Ladies and gentlemen, thank you for standing by, and welcome to the Q4 2020 Bonanza Creek Energy, Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question- and- answer session. To ask a question during the session, you'll need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Scott Landreth. Please go ahead, sir. Thanks, Josh. Good morning, everyone, welcome to Bonanza Creek's fourth quarter 2020 earnings conference call and webcast. On the call this morning, I am joined by Eric Greager, President and CEO, Brant DeMuth, Executive Vice President and Chief Financial Officer, other members of the senior management team. Yesterday, we issued our earnings press release, posted a new investor presentation, filed our 10-K 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-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. As with previous earnings calls, we will take questions from those in the sell-side analyst community on today's call. I ask that investors and others with questions please reach out to me directly to schedule a call. You can find my contact information on the Investor Relations section of our website or within yesterday's release. Now, I would like to turn the call over to Eric Greager. Eric? Thanks, Scott. Good morning, everyone, and thank you for joining us this morning. Despite the challenges, Bonanza Creek had a very successful 2020. The team delivered safe and consistent operational performance, stretching base production, lowering our cost structure, and improving our occupational safety and health rates. The year concluded with the announcement of a transformative acquisition of HighPoint Resources. The combination of Bonanza Creek and HighPoint is expected to provide significantly more scale in the rural DJ, enabling us to continue expanding our margins, delivering synergy value, and generating significant and resilient free cash flow. I'll have more to say on this transaction before opening the line for Q&A. First, I want to summarize a few of the other highlights from 2020. In early March, when faced with a dramatic decline in commodity prices, we quickly flexed down our pace of development to maintain financial strength. These actions enabled us to generate over $100 million of free cash flow in 2020 and end the year with no debt and $25 million of cash on the balance sheet. Despite a 70% reduction in capital investment, 2020 production exceeded our March expectations. What we forecasted was an average annualized rate approximately equal to 2019. What we delivered was an 8% improvement over 2019 and a substantial beat of our original guidance. In early January of 2021, we started our DUC stimulations and we're expecting to turn new wells to sales in late March. More recently, the Arctic weather impacting much of the nation also created freeze-offs in our operations. In our release yesterday, we reduced our total production guidance to a range of 20-23 MBoe/d for 1Q 2021. Our oil volumes were less impacted, which you'll notice in the improved oil mix guidance. This remains a cost and margin business, and in 2020, the BCEI team drove unit LOE and recurring cash G&A expenses to levels that had not been reached in our company's history. We're excited to work with the HighPoint team to apply the best of both companies on a combined base of assets. Briefly, I would like to address one item on the financial statements relating to the $61 million deferred income tax benefit on our balance sheet as of year-end. Sandi and Brant can provide more color during Q&A if there's interest. In summary, this is due to the company being in a sustained net income position for the foreseeable future, according to tests performed during our year-end audit. As a result of this income, we will now be able to take advantage of our deferred tax assets that were previously offset by a valuation allowance. The removal of the valuation allowance at year-end results in a tax benefit on our income statement. More exciting than taxes, we continue to make steady progress toward closing our acquisition of HighPoint. Last week, we announced key milestones and scheduled a March 12th shareholder meeting to approve the transaction. We refer everyone to our February 10th joint proxy statement and prospectus, all of which are available on our website, as the best and most comprehensive sources of information regarding the HighPoint transaction. With that, I will turn the call to the operator for Q&A. Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, press the pound key. Please stand by while we compile a Q&A roster. Our first question comes from Leo Mariani with KeyBanc. You may proceed with your question. Hey, guys. Just wanted to touch a little bit on how you're thinking about 2021. I know you've got the first quarter guidance out there. Clearly you're waiting on the timing of the HighPoint deal to give us a little bit more of an update. From a high level, we've clearly seen great strength in commodity prices. Start the year, prices arguably a lot better than most people sort of thought here. Obviously, you guys didn't really have any activity in the second half of 2020. You've kind of started to frac wells. I guess what I'm getting at is just trying to get a sense of when you think you might be able to get a rig back out there. Are you still thinking second half 2021? Might a rig come a little bit earlier just based on the robust commodity prices we're looking at here? Might you consider a little bit more activity? Do you still want to be kind of flattish year-over-year pro forma, or could there be a little bit of growth given how well commodities have done? Thanks, Leo. I think that's a great question, and we've certainly given it some thought. I think we are still planning for standing up a rig in the second half. I think it'd be safe to call that mid Q3. It'll take us a little bit of time. The good news is we've got a lot of DUCs. We'll have a steady diet of DUCs to stimulate between now and that time. Obviously, that DUC stimulation program is independent of the drilling operation, so we start to replenish those DUCs when we pick up the rig. The idea is still to operate or at least contemplate operating one level-loaded rig across the combined assets. We talked about flat to slightly declining when we announced the deal. I think given the relatively significant recovery in commodity prices, both on the natural gas side and the crude oil side, it's probably fair to use the term you used, which is flattish, and try to maintain kind of flat, stable production over time as opposed to allowing it to decline. Rather than front-run that too significantly, that's going to be driven by returns, and we'll have a new board in place after closing. Those sensitivities on returns will be discussed with the Board. I'm confident to say flattish is a good way to go, and picking up a rig early in the second half of the year and kind of think mid Q3 makes a lot of sense to us. Okay. That's helpful. Obviously, we're getting kind of closer to the point where you guys are able going to close the HPR deal, which is obviously a big milestone for you guys and roughly doubles the size of the company. Looking forward, I imagine there may be some other opportunities out there in the DJ. Do you think 50,000 Boe/d, roughly speaking, is the right scale, or would you have ambitions to continue to potentially do other deals and become a little bigger company in the next couple of years? Well, our posture is to remain engaged in the conversation on the M&A front, whether that's asset acquisitions or kind of corporate level. That all depends on valuation. Obviously, the HighPoint deal was a value-accretive deal for our shareholders on just about any per-share metric you'd like to look at. I think there's still value, Leo, in gaining scale. You have more and more opportunities to diversify risks, whether those are asset risks, reservoir risks, takeaway risks, or other kinds of risks in the business. Scale, obviously, not only gives us economies, but also gives us the opportunity to mitigate risk across the portfolio. We won't be satisfied necessarily at 50,000 Boe/d because it's 50,000 Boe/d. We certainly appreciate that 50,000 Boe/d is twice 25,000 Boe/d, and that's a great improvement in scale. We'll continue to look for value-accretive opportunities to continue to grow the business. It's got to make sense. There's got to be a fair exchange of value, and we'll be looking for those. Okay. That's great color. Just lastly from me, this may be a tricky question, but obviously you came out and redacted the guide a little bit for the first quarter for the extreme weather events. Are those pretty much cleared up on your asset at this point? Do you think that the weather's passed, is kind of everything back up and running? You have a pretty wide range on first quarter. Just trying to get a sense if you think everything's baked in, or is there just kind of a lot of guesswork involved because you still got a bunch of wells down? What can you kind of tell us about first quarter? No, we feel pretty good, Leo, that the 20- 23 MBoe/d for Q1 captures the range of outcomes, and we're definitely on the mend. I mean, weather's still tough. It's still cold. It's still below zero and some challenges in the field, but we're well on the mend, and we feel confident that it's captured in the range. Okay, great. Thanks, guys. Thank you, Leo. Thanks, Leo. Thank you. Our next question comes from Neal Dingmann with Truist Securities. You may proceed with your question. Morning, all. My question is just looking at the obviously massive footprint you have on slide 12. I don't know if you can comment sort of post HighPoint yet, maybe too premature on that. My question is really on well cadence. When looking at that acreage, if you could just give us a little color on how you, maybe for the remainder of this year and into next