Bonanza Creek Energy Inc (BCEI) Q3 2020 Earnings Call Transcript

Logo of jester cap with thought bubble.

Image source: The Motley Fool.

Bonanza Creek Energy Inc (NYSE:BCEI)
Q3 2020 Earnings Call
Nov 6, 2020, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Ladies and gentlemen, thank you for standing by, and welcome to the Q3 2020 Bonanza Creek Energy Earnings Conference Call. [Operator Instructions] After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions]

I would now like to hand the conference over to your speaker today, Scott Landreth. Please go ahead.

Scott LandrethSenior Director, Finance and Investor Relations and Treasurer

Thanks, Sidney. Good morning, everyone, and welcome to Bonanza Creek’s third quarter 2020 earnings conference call and webcast. On the call this morning, I’m joined by Eric Greager, President and CEO; Brant DeMuth, Executive Vice President and 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 with the SEC, all of which can be found on the Investor Relations section of our website. Some of the slides in the current investor presentation may be referenced during our remarks this morning.

Please be aware that our remarks will include forward-looking statements that 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 SEC 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 move to Q&A.

Now I’d like to turn the call over to Eric Greager, President and CEO. Eric?

Eric GreagerPresident and Chief Executive Officer

Thanks, Scott. Good morning, everyone, and thank you for joining us today for our third quarter earnings call. We’re pleased with the quarter we reported yesterday, and 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 start of 2021, and then open up the line for Q&A.

Our production volumes have remained resilient, despite limited capital investment since the first quarter. While oil volumes were flat from 2Q to 3Q, our Boe 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 MBoe per day to 25 MBoe per day to a range of 25 MBoe per day to 25.5 MBoe 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. LOE performance has been strong throughout the year, with the third quarter metric of $2.23 per Boe, representing the lowest unit LOE that the Company has ever recorded. Our year-to-date LOE of $2.43 per Boe is ahead of our expectations for the year, and we have revised our annual LOE guidance accordingly from a range of $2.50 per Boe to $2.90 per Boe to a range of $2.40 per Boe to $2.60 per Boe.

For RMI 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 per Boe to $1.85 per Boe to $1.50 per Boe to $1.80 per Boe based on our expectations for the fourth quarter.

Recurring cash G&A was $2.56 per Boe for the quarter and brings our year-to-date recurring cash G&A to a total of $20.1 million. We’ve tightened our annual estimate for recurring cash G&A 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 in 2Q of ’19, as shown on Slide 4 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 toward 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 Q&A.

Questions and Answers:

Operator

Thank you. [Operator Instructions] And our first question comes from Jordan Levy with Truist Securities. Your line is open.

Jordan LevyTruist Securities — Analyst

Good morning all. You’ve done a really great job in driving down operating expenses and then it looks like just in general capital cost will come down as well. Just wanted to see how you guys are looking at that for 2021? I mean, at a point, the probe can drive the operating expenses down to zero, but how do you see those two items trending moving into next year?

Eric GreagerPresident and Chief Executive Officer

Thanks, Jordan. Good morning. I think that as you point out, there is a lower bound. I don’t think we’re there yet. I think Dean and his team will continue to find opportunities. But as you’ve probably seen just in the column chart in our deck and over time tracking the Company, the rate of change, the rate of descent in unit cost is decreasing, 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 G&A, unit LOE or unit opex, including RMI, are probably going to be pretty consistent with this year. I think we’ll continue to find opportunities, and perhaps the volumes in 2021 will be quite as strong as they are in ’20. And so, I think that’s going to point to unit operating expenses kind of in line with 2020.

Jordan LevyTruist Securities — Analyst

Thanks so much guys.

Eric GreagerPresident and Chief Executive Officer

You bet.

Operator

Thank you. And our next question comes from Michael Scialla with Stifel. Your line is open.

Michael SciallaStifel — Analyst

Yeah. Good morning, guys. Your thoughts on regulatory issues, and I realize there is no real impact from the 2,000 foot setback from occupied structures, but wanted to see what you’re thinking in terms of the setbacks that the COGCC is proposing from repairing areas?

Eric GreagerPresident and Chief Executive Officer

Yeah, thanks. Good morning, Mike. It’s a good question. And I haven’t seen anything formal coming out of the COGCC in terms of how they’re — how they’re leaning on it, but my hunch is that it’s going to be weighted toward permanent bodies of water. So, permanent reservoirs, permanent lakes, permanently running rivers and streams. And I think the bias there is around protecting fish species and wildlife, raptors and the like who often congregate around permanent bodies of water. So, my hunch is it’s probably not going to include.

And again, this is — this is not informed by any intelligence I have beyond what you and everyone else has, only that I believe this to be the direction that it would be heading, that it’s going to be oriented around permanent bodies of water because it’s meant to protect fish species and raptors. So, they’ll probably be some offset distances that will impact citing requirements around raptor nests, known raptor nests. There might in fact be some consideration around serving for raptor nests. We’ve seen this in other — other places around the country that — that I have experience in Texas, New Mexico and elsewhere.

