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Edited Transcript of BCEI earnings conference call or presentation 9-May-19 3:00pm GMT

Q1 2019 Bonanza Creek Energy Inc Earnings Call

Denver May 21, 2019 (Thomson StreetEvents) -- Edited Transcript of Bonanza Creek Energy Inc earnings conference call or presentation Thursday, May 9, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Doug Atkinson

Bonanza Creek Energy, Inc. - Senior Manager of IR

* Eric Thomas Greager

Bonanza Creek Energy, Inc. - President, CEO & Director

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Conference Call Participants

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* Irene Oiyin Haas

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* John Phillips Little Johnston

Capital One Securities, Inc., Research Division - Analyst

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Bonanza Creek Energy, Inc. First Quarter 2019 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Mr. Doug Atkinson, Senior Manager of IR. Sir, you may begin.

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Doug Atkinson, Bonanza Creek Energy, Inc. - Senior Manager of IR [2]

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Thanks, Ashley. Good morning, everyone, and welcome to Bonanza Creek's First Quarter 2019 Earnings Conference Call and Webcast. On the call this morning, I'm joined by Eric Greager, President and Chief Executive Officer; Brant DeMuth, Chief Financial Officer; and Dean Tinsley, Senior Vice President of Operations and Engineering. Yesterday evening, we issued our earnings press release, posted new investor presentation and have filed our 10-Q with the SEC, all of which can be accessed on the Investor Relations section of our website.

Some of the slides in the May investor presentation will be referenced this morning during our prepared remarks. Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause the actual results to differ materially. You should read our full disclosures as described 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 a good measure 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 provide time at the end for Q&A.

Now it's my pleasure this morning to introduce Eric Greager, President and CEO. Eric?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [3]

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Thanks, Doug. Good morning, everyone, and thank you for joining us for our first quarter earnings call. We had a great quarter, and we will keep our prepared remarks brief. But first, just let me say, we're pleased that Senate Bill 181 has now moved to rulemaking. We also appreciate the supportive posture of the Weld County leadership given our acreage is located entirely on incorporated Weld County. We anticipate little impact to our ongoing development program, and we continue to receive permits on an ongoing basis.

Moving on to operations, our team did an outstanding job in Q1 with production increasing 17% sequentially. Our operations were minimally impacted by the extreme winter weather this past quarter demonstrating our ability to appropriately plan for and respond to factors beyond our control. Oil represented 65% of our hydrocarbon mix for the quarter and increased from 62% in the fourth quarter of 2018. This was driven primarily by new well production in the quarter as well as our reservoir pressure management program, which is yielding higher oil and gas.

We expect our oil percentage to be in the low-60s for the balance of the year. We recently announced results from our Pronghorn B-28 pad in our Legacy East area, which can be found on Slide 12 of our investor presentation. As you can see on the rate versus time production plot on the left, the pad is currently tracking above our Legacy East XRL type curves. We're excited about these results here and plan to continue development in this area this year to further reinforce the quality of our Legacy East acreage.

Our team continues to drive unit operating expenses lower, and I'm proud to say our LOE of $2.91 per BOE represents one of the more competitive OpEx structures in the basin. Our success here really goes back to the fundamentals of the business, the basic blocking and tackling of driving everyday line items within the lease operating expense is lower. Given the improvements in operating efficiencies, cost control and well performance, we are reducing our LOE guidance to the range of $2.75 to $3.25 per BOE from our previously guided range of $3 to $3.50 per BOE.

Lastly, we continue to layer in hedges to protect our cash flows and reduce price volatility. Details of our current hedge position are located in the appendix on Slide 19 of our May investor presentation.

With that, I'll turn the call over to the operator for Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question comes from the line of Irene Haas with Imperial Capital.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [2]

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I have a question on your Pronghorn pad. Can you explain to us maybe a little more detail what is the magic ingredient that mixes well? This pad does so well? And then when would you expect a decline eventually? And then all this good work, what's the implication for your EUR for the Legacy East? I believe right now, you have 830,000 barrel oil equivalent.

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [3]

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Thanks, Irene. I'll just say we're very confident of the type curves we have in the investor deck, and I'll just say we're enforcing that with this well performance. The magic ingredient really is, I think, the rapid innovation cycle that we've managed to create within our technical and operations team. So it's not a single kind of stimulation parameter that you can put your hands on like proppant per foot or stage and cluster architecture or fluid systems design. It's more around our ability to gather real-time data -- instantaneous data during both drilling and stimulation. But in terms of well performance, it's primarily on the stimulation side, and pump that data in real-time back through our technical and operational physics engines and analysis engines to generate further improvements. Literally, as we're staging out the well and pumping the stages, we're gaining more and more information that yields better results as we continue to pump more stages.

