. Thanks for taking the question.
Your next question comes from Gabe Daoud from Cowen.
Hey, good morning, guys.
Given the given the efficiencies that you have seen so far and kind of on track with the.
Do you see any or DMC target per foot.
Kind of wondering at the very least for 2020. If you were to think about maintaining the same pace as you as you have been in 2018 do you think that at the very least the budget for next year potentially be lower than than than what we're seeing in 2019.
Well again, we havent.
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.
Learn more about pad development efficiency gains, we are seeing continuous improvement coming modeling from our drilling teams put on completion teams have also seen improving cost per infrastructure as we as we bring wells into larger central facilities. So as we continue to move in that direction.
We would anticipate improving capital efficiency.
Too early to comment at this point.
Thanks, Jim that's helpful. And then just as a follow up obviously, you guys have a pretty attractive and.
Robust water infrastructure assets. So, we're just kind of thinking and I know.
I've talked about previously, but how you balance the benefits of that from from the Opex side versus maybe potentially.
No divesting it just given a lot of interest in assets like this in the market. Thank you.
Yes from a.
From the perspective of managing.
An unconventional play to give up water is absolutely critical to habits.
At the readiness of operations because of all the integration of we'll be drilling or completion and then the production side of it as far as the incremental benefits I'll, let Craig talk to that that we see of operating in.
Owning our own water business.
Yeah. This is Craig you know as we've looked at the you know kind of 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 projected peak, but for anybody.
As we look to source water fracs.
And then you know on a produced water basis, you know we have roughly a 2.5 water oil ratio. So that had water production is going to be with us for the life of the well.
As we look at the having the kind of the 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.
Understood. Thanks, Craig Thank you.
Your next question comes from Neal Dingmann from Suntrust.
Hi, guys could you talk about what options do you think you have been in sort of big tax all the different options.
Yes, good morning, Neil.
Good question from a loss perspective, I think it's pretty consistent with what we've messaged in the past.
The Big Texas provides a lot of optionality to our portfolio and starting last year as Craig mentioned, we integrated sort of surface data Gigi information to improve our understanding a big Tex.
And focused on five wells going forward.
Three of those wells, we've seen them flow back in the other two will be coming up settling for us more about the path that we want to take but that being said the last two wells that we've held test are very encouraging we're excited about that as far as options. There are many.
We can allocate drilling capital if the wells that are compete with Whiskey River and our co cheese portfolio. We can release, we can form out and there are multiple other commercial solutions, including Drillco JV that we could look at to preserve optionality.
No. That's good to hear I agree I think there is a lot of options. There and then took lastly on a go forward. It's notable your capital efficiencies that you continue to see both from an operational and financial standpoint, I'm just wondering.
You know how do you view I guess when you think about the larger pad development.
From two aspects one just given that your smaller size them too.
Just the sort of lumpiness in a cash flow at that causes a little bit maybe per year about how you just I guess sort of view that from an operational perspective.
Yeah.
I'll, let Craig talk about the.
If you use a baseball analogy what inning are you anything unconventional play development.
Certainly as we move into.
Pad development.
The complexities of the Delaware Basin, which are multi stack leveled horizons.
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.
Yeah on the drilling side, especially I think we're still early innings, I'll say, a 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'll recall, we 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 I still think we're early on the drilling side.
Completions, you know, 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 will be key for us I think as we move into the development of these bounded multi well co developments.
You know its 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.
I have that positive frac interference to create increased stimulated rock volume and then Neil the second part of your question was.
Relating to the Lumpiness of the cash cycle, Bob do you want to comment yes.
Yeah, We did I think when things were doing we will push the packs have to invest.
More trouble now reduced cycle time to bring those wells on quicker.
We will need to work with and we'll see some of the lumpiness with the cap will be inspecting production coming on line and that's.
Kind of on the work that we have to do is we transformed from a single and two well pads into work multi well pads as derica borrowing capacity that will match up but do expect that to get the efficiencies from bringing that production on all the same time to get through extensive wells payback thats feedback quickly.
Hey, guys. Thanks, much for all the answers.
Your next question comes from Neil Mariani from Keybanc.
