Ladies and gentlemen, thank you for standing by, and welcome to the Q1 2021 Bonanza Creek Energy Inc earnings conference call. At this time all participants are in only listen mode. After the speakers presentation there will be a question and answer session. To ask a question during the session you will press star one on your telephone. Please note this call is being recorded. If you need assistance please press star zero. I would now like to hand the conference over to your speaker today, Mr. Scott Landreth. Please go ahead. Thanks, Ryan. Good morning, everyone, welcome to Bonanza Creek's first quarter 2021 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 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 measure 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 to 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. I would like to turn the call over to Eric Greager. Eric? Thanks, Scott. Good morning, everyone, and thank you for joining us today. We're excited to host today's call to discuss our first quarter results, provide an update on the integration of HighPoint, and discuss the company's initiation of an annual cash dividend of $1.40 per share to be paid quarterly. I'll start with the announcement of our annual cash dividend. This announcement represents a significant milestone for Bonanza Creek. It demonstrates confidence in our business model and consistency of our projected levered free cash flow and our commitment to growing shareholder value. We stress-tested our business at low commodity prices to ensure we have the ability to pay a bold but sustainable $1.40 per share annual dividend, which today represents a dividend yield of approximately 4%. The resilient free cash flow of the business and strong balance sheet provide ample flexibility to support this meaningful dividend while we also pursue other value-creative opportunities. Free cash flow in excess of our base dividend will be used to maintain our low financial leverage and to pursue the highest returning opportunities for our shareholders. The first dividend payment is scheduled for June 30th, 2021, to shareholders of record at the close of business on June 15th, 2021. Our dividend announcement comes on the heels of closing the HighPoint acquisition. The integration of HighPoint's assets into the Bonanza Creek business is underway and mostly ahead of schedule. We acted quickly post-closing to begin realizing synergies that translate to over $31 million of savings within the first year. Several roles were rationalized at closing, and we currently have a transition team working on accounting and other back-office workflows and processes. The combined assets performed to our expectations during the quarter, despite challenges presented by extreme weather events in February and March. On a pro forma basis, the assets produced 42.3 MBOE per day during the first quarter, with 50% of the total volumes coming from oil. Today, we are reiterating our production guidance of 40-44 MBOE per day for the remainder of the year. On the capital front, we started our DUC stimulations in early January and turned the two pads, nine total gross wells, to sales at the end of March. Capital expenditures for the quarter of $32.9 million were below our guidance range due to lower than budgeted costs on planned activity and timing of certain non-well projects that will be completed a few weeks later than originally planned. We have reiterated our full year guidance in a range of $150 million- $170 million, and we anticipate our 2Q CapEx to be up from 1Q. 3Q will be relatively flat to 2Q, and 4Q CapEx to decline from 3Q as we take a break from completion activities at the end of the year. The weather in 1Q negatively impacted per unit LOE relative to both cost and production volumes. We incurred higher costs related to labor as well as road and location maintenance, and volumes were impacted by freeze-offs and short processing disruptions. We expect production volumes to decline slightly on a pro forma basis in 2Q and then stay relatively flat to slightly inclining in the second half of the year. We have reiterated our LOE guidance of $3 to $3.25 per BOE for the remainder of the year. Importantly, you'll also notice RMI unit OpEx is down going forward. Guidance for recurring cash G&A, production taxes, percent oil, and oil differential have also been reiterated. With that, I will turn the call to the operator for Q&A. At this time, if we do have any questions, you can press star one on your telephone keypad. Again, that's star one on your telephone keypad for any questions. We do already have some questions in the queue. The first question comes from the line of Mark Mariani from KeyBank. Hi. I wanted to get a sense of what the first quarter production downtime was, just due to storms. Could you guys quantify that for us? We did. We have, and we can. I'd like to just discuss it kind of briefly here. The February impact I've got Dean Tinsley here who's our SVP of Operations. Dean, as I recall, the February impact was about 60,000 BOE. Exactly. In total, and the March impact was a little bit less than that, about 50,000 BOE. Yeah. Total. Yep. Yeah. Yep. Obviously different in character. One was an arctic cold front, the other was massive snow event. They had slightly differing impacts in terms of the character, but both pretty significant. Okay. Yeah, I guess that, just doing the math here real quick, it looks like it's somewhere around 1,200 BOE per day, if I'm correct here. That sounds about right. Okay. I guess just from the perspective of the cadence of production here, in 2021, you guys did say you thought it was going to tick down a little bit in the second quarter versus first quarter pro forma levels. Is that still correct in light of the storm downtime? Basically, what I'm asking is, if you adjusted for the storm downtime, the number is lower, but would it be lower even when you include the first quarter storm downtime? Yeah, it's still going to be a little bit lower. I think, obviously, the Q1 events lowered Q1. Q2 will certainly have recovered from that. What we're anticipating is Q2 to be somewhere, let's say, notionally between, say, 41 MBOE a day and 42. That's a little bit lower than Q1, and then we anticipate Q3 to be a little bit over 42, and then Q4 to be exiting with a bit more strength, maybe 42.5, or a touch higher. The trajectory or the undulations are pretty subtle. Nevertheless, we want to telegraph that's kind of the shape. It's mostly a result of just the fact that 2020 meant we didn't invest a great deal of capital in new stimulations. On both sides of Bonanza Creek, both the HighPoint side and the Bonanza side, had been stretching those base assets for quite a while through 2020. Let me stop there and see if that answers the question. No, I think it does for sure. Just sort of a different line of questioning here for you folks. Obviously, you're keeping the production relatively flat. You described the trajectory. It's up just a small