Q3 2020 Bonanza Creek Energy Inc Earnings Call
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Ladies and gentlemen, please stand by your conference call scheduled to begin momentarily. Thank you for your patience as we continue to standby.
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Todays conference is being recorded and if you acquire anything assistance. Please press star zero.
Looking at the conference over to your Speaker today Scott manager. Please go ahead.
Thanks, Andy Good morning, everyone and welcome to Bonanza Creek's third quarter 2020 earnings conference call and webcast on.
On the call. This morning, I'm joined by Eric Rager, President and CEO, Brett <unk> Muse executive.
Executive Vice President CFO and.
Other members of the senior management team.
Yesterday, we issued our earnings press release posted a new investor presentation and filed our 10-Q and you get to see all of which can be found on the Investor Relations section of our website some of the slides and the current investor presentation, maybe referenced during our remarks this morning.
Please be aware that our remarks will include forward looking statements are subject to many risks and uncertainties that could cause actual results to differ materially from these statements you should read our full disclosures regarding forward looking statements contained in our 10-Q 10-K and other FCC filings.
Also during this call we will refer to certain non-GAAP financial measures because we believe they are good metrics to use in evaluating performance reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release and Investor presentation.
We will start the call with prepared remarks, and then moved to Q today now I'd like to turn the call over to Erik rigor President CEO Eric.
Thanks, Scott Good morning, everyone and thank you for joining us today for our third quarter earnings call. We're.
We're pleased with the quarter, we reported yesterday I. Appreciate your time this morning discussing the results.
As with previous quarters I'll briefly cover a few highlights from the quarter provide some color for the fourth quarter and started 2021 and then open up the line for Q1 <unk>.
Our production volumes have remained resilient despite limited capital investment since the first quarter.
While oil volumes were flat from Twoq to Threeq, you RBL, we volumes increased 6% sequentially to 26.2 Mboe per day.
Year to date production has averaged 25.3 mboe per day and as a result, and based on our view of the fourth quarter. We are raising annual production guidance from a range of 24 to 25 Mboe per day to a range of 25 to 25, and a half and Bailey per day.
We also tightened our annual oil mix guidance to a range of 54% to 56% as a result of higher gas volumes during the third quarter.
Hello, We performance has been strong throughout the year with the third quarter metric of $2.23 per Boe, representing the lowest unit LNG that the company has ever recorded.
Our year to date, although we have $2.43 per BOE is ahead of our expectations for the year and Weve revised our annual allergy guidance accordingly from a range of $2.50 to $2.90 per Boe.
To a range of $2.40 to $2.60 per Boe.
For our in my operating expenses, we've been more or less on pace with our annual expectations for the year, but it brought down the upper end of our guidance range from $1.50 to $1.85 per Boe to $1.50 to $1.80 per BOE, we based our expectations for the fourth quarter.
Recurring cash DNA was $2.56 per Boe for the quarter and brings our year to date recurring cash DNA to a total of $20.1 million.
We've tightened our annual estimate for recurring cash DNA to a range of $26 million to $28 million down from a range of $27 million to $29 million.
Capex for the third quarter was minimal as planned at $1.8 million.
Bringing the year to date capital investment to $64.6 million.
Today, we reiterate the previously provided annual Capex guidance range of $60 million to $70 million.
Free cash generated during the quarter was used to pay down the RBL by $38 million to $20 million drawn as of the end of the quarter.
We continue to make progress toward paying off the balance since the end of the quarter and currently have 10 million drawn.
Our production profile over the last six quarters going back to 24.4 Mboe per day into Q of 19.
As shown on slide four of the current IR deck demonstrates the capital efficiency, we look to employ again as we head into 2021.
Currently we expect to begin the year by completing ducs in inventory.
Despite the resiliency we've seen in recent quarters, we do expect volumes to be lower in the first half of 2021 than we do in the second half of the year, while the capital investment will be weighted towards the first half.
We still anticipate 2021 full year production to be approximately flat to full year 2019.
With that I will turn the call back to the operator for today.
Thank you ladies and gentlemen, if you have a question at this time.
Please press the star in the one key on your telephone.
Once again, so I wanted to ask a question.
First question comes from Jordan Levy with Qs Securities. Your line is open.
Good morning, all you've done a really good job driving down.
Operating expenses it looks like just in general capital costs would come down as well I just want to see how you guys are looking at that for 2021 and <unk> point.
Yes.
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Can't drive the operating a stepping down to zero, but no.
How do you see those two items trend that you are moving into next year.
