Ladies and gentlemen, thank you for standing by, and welcome to the Q3 2020 Bonanza Creek Energy Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session.

[Operator Instructions] I would now handover the conference over to your speaker today, Scott Landreth. Please go ahead..

Thanks, Sidney. Good morning everyone and welcome to Bonanza Creek’s third-quarter 2020 Earnings Conference calls it to 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 would like to turn the call over to Eric Greager President and CEO, Eric..

Thanks, Scott. Good morning everyone and thank you for joining us today for our third-quarter earnings call. We are pleased with the quarter, we reported yesterday, and appreciate your time this morning discussing the results.

As with previous quarters I will briefly cover a few highlights from the quarter, provide some color for the fourth quarter and the 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 the 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 have 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 have 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 2019 as shown o 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 inventory.

Despite the resiliency we have seen in recent quarters, we do expect volumes to be lower in the first half of 2021 then 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 for the full-year 2019.

With that I will turn the call back to the Operator..

Thank you, ladies and gentlemen. [Operator Instructions] Sir, I want to ask a question. And our first question comes from Jordan Levy with QS Securities. Your line is open..

Good morning all. You have done a really great job of driving down operating expenses in them.

It looks like just in general capital cost will come down I just wanted to see how you guys are looking at that for 2021 I mean, at a point you know can’t drive, the operating expenses down to zero, but how do you see those two items trending moving into next year..

Thanks Jordan, and good morning, I think that as you point out, there is a lower bound.

I don’t think we are there yet, I think Dean and his team will continue to find opportunities but as you have 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 costs across the board, whether we are 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 will continue to find opportunities and perhaps the volumes in 2021 won’t be quite a strong as they are in 2020 and so I think that is 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 Scialla with Stifel. Your line is open..

Yes, good morning guys get your thoughts on regulatory issues, and I realize there is no real impact from the 2000 foot setback for market rate structures, but wanted to see what you’re thinking in terms of the setbacks that the COGCC is proposing from repairing areas..

Yes, thanks good morning Mike. It is a good question and you know, I haven’t seen anything formal coming out of the COGCC in terms of how they are leaning on it, but my hunch is that it is going to be weighted toward permanent bodies of water, so permanent reservoir, permanent lakes, permanently running rivers and streams.

And I think the bias there is around protecting fish species and wild life, Raptors and the like, who often congregate around permanent bodies of water. So my hunch is it is probably not going to include and again 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 is going to be oriented around permanent bodies of water, because it is meant to protect fish species and Raptors. so there will probably be some offset distances, that will impact citing requirements around Raptor nest, known Raptor nests.

There might in fact be some consideration around serving for Raptor nest and as we have seen this in other places around the country that I have experience in Texas, New Mexico and elsewhere. So the short answer is, we don’t know that is a hunch, it is an expectation that is 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, 2000 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 1000 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..

I appreciate that Eric. And I wanted to ask you about if you have been floating your wells back any differently this year versus last. You have been able to hold your production or 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 has been any change in the way you are restricting the flow rates at all or anything else that is impacting the production rate..

Yes, Mike, we actually have been and that is 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 is favorable, right.

The longer you can you can hold reservoir pressure up by restricting the pressure decline the longer and more thoroughly to sweep oil early in the curve and inevitably the reservoir pressure will drop and as it does drop you get increasing gas production, because it is a solution gas drive environments 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 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 and the composition response, the better armed we are through our various Dynamo optimizing tools to respond to all different price environments in 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 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..

About the same. I think we have 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, its 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 are going to see a very sturdy stimulation design in terms of intensity and you will 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 flow back.

And so when you compare peak rates in 2019 to peak rates in 2020, I think what you will 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 2019 versus 2020 I think what you will see is the more we restrict the wells, the more we sweep oil to the front of the curve and the economics.

Our bias toward favoring the economic environment we are in, in this case low price stretch the base sweep as much oil as possible forward and maintain a flat production profile..

It is great, Eric thanks. I will get back in the queue..

Thanks, Mike..

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

Good morning..

Good morning Noel..