Hi, guys I was hoping to get a little bit more color on big tax in terms of how many of that is 29000 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 I don't have those results kind of prompted more discussions on other farm outs are drilled because.
You feel like those results are kind of getting up to get one of those deals done.
Well you know I think there are a lot of commercial avenues open for Big Texas, I mentioned earlier and certainly when you have positive and encouraging well results.
Those opportunities become.
In a much much better and.
You know I think it's too early to comment on any type of acreage expiry that could occur and big text. This year next year.
Other than we're studying it very carefully.
With an eye on capital allocation and our overall portfolio and Optionality of the acreage that we haven't been text.
Okay.
And I guess.
Additionally, kind of sticking with big tax year. So just trying to get a sense what would the cost was that recent wolfcamp, a well as well as your your Woodford well there.
Yeah. This is Craig Walter so as far as the cost associated with those two particular wells down in big takes a little bit higher than our 12 $50 per foot average those are single wells. So we had to build a single well facilities and we also didnt get the benefit of.
Zipper completion or Simax type operations, there so it was little bit higher than our 12 50 number.
Okay. That's helpful and I guess, just with respect to DNA looks like you guys certainly tight pretty good chunk out of that added the guidance. This year can you just kind of talk through a little bit Uh huh.
Hi, guys able to do that in mind, you see further reductions going forward.
Yeah absolutely.
We look at our June eight courses.
Yeah on the cash.
Yes, so as we looked at our pace of activity in 2019 and beyond we simply Readdressed organizational.
Needs and.
And focused on driving cost down to protect margins at the end of the day. This is all margin game and we've got to improve on cost and certainly strive to offset any leakage of loss of margin.
Okay. Thanks.
Your next question comes from Michael Fiano from Stifel.
Hey, good morning, everybody.
Looking at.
Your your inventory and know what you've drilled so far just wondering.
Are there any more zone do you like the test at this point or do you feel like you have pretty well delineated vertical column at this point.
Craig why don't you speak to what we've got as far as.
Ongoing appraisal exercise room focused on our core areas, but we are we are testing continue to test various zones throughout the.
Hey, Michael This is Craig Great question as we look at kind of a you know that.
Full column that we have available to us I mean, obviously, our focus has been I'll say third bone spring through the Wolfcamp b.
No we demonstrated kind of a percent of wells that we're going to have this year in those various horizons and.
A little bit over 50% Wolfcamp, a and then I think it was equal to 22% each in the third bone and Wolfcamp B, we do have some.
Thank you, we have a well drilling right now and into the second bone spring well.
You know excited to this will be our third bone spring well cross jagged peaks portfolio.
So excited to see what that will do.
Our our G. and G. and subsurface team continues to evaluate those other horizons, but we don't have any plans currently to go out and test.
Okay, and that second bone spring, well, Craig where is that located.
Sorry, it's in Whiskey River.
Okay.
And then just looking at.
Slide 15.
Your.
Wolfcamp a well in.
Big Tech so looks like it.
Had an uptick in productivity after about 100 days I assume that's.
That 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.
And Michael This is Craig again, so gay you noticed it very well I mean, basically a day a 110, you see that slight inflection that's exactly when we install 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 safety from an operating cost standpoint, and again, the well was performing nicely up until that point.
Yeah happy to put the south on you I talked about it in the prepared remarks, but we're almost 1100 barrels of oil per day past seven days, so that well.
Looking very encouraging right now.
That's a pretty typical pump installation time as we look across kind of whiskey River that was kind of that three two.
I'll say six month mark dependent upon the wall.
Got it Okay. This last one for me, Jim just kind of philosophical question.
You guys have I think done a pretty darn good job since youve.
Taking over the helm there pretty much done everything you said generally beat numbers every quarter.
Your stocks down 26% this year kind of in line with the.
The rest of your midcap peers.
Just wondering your thoughts on what do you do.
Differently too.
Make your your stock moving the other direction does the.
The idea of merger of equals make any sense to from a.
Philosophical standpoint, or anything else that.
You could add there.
No. That's an interesting question and certainly one that.
Comes up quite frequently.
Our view is that the deep inventory, we have and the runway that we've got in front of us more operational efficiency capital efficiency gains there and we feel strongly that we can continue to improve.