Thanks, Jordan good morning.
You know I think that.
As you point out there there is a lower bound I don't think we're there yet.
I think Dan and his team will continue to find opportunities.
But but as you've probably seen just in the.
In the column chart in our deck and over time tracking the company.
The rate of change in the rate of descent in unit cost is.
Decreasing as we as we kind of approach that lower bound so what I would say is next year's unit.
Unit costs across the board, whether we're talking about recurring cash DNA.
Entered ela, we or unit opex, including RMR are probably going to be pretty consistent with this year I think we'll continue to find opportunities.
And perhaps the the volumes in 2021 won't be quite as strong as they are in 20 and and so I think that's going to point to unit.
Operating expenses kind of in line with 2020.
Thanks, So much guys you bet.
Thank you and our next question comes from Michael Gallo with Stifel. Your line is open.
Yes, good morning, guys.
Thank you.
Thoughts on regulatory issues.
And it really has no real impact from the two.
2000 foot setback from upgrades structures, but.
Wanted to see what you're thinking in terms of the setbacks. The Seo GCC is proposing from repair in areas.
Yeah. Thanks, Good morning, Mike.
It's a good question and.
You know I haven't seen anything formal coming out of the C or GCC in terms of how theyre, how they're leaning on it but.
My hunch is that it's going to be weighted toward permanent bodies of water.
So you know permanent reservoir as permanent lakes permanently running reversion streams and I think the bias there is around protecting fish species.
And.
Wildlife Raptors and alike.
Who often congregate around permanent bodies of water. So so my hunch is it's probably not going to include again. This is.
This has not informed by any intelligence I have beyond what you and everyone else has only that.
I believe this to be the direction.
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That is that it would be heading.
That it's going to be your oriented around permanent bodies of water because it's it's meant to protect fish species and and raptor, so they'll probably be some some offset distances.
That will impact sighting requirements around raptor nests known Raptor nast's, there might in fact be some consideration.
Consideration around surveying for Raptor announced we've seen this in other.
Other places around the country that that I've I have experience in Texas.
New Mexico and elsewhere so.
Short answer is we don't know.
That's that's a hunch as an expectation and we we anticipate that it won't be very impactful I don't anticipate.
Any any setback distance or buffer zones to be nearly as significant in terms of just the bus, though the length the 2000 foot.
From occupied structures I don't think anything related to bodies of water.
Are going to be nearly that that large I would anticipate that perhaps in.
Under a 1000 feet, perhaps 300 to 500 feet might be reasonable.
But again I don't know anything more than than you know this is Mike.
My hunch based on what I understand to be the driving factors behind.
Those protections.
Well I appreciate that.
And.
Wanted to ask you about.
If you've been.
Floating your wells back any differently this year versus last you've been able to.
Hold your production or actually even grow it a little bit less.
Last couple of quarters without a whole lot of.
To be behind that.
Just wanted to see if theres been any change in the way you're.
Are you restricting the flow rates at all or anything else its impact on the the production rate yes.
Yeah, Mike, we actually have been and that's one of the reasons why.
2020 has been.
More resilient deeper into the calendar year than.
Than many might have expected.
And the good news is from up reservoir pressure management perspective and from a.
GR work or oil mix to gas.
Relationship that's favorable right the longer you can you can hold.
Reservoir pressure off by restricting the pressure decline the longer and more thoroughly yes, we boil early in the curve and.
Inevitably the reservoir pressure will drop and when it when and as it does drop you get increasing.
Gas production, because it's a it's a.
Solution gas drive environments are the lower the pressure in the reservoir.
The more.
Oil.
Becomes gas through through that.
That production horizon.
In any case, we have been producing the wells to our enhanced recovery flow back techniques and more restrictive in 2020 that even in 2019 or 2018 and the good news is the more we learn about the response the reservoir response end the call.
Composition response, the better armed we are through our various.
Dynamo optimizing tools to respond to all different price environments, and all different kind of reservoir management.
Circumstances, we might find ourselves in.
Okay, Great and I guess, a follow on to that so.
If we look at state data and try and compare early rates from your 2020 completions versus 2019 really via a fair comparison, so I guess can.
Can you say, how you see the quality of this year's wells versus last year.
About the same.
I think we've got.
Mix of.
West legacy and central legacy and a little bit of east legacy.
In 2020 as well as as 2019, so I think the reservoir quality is generally speaking about the same.
Stimulation design is definitely a function of price.
It's price dependent and so the stimulation designs are all meant to me.