So rather than perhaps the older style of pumping a single kind of geometric stimulation with a single type of fluid systems design and horsepower delivery and then waiting 6 or 9 months for results and then repeating that cycle on something that feels like a 3-quarter cycle length period, we've shortened that to a stage, which can be fractions of a day even. So we can make these rapid innovations literally, while we're pumping the fracture stimulation. And I think that is part of what has driven the performance improvements that you see in well performance. It's also in the enhanced recovery flowback dashboard that we operate that we literally make daily and, in some cases, more frequent changes to reservoir pressure management. Artificial lift designs are the same way. This is a very short cycle innovation process, and we think that's one of the keys to moving quickly is gathering intelligence early and then putting it into your analytical decision-making very quickly and then acting nimbly with that information to put changes on the ground.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [4]

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Okay. Great. If I may have one follow-up question. With all these wells and this set wells as such in each quarter, you continue to improve it. Can you kind of quantify the improvement in terms of your dollar per barrel breakeven, say, 2017 and versus now? What is it -- how it's trending?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [5]

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Well, yes, our breakeven oil prices continue to improve because we're wrenching costs out of the structure. And I think maybe the best way to answer that question is to point to the 4-pack slide in our investor deck. It's a series of -- I'm looking for the slide right now. Slide 5? Yes, it's Slide 5, and the way we like to talk about this, Irene, is we essentially point to the lower right panel in that 4-pack. And you'll notice over the last couple of quarters -- and this is no surprise to anyone on the call -- that we've seen realized prices -- the industry has seen realized prices fall sequentially for 2 quarters now. Yet despite that drop in pricing, we've actually been able to maintain EBITDAX growth over those sequential quarters and, in fact, drive our EBITDAX margin up even farther.

And we point to the panel on the lower left, Wattenberg LOE, which has cut over 3 quarters -- or if you include 2Q of '18 cut our LOE cost more than half. And we're also driving that same cost control discipline and kind of blocking and tackling operational discipline into all elements of our cost structure. So I think well performance helps. I think artificial lift and reservoir pressure management helps a great deal to reinforce well performance. But the cost control drives right to the bottom line and ensures you can continue to grow EBITDAX and EBITDAX margin despite lower prices. And that's one of the things I'm most proud of with regard to the team's performance. Does that answer your question?

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [6]

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Yes. That was good. We can follow-up later.

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Operator [7]

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And our next question comes from the line of Welles Fitzpatrick with SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [8]

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Congrats on a great quarter. I think you might be the only green thing on the screen today. So I-25 pad, obviously, the 90-day rates look very strong, but obviously they are 90-day rates. Can you talk to applying both the spacing of 16 well per unit and the enhanced completions across the acreage? And when you might start moving a little bit? Obviously you've done higher completions in the East, but when you might move the kind of whole package a bit to the East?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [9]

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Yes. Thanks, Welles. You know, we've told this story, and each time I look at Slide 11, I tell the story in the same way, which is, you come in first and take your best shot at it. In this case, it was the 2018 Legacy wells. That's the gray line now aggregated into 1 dash line. And then we work backwards moving the well performance up into the left until we're reasonably satisfied with that. And then we start increasing the density of the wells on it on a wells per section basis. We're sort of 3 quarters in or maybe 4 quarters in on the story here that's told on Slide 11.

As we continue to move across the acreage Central and East, we're not far -- as far along in that story. And so the B-28 is probably the gray line. And so we need to get some time here, but we're going to continue to study some of the leading indicators, things like ISIPs, the way the wells treat, the early flowing bottom hole pressures and do some additional engineering. So that the next time we come back into the area, we can be developing a slide like this. But the way I would answer your question in short is we're actually taking the performance of B-28 already and running it through our economic optimization process and planning the next couple of pads. So what you can expect to see is a slide like Slide 11 in the coming quarters telling the story as it progresses in and around the Pronghorn B-28.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [10]

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Okay. That's great. So it sounds like the B-28 is kind of fitted to that 580 MBoe curve, if I heard you right. Can you remind me the 16 wells that were on the I-21 pad, how many of those were Codells? How many of those will we probably just want to take out of the models, if it does move East?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [11]

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What -- just wanted to point back, Welles. I thought you reiterated that the Pronghorn B-28 was connected to the gray line. I didn't mean to imply that. I was just saying it sort of it's in -- it takes that position in the progress of the story. What I would clarify is that the Legacy East XRL type curve is an 830 MBoe EUR. So I just wanted to follow up and clarify that. It is actually a much bigger type curve on the -- that the B-28 is fitted in. So that's the 830 MBoe. Now with that, can you repeat your question because I was looking for that clarification?