year, how you're thinking about that. I don't know if you can, as I mentioned, whether if you want to just keep it without HighPoint at this point. I think best way to talk about it is as a pro forma enterprise, over 200,000 net acres, as you indicated, Neal, on slide 12. We'll continue with the DUC stimulation work and putting those to sales. That should be in the range of 40-45 DUCs all throughout the year. Our DUC stimulation program on the standalone Bonanza side for Q1 is weighted to the first half of the year, and then we start blending in HighPoint after close. In terms of cadence or pace of development, those turn-ons are going to start in March, and there'll be a pretty steady diet of turn-in lines through the second quarter of those wells that were stimulated by Bonanza standalone in Q1. As we start to blend in the HighPoint DUC inventory as you move into Q2 and Q3, turning those in line. As we pick up the rig and we start replenishing the DUC inventory, the idea essentially, Neal, is to solve for something that feels like notionally about a flat production profile. There'll be some wobbliness on a quarter-to-quarter basis just based on variability of turn-in lines and so on. Generally speaking, we want to maintain flat, stable production profile over time. That's a slight correction to the flat to slightly declining, which we rolled out in November. That's obviously based on higher returns and our returns orientation, given the rally in both natural gas and crude oil pricing. On a one-rig operated pace of development, if you think about over time, that one rig, kind of one frack crew operated pace of development, will turn on a mix of XRLs and SRLs at about 50 per year. Notionally, we'll be able to drill off permit inventory and location inventory across the acreage at a pace of about 50 wells per year. We've got two years of one rig development queued up already in approved permits, and far more than that in terms of high-quality locations and inventory. Wow. I love the inventory. Then just as a quick follow-up on slide 13, looking at infrastructure, I think I know the answer, but I'd just love to hear your color on it. Seems to me you have more than appropriate infrastructure at this time. You look at the gas, oil, and water, maybe, Eric, just love to hear your comments a little more on that slide as far as the combined company, sort of how you think about total infrastructure. Yeah, we couldn't be more excited to put these two gathering systems together. As you point out, it's not just a gas gathering system. It's a gas gathering system, a produced water gathering system, and an oil gathering system. We've got multiple interconnects to multiple midstream gas processors, multiple interconnects to different crude oil pipeline access points and terminals. The gathering system assets obviously represent intrinsic value on their own, which gets better by connecting them, lowering the system-wide gas gathering pressure, which improves the base performance of the wells, all wells connected to it. Then you take that and you compound it even further, when you've got, in the examples where we have, for example, two sections abutting one another or adjacent where Bonanza Creek would have developed one on section length and HighPoint Resources would have developed the adjacent on section length. We can now develop both, pick up the idle resource that would have otherwise been in the setback of those two sections. That's true incremental resource added. Also the economies of scale that are provided by drilling longer laterals. You combine that with tying those systems into either HighPoint Resources' gathering system at the surface or Bonanza Creek's gathering system at the surface. You can see that it basically takes the levelized supply cost to the entire 200,000 net acre position down the cost curve. We just couldn't be more excited to sink our teeth into that. We quantified some of the benefits and some of the synergies, but we think there's a lot there as we continue to dig through, just continuing to lower the levelized supply cost and improve our cost structure. Fantastic details. Thanks so much again. Thank you, Neal. Thank you. Our next question comes from Michael Scialla with Stifel. You may proceed with your question. Good morning, guys. Eric, you mentioned you have an inventory of a couple of years of permits based on a one-rig program. Have you received any permits since the Oil and Gas Commission implemented its new rules in fourth quarter? Just want to get your thoughts on how those new rules might impact you in terms of timing and cost and other aspects. Hey, Mike. Yeah, thanks for the question. We have been receiving a very steady inbound pace of permits. Permits for locations and wells themselves. Those are Form 2 and Form 2A. We've continued to get those throughout 2020 during the rulemaking and then in the time since. We feel pretty good about all the work that's