Maximize the economic return and so those vary a little bit but in general you're going to see a very sturdy stimulation design in terms of intensity.
And.
But youll see us in lower price environments, where we want to stretch the base and we want to stretch.
The production.
Be just a little bit more conservative on on enhanced recovery flow back and so when you compare.
Take rates in 2019 to peak rates in 2020, I think what you'll see is the 2020 peak rates are a little bit lower but if you watch you integrate under the curve of those two different populations of wells.
And you isolate 19 versus 20, I think what you'll see is the more we restrict the wells.
The more we sweep well to the front of the curve and.
The economics are bias towards favoring the economic environment, where and in this case.
Low price.
Stretch the base sweep as much oil as possible forward and maintain a flat production profile.
That's great. Thanks, So let us get back into queue. Thanks, Mike.
Thank you and then next question comes from Noel Parks with Coker and Palmer. Your line is open.
Good morning.
Good morning, all.
You know.
Of course as the years.
Come along here Weve been talking so much about service cost environment in cost having come down.
Yet again this year and.
From a I don't know if I heard anybody in the in the DJ talk about it but I have heard operators and other basins talk about being pleasantly surprised at how smoothly things run when they they do bring.
A frac team back together and I was just wondering if anecdotally you were you were hearing anything anything similar in the area.
Yes, we certainly have been one of one of the concerns naturally and it's and that's what I think you're you're speaking to is when there is such a dramatic disruption in.
Utilization of Frac crews in this case.
A lot of experience disappears or gets diluted.
And then when the industry turns around and utilization rates start increasing there is some bumpy start ups and.
A lot of friction in the process. So far we haven't we certainly havent experienced it and we've we've used a variety of different frac.
Frac service providers. This year, so even though we've only put three pads to production. This year, we have distributed to work around and we've been pleasantly surprised by the efficiency of the crews that move in rig ups rig down move outs and just the efficiency of the.
Zipper fracking operation and the multi wells on location that has been remarkably consistent with prior years.
We're always either accelerating or decelerating in this industry and both are difficult.
But in my experience, it's been harder to accelerate so we'll be we'll be on the lookout for that and we'll spend extra time planning.
With.
With our service providers.
Hi, there I'm I'm actually surprised to to.
Is that what you're saying is even or what you've experienced even than that positive and.
I guess I'm wondering if you.
If you get in a situation of a of a.
You are leaning more towards one vendor or another.
Is the attitude pretty.
Pretty much like these are sort of bargain bargain prices because we're in an unusual situation like unusual macro and employment situation or.
Or I mean could you.
Do people seem receptive to it to maybe locking in.
The rates, where they are I guess first of all for an extended period of time and the cost of that.
I don't know if they typically would more or less guarantee you. The same crews you have in the past.
Generally speaking.
The service providers are a little reluctant to guaranteed to put to put something.
That would be binding on them, but.
At the same time, they'll they'll work carefully with us through our planning process to ensure that the full.
The full complement of crews and it's not just it's not just the fracture stimulation service providers. It's.
The wireline lubricate or is the wireline services themselves.
The flung plugs and guns and all the various services pumped down and all the rest coiled tubing I mean, it's a whole suite of services, but we generally start planning those well in advance and we'll be working with the service providers for.
A month in advance.
And generally speaking they all have their crews identified because we'll have the windows identified in time.
And they will be able to keep them together.
On the on the expectation that the work is coming now we are we are planning on and have already been in several rounds of communication with our stimulation service providers. Both frac horsepower on all the all the rest of the ancillary services for 2021.
And we're looking at the full the full inventory so notionally, we'd be talking to our Frac service providers and others on a 30 dock program. So so they're looking at putting together and then holding together consistent.
Cruise and services throughout.
A 30 Dot program for us.
Great and just one last one.
You know we've seen some of the energy industry consolidation.
Some of the deals actually close and to some degree some of those are.
Involve participants in the in the DJ just wondering if you've seen any any fall out yet in terms of things happening in the field with some of these and under your ownership.
We haven't.
Again, we used to two different Frac service providers.
And we put that cnineteen pad on in Q2.
And.
Since that time, we've been pretty much constant communication with the with the service providers for 2020 one's program.
Haven't seen and Dean hasn't Hasnt mentioned any anything.
Any fall out or sort of negative feedback related to.
Kind of new aggregated companies and.
Negative results related to their employment accrue as you.
Youre down to something in the range of three or four years.