You know of course as the years come along here, we have been talking so much about the service cost environment and cost haven’t come down yet again this year.

And from anybody 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 the concerns naturally and it is what I think you are speaking to is when there is such a dramatic disruption in the utilization of frac crews. In this case, a lot of experienced disappears or gets diluted.

And then when the industry turned around and utilization rates start increasing, there are some bumpy start-ups and a lot of friction in the process. So far we certainly haven’t experienced it and we have used a variety of different frac service providers this year.

So even though we have only put three pads to production this year, we have distributed to work around and we have 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 farcing operation and the multi-wells on location that has been remarkably consistent with prior years.

We are always either accelerating or decelerating in this industry and both are difficult, but in my experience it has been harder to accelerate. So will be, will be on the lookout for that and we will spend extra time planning with our service providers..

I’m actually surprised to - what you are hearing is even or what you experienced even then that positive and I guess I’m wondering if you get in the situation of you are leaning more towards one vendor or another, is the attitude pretty much like these are sort of bargain prices because we are in an unusual situation like unusual macro and employment situation or I mean could you -do people seem 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 have had in the past..

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 will work carefully with us through our planning process to ensure that the full, the full complement of crews.

And it is not just a fracture stimulation service providers, it is the wireline lubricators, the wireline services themselves the plugs and guns and all the various services pump-down and all the rest, coil tubing, I mean it is a whole suite of services.

But we generally start planning those well in advance and we will be working with the service providers for months in advance and generally speaking, they all have their crews identified because we will have the Windows identified in time, and they will 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 are looking at the full inventory so notionally we would be talking to our frac service providers and others on a 30 DUC program.

So, so they are looking at putting together and then holding together consistent crews and services throughout a 30 DUC program for us..

Great and just one last one. We have seen some of the images consolidation some of the deals actually close and some to be, some of those involve participants in the in the DJ. I was wondering if you have seen any fallout yet in terms of things happening in the field with some of these and under new ownership..

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 have been pretty much constant communication with the service providers for 2021 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 in rigs running in DJ now and it is probably going to, it is 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 have 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 that there are these discontinuous - the frac crews themselves, will stay fully employed.

But they work a little bit with us and a little bit with some of the others and we will just have to work together to coordinate schedules and ensure that the frac remain kind of level loaded over the year.

And I think that is been one of the benefit, is that we have been able to manage as an industry level loading of the crew complement across all the services in DJ..

Great. Thanks a lot..

Yes, thank you Noel..

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 wondering what you think is contributing to that..

Yes, it is good question. Phillips. Good morning. It is really a combination of things mostly that shape of GOR increasing overtime as you draw down reservoir pressure and it has been a little bit delayed this year relative to what you would have expected, if you had watched the drawdown and maturation process of our previous packages of 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 is related to this extended 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 prior package of wells 2019 and 2018 you will notice that in the slope and trajectory of the well performance. It is a later peak at a slower build up and that also flows through to when the GOR starts increasing it is later in the life of the pads..

Okay, makes sense. Thanks for that. It looks like you guys will start up in French Lake.

I guess in late 2021 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?.

Yes, our plan at least for 2021 Phillips is to - continue to expect that late 2021 startup of drilling in French Lake without half of the one gross operated rig down there. And then in our legacy position, our operated position, it is going to be exclusively docks for next year.

Now 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 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 Scialla 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 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..

You know I. I think that that is probably a reasonable gas Mike. We have been pleasantly surprised by the degree to which the production will stretch and will remain stronger than prior forecast as we restricted 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 are doing is really just trying to be I think transparent with the outside world in saying it is likely to be lower in Q4 than Q3, but not by a lot.

And we have 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 2021.

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 towards the first half and the first couple of quarters potentially being lower than our Q4 of 2020.

I don’t think it is 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 have seen in the way these pads and base respond to our stretching efforts..

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

Thank you. We just want to say thank you for your interest in Bonanza Creek and we will look forward to the time when we can see one another again on the road..

Ladies and Gentlemen, this concludes today’s conference call. Thank you for your participation, you may now disconnect. Everyone have a good day..