So the short answer is, we don’t know that’s a hunch, that’s an expectation, and we anticipate that it won’t be very impactful. I don’t anticipate any setback distance or buffer zones to be nearly as significant in terms of just the length, the 2,000 foot from occupied structures. I don’t think anything related to bodies of water are going to be nearly that large. I would anticipate that perhaps in the under 1,000 feet, perhaps 300 feet to 500 feet might be reasonable. But again, I don’t know anything more than you know. This is my hunch based on what I understand to be the driving factors behind those protections.

Michael SciallaStifel — Analyst

Well, I appreciate that, Eric. And wanted to ask you about, if you’ve been flowing [Phonetic] your wells back any differently this year versus last. You’ve been able to hold your production, actually even grow it a little bit last couple of quarters without a whole lot of activity behind that. I just want to see if there’s been any change in the way you’re — are you restricting the flow rates at all, or anything else that’s impacting the production rate?

Eric GreagerPresident and Chief Executive Officer

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 many might have expected. And the good news is, from a reservoir pressure management perspective and from a GOR or oil mix to gas relationship, that’s favorable, right. The longer you can hold reservoir pressure up by restricting the pressure decline, the longer and more thoroughly you sweep oil early in the curve and inevitably the reservoir pressure will drop. And when — and as it does drop, you get increasing gas production, because it’s a solution gas drive environment, so the lower the pressure in the reservoir, the more oil becomes gas through that production horizon.

In any case, we have been producing the wells through our enhanced recovery flowback techniques and more restrictive in 2020 than even in 2019 or 2018. And the good news is the more we learn about the response, the reservoir response and the 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.

Michael SciallaStifel — Analyst

Okay, great. And I guess, I’ll follow-on to that. So, if we look at state data and try and compare early rates from your 2020 completions versus 2019, that might not really be a fair comparison. So, I guess can you say how you see the quality of this year as well as versus last year?

Eric GreagerPresident and Chief Executive Officer

About the same. I think we’ve got a mix of West Legacy and Central Legacy and a little bit of East Legacy in 2020, as well 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 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 you’ll 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 enhanced recovery flowback.

And so, when you compare peak 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 — if 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 oil to the front of the curve and the economics are biased toward favoring the economic environment we’re in. In this case, low price, stretch the base, sweep as much oil as possible forward, and maintain a flat production profile.

Michael SciallaStifel — Analyst

That’s great, Eric. Thanks. I’ll get back in the queue.

Eric GreagerPresident and Chief Executive Officer

Thanks, Mike.

Operator

Thank you. And then next question comes from Noel Parks with Coker & Palmer. Your line is open.

Noel ParksCoker & Palmer — Analyst

Good morning.

Eric GreagerPresident and Chief Executive Officer

Good morning, Noel.

Noel ParksCoker & Palmer — Analyst

Of course, as the years come along here, we’ve been talking so much about service cost environment and costs haven’t come down yet again this year. And from — I don’t know if I heard anybody in the DJ talk about it, but I have heard operators in other basins talk a lot being pleasantly surprised at how smoothly things run when they do bring frac team back together. And I was just wondering if anecdotally you are hearing anything — anything similar in the area.

Eric GreagerPresident and Chief Executive Officer

Yeah. We certainly have been — one of the concerns naturally and it’s what I think 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 are some bumpy start-ups and a lot of friction in the process. So far, we haven’t — we certainly haven’t experienced it, and we’ve used a variety of different frac service providers this year.

So even though we’ve only put three pads to production this year, we have distributed the 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 on the lookout for that and we’ll spend extra time planning with our service providers.

Noel ParksCoker & Palmer — Analyst

I’m actually surprised to that — what you’re hearing is [Phonetic] even or what you experienced even then that positive. And I guess I’m wondering if you — if you get in the situation of leaning more toward one vendor or another, is the attitude pretty much like these are sort of bargain prices because we’re in an unusual situation like unusual macro unemployment situation, or I mean could you — do people seen receptive to maybe locking in the rates where they are? I guess first of all, for an extended period of time and in the course of that, I don’t know if they typically would more or less guarantee you the same crews you’ve had in the past.

Eric GreagerPresident and Chief Executive Officer

Generally speaking, the service providers are a little reluctant to guarantee to put something that would be binding on them, but at the same time, they’ll work carefully with us through our planning process to ensure that the full complement of crews and it’s not just the fracture stimulation service providers, it’s the wireline lubricators, the wireline services themselves, the plugs and guns, and all the various services, pump-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 months in advance. And generally speaking, they will have their crews identified because we will have the windows identified in time. And they’ll be able to keep them together on the expectation that the work is coming. Now we are planning on and have already been in several rounds of communication with our stimulation service providers both frac horsepower and all the rest of the ancillary services for 2021. And we’re looking at the full inventory. So notionally, we’d be talking to our frac service providers and others on a 30 DUC program. So, they looking at putting together and then holding together consistent crews and services throughout a 30 DUC program for us.

Noel ParksCoker & Palmer — Analyst

Great. And just one last one. We’ve seen some of the — [Indecipherable] consolidation, some of the deals actually closed and some to be — some of those are involve participants in the DJ. I was wondering if you’ve seen any fallout yet in terms of things happening in the field with some of these under new ownership.