ongoing. I think the COGCC now with the kind of permanent full-time commissioners in place, they're able to get a lot more steady pace of work done. It feels to us like things are incrementally stabilizing. We've got the bulk of the rulemaking behind us in 2020 and the January 15th effective date. There's a little bit more rulemaking ahead of us, but we don't see that as necessarily difficult or otherwise challenging in terms of the company's ability to develop. We just want to see continued stabilization and pace on permit generation, permit clearing, and COGCC hearings and activities at the commission. Do you anticipate any incremental costs with the new rules? Incremental since January 15th, I would say no. It has been a pretty steady increase in the rigor of things like leak detection and repair, site visits, site inspections, and reporting requirements. We've been involved in the rulemaking and sort of front-running those anticipated costs over the last three to six quarters. As we see it coming, we generally build processes and procedures in place. What I would suggest on that answer, Mike, is that we've got most of it built in. Again, you don't sort of wake up on January 15th with the new commission and the new rules in place and then put the processes in place. The cost structure we've had over most of 2020 has most of the procedures and rigor built in, and obviously the associated cost built in. Got you. Okay. Looking at the free cash flow you're going to generate over the next few years, it looks like you're going to be able to reduce the debt you inherit from HighPoint pretty quickly. When you get that to where you want it, I just want to get your thoughts on how you're looking at the use of free cash flow after that, maybe in terms of dividend or buyback or other uses. Yeah, all of those are on the table, Mike. We will have a new Board in place at the closing. I'd hate to front-run those Board decisions and the proper and rigorous analysis, but it's going to be driven, like it always has been at Bonanza, driven by returns. There's going to be probably a mix in that basket of consideration. I think dividend certainly is something we want to talk about and want to better understand. Share repurchases as well. Although, with just 30.5 million shares out, repurchasing those shares is going to be it has a downside to it, but there is a return associated with that activity as well. Then, getting the leverage ratio down to half a turn isn't going to take long. There is an opportunity to use some combination of cash and stock should we find a good opportunity to continue inorganically growing the business through combinations with other companies. Great. Thanks, Eric. Thanks, Mike. Thank you. Our next question comes from Phillips Johnston with Capital One. You may proceed with your question. Hey, guys. Thanks. Just one for me. Page four of the slide deck shows $642 million of PV-10 value at the year-end strip. I'm just wondering if you could provide just the PDP component of that. Yeah, Phillips. Good morning. Thanks for the question. At year-end strip, just to be specific, the PDP PV-10 is $437 million. Okay. That's it for me. Thanks, guys. Thanks. That was easy. Thank you. Our next question comes from Noel Parks with Tuohy Brothers. You may proceed with your question. Good morning. Morning, Noel. Hi. I think since we last spoke, we've got what, $15 improvement on oil prices? How much can change in just a few months. Along those lines, I was just wondering, as far as the different scenarios you were contemplating heading into the HighPoint, well, the announcement of the HighPoint acquisition. I'm just wondering, do you have any thoughts about maybe what the cost structure might look like going forward? I guess I'm just wondering on the service side, after a really slow year in the basin and the COGCC shutting so much down. Now, when things do come back, do you believe we've finally seen the trough in service prices, or do you think there's still capacity and people and equipment out there that badly wants to get to work again? Thanks, Noel. It's a great question. There's a different strategy for different parts of the cycle. I think as we reach this inflection here over the last quarter where things started kind of dramatically grinding up into the ride in the commodity prices. We see ample idle capacity on the drilling contractor side of the business. There's going to be crews available and rigs available and contractors, and they're not going to be, as far as I can tell, in a position to really command premiums for the most part. That's on the kind of the drilling side of the business, the full suite of drilling location services. When it comes to stimulation services, I think it's quite the opposite. I think the stimulation market has tightened meaningfully, just in the last few months. It was already beginning to tighten, even in the back half of 2020, as folks were both