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [12]

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No, no, fair enough. Yes, how many on the I-21s were -- can you give us a breakdown of the different numbers on the Codell?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [13]

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Yes. So the I-21 at 16 well per section pad that we drilled there in the little dashed box and in red dashed lines, those are all Niobrara B and Cs. So what we face here with our Codell is, as you know, we've talked about the Codell being geologically better developed to the West and kind of pinching out as you move East across to our acreage. And when we have an opportunity to drill a pad, if we insert a Codell, it's our current position. That if we insert a Codell and bring that into the pad layout, we don't want to stack a Niobrara on top of it because that has generally yielded poor performance.

So, in essence, you can look at an opportunity cost by putting a Codell in. We almost have to remove a Niobrara. And because the well performance has been consistently strong as we tie these subsurface Niobrara wells together, with the stimulation spacing and stacking arrangement, we've opted to continue with Niobrara B and Cs. So this I-21 pad doesn't have any Codells in it.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [14]

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Okay. That makes subtle sense and presumably would make it even easier to apply as you move East. Obviously, Slide 5, very impressive. You guys probably had the biggest LOE per unit drop in the space. Can you talk to -- as you ring out all these efficiencies and presumably there is some diminishing return to doing that, can you talk to how you might turn or how you're looking at the A&D market now that you guys are pretty well positioned as one of the more, if not the most, efficient operator in this neck of the woods?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [15]

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Yes. The way we think about M&A and A&D is the way -- I think we talked about it on conference calls and certainly in investor presentations. We really think about it in this -- things we like about Wattenberg and DJ and then the things that we'd hope to avoid. And in that, we kind of call it the process of elimination. We certainly don't want to make our story more difficult to follow by bringing on a lot of additional urban exposure. That exposure to the West sometimes also happens to have life-of-lease acreage dedications that can constrain growth. And so for those reasons, we think that really high-quality reservoir to the West also has a number of factors that we wouldn't want to necessarily take on.

So if you take some of the operating A&D opportunities a little bit further to the West off the table, and we also think about high-quality resource, and you don't want to dilute the quality of the resource, but I think we bring a unique operational and technical process to the reservoir. So we can sort of open up geographically a little bit in and around our position, but you really want to focus on things that I think our company does well and our team does well, and that is blocking and tackling. It's operational efficiency. You'd like to drill longer laterals. You'd like to put bigger stimulations. You'd like to tie in to existing infrastructure like Rocky Mountain Infrastructure and then be able to control gathering system pressures at the wellhead to improve well performance.

And we see this as a kind of a virtuous cycle, where you continue to drive the things you do well across the larger and larger package of acreage. So the way I would think about it is we don't want to be subscale in 2 basins. So to imagine that we would go out far afield and do something significant out of DJ would be to drive us toward as being subscale in 2 basins. The way we think about it is to drive our efficiency more close to home, while we gain that scale and all the benefits and economies that scale provides. And of course, these things move over a number of chapters. Eventually when we gain scale, then there will be opportunities, I think, to pivot into other places to diversify risk. But the way we think about A&D and M&A is to concentrate our efforts in and around DJ where we think we can leverage the things we already do well and the acreage we understand really well.

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Operator [16]

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And our next question comes from the line of Phillips Johnston with Capital One.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [17]

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First question is on CapEx. You spent $45 million in first quarter which I think is only about 18% of the budget. And yet your net well pops were about 15 which is close to half of the planned pops for the year. So just wanted to reconcile that calculus. Are we on track to significantly underspend the budget? Or is there something that I'm missing from either a timing or an approval perspective?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [18]

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Yes. Thanks, Phillips. It's a good question. And the way we think about this is you actually have to go back to Q4. And remember, we spent over $100 million of CapEx in Q4. And we talked about on our last earnings call how that sets up Q1. And now with a 17% sequential production growth Q1 over Q4, that's pretty well in line with what we expected. Our drilling and completions and flowback schedule is right to our expectations. In fact, all the spuds, rig releases, completions, turn-ons and connections are within a day or 2 of our schedule. D&C AFEs are right to our expectations.