Rigs running and DJ now and it's probably going to it's probably going to stay pretty tight over the course of the next couple of quarters.
But I do expect Frac services to to step up a little bit in utilization next year, but we've got we've got ample crews and horsepower in DJ to pick up because I don't think anybody is running kind of full bore continuous completions program. So there are these discontinuous.
The frac crews themselves will stay fully employed but they'll work yeah, they'll work a little bit with Austin, a little bit with some of the others and we'll just have to work together to coordinate schedules and ensure that the frac crews remain.
Kind of level loaded over the year and I think thats been one of the benefits.
Is that we've been able to manage as an industry level loading of the of the crew complement across all the services and DJ.
Great. Thanks, a lot yes, thank you know.
Thank you and our next question comes from the line of Phillips Johnston with capital One your line is open.
Hey, guys, Thanks, and happy Friday, you mentioned stronger than expected gas production.
In the third quarter, which led to an increase in your full year guidance.
Just just wondering what you think is contributing to that.
Yes, it's good question Philips good morning.
It's really a combination of things.
Mostly.
That shape of Geo or increasing over time as you drawdown reservoir pressure and it's been a little bit delayed.
This year relative to what you would have expected a feud watched.
The.
The drawdown in and maturation process of our previous packages of wells, primarily because we are being just a little bit more conservative in 2020 in terms of how we flow the wells back and so so that the increase in Q3 gas.
Probably would've happened a little bit earlier in the curve in prior years.
But it's related to this extended.
Yes.
Enhanced recovery flow back being a little bit more extended and a little bit more conservative and restricted this year relative to prior years and if you are segregating.
The 2020.
Wells from from prior batch of Wells 19, and 18, you'll notice that in the in the slope and trajectory of the of the well performance is a later peak.
A slower build up and that also flows through to win the Geo our starts increasing its later.
In the life of the pads.
Okay makes sense, thanks for that looks.
It looks like you guys.
We will start up in French Lake I guess in late 21, I should stand up of 50 50 rigs. There would you would you look to continue activity under the legacy acreage or wood wood with activity essentially just be shifted over to essentially yes.
Yeah, our plan at least for 2021 Philips is too.
You know continue to.
I expect that late 21 startup of drilling in French Lake with our half of the of the one gross operated rig down there.
And then in our our legacy position our operated position its going to be exclusively docks for next year now if things.
Materially out if the commodity price environment materially outperformance.
What the strip is telling us today.
We could potentially in 2022 step into an operated program.
We likely would in fact, one of the things we.
And you would back into this if you looked at just the production profile that we would.
Want to want to Tinker with an operated program to solve for a production profile overtime that looks pretty flat.
Okay sounds good thank you.
Thank you and our next question comes from the line of Michael Saylor with Stifel. Your line is open.
Yes, Eric you said you anticipate some production decline in the first half of next year, and then growth in the second half and overall flat year over year can you put a greater detail behind that are you thinking kind of mid single digit first half decline or is it something more than that.
You know I.
I think.
That it's probably thats, probably a reasonable gas Mike we we've been pleasantly surprised by the degree to which the production will stretch and will remain stronger than.
Prior forecasts as we as we restrict the production.
But there's there's no getting around the fact that we won't have put any new production on.
Since Q2.
And so Q3 is stretching Q4 is continuing to stretch that that same kind of Q1 and Q2, new turn on.
That just can't go on forever as you know and so what we're doing is really just trying to be I think transparent.
With with the outside world in saying.
Is likely to be lower in Q4 than Q3, but not by a lot and we've provided some guidance around that number in Q1 and Q2 I don't I don't expect it to be.
As a whole I just expect it to be kind of sequentially lower in Q1, and Q4 and then depending on how how quickly we can get wells stimulated in turn turn to sales.
Starting in January of 21, Q2 may be flatter it may actually be increasing but we just want it to be kind of transparent with everyone about the bias for capital leaning toward the first half and and the first couple of quarters potentially being lower than than our Q4 of of 20.
20, I don't think its I.
I don't think it's double digits I think your your suggestion of a single digits is probably about right and we could be pleasantly surprised based on the strength we've seen in in the way these pads.
Pads and base respond to our.
Our stretching efforts.
Thank you I'm not showing any further questions at this time I'd now turn call back to speakers for further remarks.
Thank you we just want to say thank you for your interest in Bonanza Creek, and we'll look forward to the time when we can see one another again on the road.
Ladies and gentlemen.
Pardon me. This concludes today's conference call. Thank you for your participation you may now disconnect everyone have a good day.
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