The returns on our wells as we shift into the Codell pads.
I do firmly believe that.
By focusing on increasing economic value through very thoughtful allocation of capital and improving individual well returns will be.
Yeah, Ana click over the company.
And and return cash to shareholders and Thats, our focus right now so as far as philosophical discussions on.
Im always or other type activities.
We're very focused on our core business right now and we see that as the best routes are growing value.
Demonstrating that in our ability to do that over the next several quarters as we shift to pads is going to be critical and.
And showing the market and our investors that we can deliver it I think our past five quarters, we've delivered on that and we anticipate delivering on that in the future.
I appreciate the answer thanks.
Your next question comes from Irene Haas from Imperial capital.
Yes, congratulations on the success you have in the tax area and I was kind of curious how much did you spend exactly in dollar millions dollars in 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 successful venture what are the plans to take away the Woodford gas.
Good morning, everyone and thanks for your question.
I think Craig mentioned that we spent over the 12 50, we don't want to give any specific numbers because I don't think were full in the on what those numbers are but it's very close to what Craig mentioned and.
You know the.
The comment on these being single wells as you don't have shared infrastructure. So those costs are expected to be higher.
We moved into a development phase obviously, we would have shared infrastructure and they would come in line with.
Our cost throughout.
Our fuel development operations.
As far as gas take away.
You can comment on.
What our view is long gas take away the current market, Yes, Irene I think your question was on gas Baytex.
You know there are a number of midstream companies down there with options surrounding us or.
For West and South.
Thats correct.
Actively evaluating but with the long haul flying.
On your September October timeframe.
We don't.
Great from what I remember you guys are not far away from the regional trunk lines. There is that is that right.
That's right, but lot of sits directly to the lowest dose.
Great. Thank you.
Your next question comes from Paul Grigel from Macquarie.
Hi, 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 with Gilbert.
Correct.
Paul We had a hard time here, but I think let me just repeat your question make sure we understand.
What were the HBP requirements for which can either in the retirements.
Yeah in terms of number brings.
Craig do you want to comment on that really on the per day, if I can take that yesterday that Colbert are where we're in a really good position in whiskey River. We're about 92% of Whiskey River is HBP are in continuous development and we've got really manageable number of obligation wells in 2020, it's less than 10 obligation wells next year.
Okay, Great and then I guess, maybe changed over to the Elouise 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 the lifting and should we kind of view that as a new baseline level moving forward.
Into into 2020 beyond.
Yeah. This is Greg as our Ela, we expenses came in for the first and you know the first half of 2019, and just an expectation around kind of our E S P or electrical submersible pump.
What it costs us to run those from a power standpoint.
As well as you know some workover expenses and so we I think as we reset our guidance.
You know I would expect that to but definitely near term kind of be our go forward dollar per diem.
And is that is there kind of continuous power issues that are causing that or is it is it something that may be found overtime is into play continues to yeah. Yeah, 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 yes Pete.
Okay. Thanks for clarifying thank you.
Your next question comes from Kashy Harrison from Simmons energy.
Hi, Good morning, Thank you for taking my questions.
And apologies. If this was it was asked earlier at the drop of for a second but.
Have you what's the size of the core position in big tax of this of this fairway that you're currently attacking.
In acres.
Well, we're we're still testing that Casey and we won't really have the results of those tests and so we finished these last two wells because they'll help define what that core looks like you know weve gone through a lot of mapping integration of Threed seismic data geological information and ER.
We've got a view of you know the various area, but we don't have it specified yet as far as.
Core and what that acres designation looks like.
Got it and then as we as we you know understanding that it's too early to think through specifics for 2020 I was just wondering if you were to it.
Do you have a sense of what that maintenance capital estimate could be to hold the exit rate for this year flatten into into the next year.
We've looked at that from a lot of different aspects and.
Around four rigs or three and a half rigs is is generally where we see that.
Does that help your question.
Yes.
And as a reminder to ask a question press star one on your telephone keypad.
We have no further questions at this time I will turn the call back over to the presenters.
Thank you again for joining us on the calls morning, we look forward to answering the questions and taking your feedback one of the many conferences, we haven't got coming months.
This concludes today's conference call you may now disconnect.
Hmm.