recognizing some of the idle capacity was being taken out of immediate availability. At the same time, that which was immediately available was being contracted. I would say on two fronts, drilling, there's idle capacity, and operators will be able to drive a pretty hard bargain on the drilling side. On the stimulation side, it's going to be a little bit more difficult. We've got a stimulation crew under contract now, and we'll maintain that crew under contract for most of the year, to maintain our steady diet of DUCs and then replenish DUC inventory throughout the balance of 2021. We feel pretty good about our access to those services. Those are long-running relationships. I don't anticipate paying spot premiums for those as we've maintained these relationships over time. If you think about some of the other sub-elements, roustabout services, facilities construction services, pipelining services, and the like, I think there's still plenty of slack in the system in most of those service domains. I wouldn't anticipate that tightening up significantly. On the oil country tubular side of the business, I do anticipate that starts to tighten here in Q2 and continuing on. If you look at the scrap metal market, it's kind of a precursor to oil country tubular goods and can be a leading indicator, and that's up substantially worldwide, prices for scrap metal. Let me stop there, Noel, and see if you've got other questions or comments on what I've just said. No, that was really helpful. When I hear you talk about just any elements of tightness, it does make me think, hey, I guess we're in the middle of a real honest-to-gosh rally after such a long time. I guess one more from me. Do you have any thoughts on your hedging policy going forward with the combined companies? Yeah, it's a good question. Again, me trying to front-run what might be a new audit committee certainly will be compositionally, at least, a few new members of the new Board. I can't get specific on that, Noel, but what I would say is, we intend to maintain a very strong balance sheet around a half a turn of leverage. That balance sheet means you don't want to be too aggressive on hedging. You want to be able to allow that balance sheet some exposure. That's just a fundamental balance sheet versus hedging and risk management. Brant, do you want to comment on hedging beyond that? What you think the strong balance sheet and the larger company might imply without front-running an audit committee? Not too, specifically. Noel, I think the tactics will continue to be a pretty disciplined layering strategy, which we've always employed here, predominantly using zero cost collars. Obviously, the book is detailed in the 10-K, you can see that in our existing positions that in the first quarter, we are about three-quarters hedged on the oil side, that declines off relatively quickly over the ensuing quarters. I think that structure will remain as is, even though we're doubling the size. Great. That's all I had. Thanks. Thanks, Noel. Thank you. Our next question comes from Chris Davis with Goldman Sachs. You may proceed with your question. Hi, you hear me? Yeah, Chris. Yeah. Yeah. Chris. The freeze-offs in Colorado and these outrageously high spot prices, is that causing any kind of derivatives whiplash or anything? Brant, why don't you take that? Yeah. Thanks for the question, Chris. I wouldn't call it a whiplash. Clearly, we have a good percentage of our Q1 natural gas hedged. The ceilings of those are in the mid twos, two and a quarter, and a little bit higher than that on some. Clearly that hedge, as gas spikes, works against you as they're structured to do. I would say that the benefit of the current situation, as reflected in our realizations, has been more on the natural gas liquid side, which has become a larger percentage of our product mix. We don't have any of the propane or any of the component products hedged at this point. Between the improved recovery of NGLs, that's been reflected in the overall improvement in realized prices on an oil equivalent basis. Does that help? That helps. I was just thinking, if there's a freeze-off and you can't deliver, and you have an options contract that offsets that seems like that could be a big problem for some producers, and I was just checking with you guys. Yeah, that's actually a good question as well. Our hedge contracts are financial contracts, so we don't deliver physical against those contracts. Okay. If it's a $350 spot price and you have to settle, and normally you would settle by when you deliver physical, you're going to receive $357. If you can't deliver physical, that's what I worry about. Yeah. I'm actually not concerned about our inability to deliver on our contracts, Chris. I'm not entirely sure I understand the question, but what I think I'm hearing is perhaps some concern on whether or not we might have demands to deliver which we can't meet. Right. We have no difficulty at this