Eric GreagerPresident and Chief Executive Officer

We haven’t — again, we used two different frac service providers and we put the T-19 pad on in Q2. And since that time, we’ve been in pretty much constant communication with the service providers for 2021’s program. I haven’t seen and Dean hasn’t mentioned any fallout or sort of negative feedback related to kind of new aggregated companies and negative results related to their employment crews.

You were down to something in the range of three or four rigs running in 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 step up a little bit in utilization next year. But we’ve got — we’ve got ample crews in horsepower and DJ to pick up, because I don’t think anybody is running kind of full bore continuous completions program.

So, they are — there are these discontinuous — the frac crews themselves will stay fully employed, but they’ll work — yeah, they’ll work a little bit with us and 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 that’s been one of the benefits, is that we’ve been able to manage as an industry level loading of the crew complement across all of the services in DJ.

Noel ParksCoker & Palmer — Analyst

Great. Thanks a lot.

Eric GreagerPresident and Chief Executive Officer

Yeah. Thank you, Noel.

Operator

Thank you. And our next question comes from the line of Phillips Johnston with Capital One. Your line is open.

Phillips JohnstonCapital One Securities — Analyst

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 wondering what you think is contributing to that?

Eric GreagerPresident and Chief Executive Officer

Yeah, it’s good question, Phillips. Good morning. It’s really a combination of things, mostly that shape of GOR increasing over time as you draw down reservoir pressure. And it’s been a little bit delayed this year relative to what you would have expected, if you’d watched the drawdown and maturation process of our previous packages at well, primarily because we are being just a little bit more conservative in 2020 in terms of how we flow the wells back.

And so, the increase in Q3 gas probably would have happened a little bit earlier in the curve in prior years, but it’s related to this extended enhanced recovery flowback being a little bit more extended and a little bit more conservative and restricted this year relative to prior years. And if you’re segregating the 2020 wells from prior package of wells ’19 and ’18, you’ll notice that in the slope and trajectory of the well performance, it’s a later peak and a slower build up and that also flows through to when the GOR starts increasing. It’s later in the life of the pads.

Phillips JohnstonCapital One Securities — Analyst

Okay, makes sense. Thanks for that. It looks like you guys will start up in French Lake I guess in late ’21. As you stand up a 50-50 rig there, would you look to continue activity under the legacy acreage or with activity essentially just be shifted over to French Lake?

Eric GreagerPresident and Chief Executive Officer

Yeah. Our plan at least for 2021, Phillips, is to continue to expect that late ’21 start-up of drilling in French Lake with our half of the one gross operated rig down there. And then in our legacy position, our operated position, it’s going to be exclusively DUCs for next year. Now, if things — materially, if the commodity price environment materially outperforms 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 tinker with an operated program to solve for a production profile over time that looks pretty flat.

Phillips JohnstonCapital One Securities — Analyst

Okay. It sounds good. Thank you.

Operator

Thank you. And our next question comes from the line of Michael Scialla with Stifel. Your line is open.

Michael SciallaStifel — Analyst

Yeah. Eric, you said you anticipate some production decline in the first half of next year and then growth in the second half, and then overall flat year-over-year. Can you put any greater detail behind that? Do you think kind of mid-single-digit first half decline, or is it something more than that?

Eric GreagerPresident and Chief Executive Officer

I think that it’s probably — that’s probably a reasonable guess, Mike. We — we’ve been pleasantly surprised by the degree to which the production will stretch and will remain stronger than prior forecast, as we restrict the production, but there is 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 same kind of Q1 and Q2 new turn-ons. 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 the outside world in saying it’s 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 expect it to be a whole, I just expect it to be kind of sequentially lower in Q1 and Q4. And then depending on how quickly we can get well stimulated and turn to sales, starting in January of ’21, Q2 may be flatter, it may actually be increasing.

We just wanted to be kind of transparent with everyone about the bias for capital leaning toward the first half and the first couple of quarters, potentially being lower than our Q4 of 2020. I don’t think it’s double digits. I think your suggestion of single digits is probably about right and we could be pleasantly surprised based on the strength that we’ve seen in the way these pads and base respond to our stretching efforts.

Operator

Thank you. And I’m not showing any further questions at this time. I’d now like to turn the call back to speakers for further remarks.

Scott LandrethSenior Director, Finance and Investor Relations and Treasurer

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.

Eric GreagerPresident and Chief Executive Officer

Thank you, everyone.

Operator

[Operator Closing Remarks]

Duration: 27 minutes

Call participants:

Scott LandrethSenior Director, Finance and Investor Relations and Treasurer

Eric GreagerPresident and Chief Executive Officer

Jordan LevyTruist Securities — Analyst

Michael SciallaStifel — Analyst

Noel ParksCoker & Palmer — Analyst

Phillips JohnstonCapital One Securities — Analyst

More BCEI analysis

All earnings call transcripts


AlphaStreet Logo

Leave a Reply

Your email address will not be published. Required fields are marked *