And so really the difference between, say, $45 million and what you might have expected if you take our $242 million midpoint of total CapEx and you divided it uniformly over 4 quarters, you would have expected something higher than that. The reason it's not is simply because when you look at our completions schedule, we're running a drilling rig continuously and level loaded throughout the year. But we had a frac crew running right up to the end of the year, then we released our frac crew. And this was all by design. And then we didn't have a frac crew running until about midway through Q1 when we picked them back up. We'll continue at this 1 frac crew, 1 rig continuous pace with our CapEx growing through Q2, peaking in Q3 and then fading back, again, as we move through Q4. So you've got kind of the centered Q3 loaded CapEx, but it's really just a function of the way we've structured the budget, and everything is in line with our schedule and in line with our expectations.

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John Phillips Little Johnston, Capital One Securities, Inc., Research Division - Analyst [19]

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Okay. I appreciate the detail on the cadence there for the rest of the year. Second question just wondering if there is any update on the performance at Whitetail on the North? And do you plan on drilling any more wells on the northern acreage anytime soon?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [20]

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Yes, thank you. We put a really big stimulation on Whitetail, and the flowback and load recovery is performing to our expectations. The well is actually performing to our expectations, meeting type curve expectations. But because we put such a big stimulation on it, it's taking quite a while to get meaningful trajectory on flowing bottom hole pressures. And as a consequence, we weren't quite ready to put it out. It will be coming in the next quarter, and we might even update sooner than that if it breaks hard and we've got a lot of data. But it's generally tracking in line with the Legacy East performance, the Pronghorn B-28 pad. So we're very satisfied with it. But I think the idea here around load recovery is you can't get a good read on flowing bottom hole pressure, which is the leading indicator of reservoir performance until you've gotten a substantial amount of the load off. And these were big stimulation designs, so there was materially more fluid to flow back. So more to come on it, but we are encouraged by the performance.

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Operator [21]

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(Operator Instructions) And our next question comes from the line of Welles Fitzpatrick with SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [22]

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Two quick ones. On the Pronghorn B-28, obviously on day 150 it kind of -- it starts moving back up. I would imagine that's well after you watered. Can you give any commentary on what's pushing that? Is that a midstream issue?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [23]

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There are a number of factors that we're continuously monitoring and optimizing. There is artificial lift and flowback. There's also surface facilities optimization. But I wouldn't necessarily presume that we've gotten all the fluid back at 150 days. This stimulation -- you can see that in the first 90 days, it's pretty clear that it's -- the reservoir is working hard to unload. And then you see at -- at about day 75, you see the volatility start to go up in some of these short-dated measurements. It starts to get just a little bit noisier. And I think what that's showing us is that the reservoir is -- it's slugging. You've got new strap blocks turning on. You've got new stages coming on.

Keep in mind that a long lateral like this -- these don't all log on simultaneously. It generally bring the heel on first as you dewater it, and you move further and further down the lateral as these new stages start to log in, as the reservoir starts to reach equilibrium with the wellbore pressure. And so what we're seeing here is the volatility between say day 75 and day 150 as you're continuing to open up the SRB and log in those strap blocks and frac stages. And then you see it start taking off on that more upward trajectory at about 155. We actually think about 155 and on, it's still substantial. We're still getting substantial load recovery, but we do think we've logged in all of the stages at this point. And so you're really starting to dewater the deepest further back -- the frac complexity of the SRB that's further away deep into the toe and far away from the wellbore.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [24]

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Okay. That's very helpful. And then lastly just have to ask. Any updates from your partner in French Lake? Or are the plans as had been described previously?

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [25]

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Yes. They are as have been described previously. You can imagine that those guys are undergoing a bit of a whipsaw. And our folks up here, our contacts up here in Denver, they're working hard to continue on the program. And each time we talk to them and we talk to them often both at an engineering and development level and also kind of at a management administrative level, and they're telling us the same thing. Look, we haven't been giving -- this is what they tell us: We haven't been given any other instructions except to stay the course and stay after it. And so that's what they are telling us. And this feels pretty good to us, so.

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Operator [26]

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Ladies and gentlemen, this concludes today's Q&A session. I would now like to turn the call back over to Eric Greager, CEO, for any closing remarks.

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Eric Thomas Greager, Bonanza Creek Energy, Inc. - President, CEO & Director [27]

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Thanks, Ashley. I just want to point out we'll be attending the Tudor, Pickering Conference in Houston next week and then subsequent to that the J.P. Morgan Conference in New York City in June. And hopefully, I'll get a chance to meet some of you there. Thanks, again, for joining our call and your continued interest in Bonanza Creek.

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Operator [28]

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Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a wonderful day.