point, despite the freeze-offs that impacted the business over the weekend. No problem delivering against our contracts. Okay. Thank you very much. Really just the settlement price. Thank you, Chris. Thank you. As a reminder, to ask a question, you'll need to press star one on your telephone. Our next question comes from Ray Deacon with Petro Lotus. You may proceed with your question. Yeah. Hey, good morning, Eric and Brant. Good morning. I had a follow-up on your NGL comment. There's been a pretty big uptick in industrial demand for natural gas. Do you see any read-through on NGL realizations relative to NYMEX in 1Q or 2Q? Yeah. Ray, thanks for the question. They continue to improve. Natural gas liquids, specifically propane, has spiked pretty dramatically here in the last couple of months and partially flowed through in the fourth quarter. It continues to be in high demand, obviously, for heating. I think we'll continue to benefit from unrealized high NGL prices. Got it. Just a follow-up, I guess, with what you mentioned about the COGCC's stricter policies around leak detection and repairs. I guess, do you feel like you might be maybe ahead of some of your peers in the Permian or other basins in terms of being able to talk about the sustainability metrics, emission metrics that most E&Ps are kind of moving towards? Ray, that's a great question, and we absolutely believe that understanding how to be a responsible steward of your resources, whether those are capital resources, land resources, oil and gas subsurface resources, or in this case, air emissions resources and the impacts or the externalities of our operating business. We believe that we've got a competitive advantage. Operating in Colorado, operating with the level of transparency and surface cultural tension that exists in DJ gives us the opportunity, pushes us to be better and delivers to us steel sharpens steel, and it makes us better. The improvement in our operating practices and our knowledge of state-of-the-art best available and safest technologies means that we have a competitive advantage against most operators who don't operate in the same environment. I think that's in terms of leak detection and repair. It's in terms of reporting standards, whether those are CDPHE to the EPA, Title V management according to EPA non-attainment, which the U.S. EPA has custody and stewardship over some jurisdictions, including the Denver metro area. In short, we think it makes us better. We think it's a competitive advantage, and we think most E&P across the U.S. is probably lagging the state of Colorado and lagging in the learnings and the tension we've been able to capitalize on. That's great. Thanks very much. Just a last quick one. I think last quarter, you didn't have clear communication from OXY on plans for French Lake. Does the current budget include anything for drilling there? Yeah, 2021, it doesn't. It does not. Okay. Yeah. What we have is a great relationship with OXY, and we continue to work closely with them. We know they're working hard. Beyond 2021, they're a big organization, and they've got kind of budgeting and long-range plans in place for 2022 and beyond. The short answer is no for 2021, and I think 2022 just remains to be discussed with OXY and remains undetermined at this point. Great resources, great relationship, and everyone's working hard to capitalize on it. That's great. Hey, thanks very much. Thank you, Ray. Thank you. Our next question comes from Thomas Hughes with Wells Fargo. You may proceed with your question. Hey, guys. I just wanted to see real quickly if you've reevaluated the flowback strategy, just in light of oil prices and shape of the curve? Yeah. Thanks, Tom. It's a good question. We will always adjust our economic optimization model according to a constantly updating cost model and a constantly updating revenue model. That includes reservoir pressure management, which is what informs our flowback strategy. It comes as part of the continuously evolving Dynamo, economic optimization tool. What that'll do is it'll tell us whether or not based on the revenue model attached to the type curve, reaches an economic optima with changes, whether that's choking or opening, and then it forecasts and optimizes various streams and various dollar values according to those streams. I guess the short answer is yes. I think the short answer will always be yes, based on the process. The process is set to update continuously on continuously changing cost model and revenue model assigned to a very specific set of type curves according to Dynamo's physics engine. Okay. Thank you. Thanks, Tom. Thank you. I'm not showing any further questions at this time. I would now like to turn the call back over to Eric Greager for any further remarks. Thank you. I just want to thank everyone for joining the call this morning and for your continued interest in Bonanza Creek. Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.