amount. How do you think about it sort of longer term? Clearly, at these commodity prices, returns on drilling wells look pretty good. What type of conditions do you think are kind of necessary out there in the marketplace for you guys to maybe put some modest growth into the volumes on a longer term basis here? Yeah. It's a great question. We do anticipate remaining mostly flat through 2022 as well as 2021. I think the best way to think about our operatorship of the combined assets is to take these and operate them mostly flat. Obviously, as a result of a stronger commodity price, returns are up. We want to make sure that we take advantage of not only the strength in the commodity price, but also demonstrate the capital discipline we believe that public investment community still expects of public companies, while generating, obviously, strong levered free cash flow. We'll have other opportunities even beyond organic growth through the drill bit to take advantage of attractive returns. All right. Obviously, very sizable dividend that you folks announced today. To the extent that you're kind of keeping the production, call it, relatively flattish, how do you think about the other uses of free cash flow, maybe as we get into next year? Looks like you'll be able to pay off most, if not all, of the revolver here in 2021. You obviously hinted at some inorganic growth, potentially. Absent that not happening, obviously M&A is tricky to predict. How do you see the free cash flow from Bonanza getting utilized, say, next year? No, it's a great question, and M&A is very tricky to handicap and predict. What we would anticipate is, we'll remain active in that conversation, and certainly with an eye toward continuing to drive value accretion for our shareholders on that front. We continue to think about share repurchases, although we haven't yet initiated a share repurchase plan. We continue to think about that and to talk about that with our board. Those things can be tricky as you know, in a commodity-driven, wildly cyclical business. Generally, you have flush cash when your share price is genuinely high, and generally low on flush cash when the share price is attractive to repurchase. We want to be thoughtful about that, and we want to demonstrate discipline to our shareholders. We're going to continue in the conversations around M&A and A&D to the extent we can drive value accretion for our shareholders. We'll continue to have conversations with our board and understand how the investment community thinks about share repurchases. Rather than let cash just simply pile up on the balance sheet, we'll find good opportunities, whether that's special one-time dividends or increasing the base dividend. We want to have all the tools at our disposal and think, as long as we've got a strong balance sheet, lots of levered free cash flow available post-dividend, that opportunities will present themselves. Okay, thank you. Thank you. Our next question comes from the line of Neal Dingmann from Truist Securities. Morning. Eric, based on something you just said, really nice on that, obviously, not only the cash flow kicking off, but the talk about the stable production well into next year. Seems like, looking at our numbers here, there's certainly a number of levers you could pull if you wanted to flex production a little bit. Could you talk, maybe drill down a little bit more on that comment you made about sounds like you have a lot of confidence when talking to you and Brant over the stable production. Just thoughts about that into, I know I don't want to get too much into next year yet, but just maybe what sort of knobs you could turn and to either crank up as prices continue to, if they ramp here, to maybe continue to crank the free cash flow or could continue to crank production a little bit more? Yeah. It's a great question. We've got available permits and inventory. We've got available locations and inventory. We've got lots of opportunity to move across this 260,000 acre position here in DJ. On Hereford, we want to take some more time and continue to really apply rigorous geoscience and be sure we understand all the work that was done, all the data that was collected. I know you didn't ask about Hereford in particular, but I think it's important to understand we're hard at work to understand that asset and really be sure we understand what makes it tick. We've got plenty of opportunities across the acreage position to drill and develop organically. Really what we want to do-- and we've got, obviously, the financial capacity, the liquidity to step on the accelerator. We do think there is some potential as world oil prices continue to push upward for OPEC to continue to open up and release some of that. We also think it can remain a little lumpy or uneven as we continue to move forward with regard to global oil demand. We want to be careful about demonstrating capital discipline to our shareholders, and find ways that present themselves uniquely today to those with a strong balance sheet, lots of levered free cash flow to capitalize on. We think DJ is a very, very interesting environment with low multiples, a well-typed basin. Enough regulatory concern that there's not a great deal of competition for bidding. We want to make sure that those organic opportunities for growth are going to remain there. They're in the subsurface. We continue to build location inventory and permit inventory. The time right now is really ripe for us to create shareholder value through events that might be, I don't know, inorganic in nature that provide us opportunities today that might not be around forever, whereas the organic growth opportunities that will definitely be there. Let me stop there and just see if that is enough color and character around the way we're thinking about it between organic opportunities which will remain available to us and inorganic opportunities which we think we can capitalize on in an opportunistic fashion. No, very well said. Shows all the optionality you have. Then maybe just to follow up, maybe a bit more for Brent, just on spending. Certainly was a bit lower even this, I guess, first quarter than we thought. Second quarter looks like just going to pick up a little bit more on the midstream side. I'm just wondering, seems that spending continues to be a little less than we thought. Maybe could you talk a little bit on the remainder of the year? I guess more pertaining to after you spend the current quarter for a little bit more on midstream, how you think. I know you've got the guide out there, but it certainly seems like going forward, this will continue to sort of tick lower, just based on the organic. Yeah. Thanks, Neal. The first quarter CapEx number was a bit lower than we anticipated. Part of that was some excellent work by the guys in the field to save some money on some projects. To your point, we had some midstream projects that were pushed due to the weather. Those are still, as we reiterated the guidance, those are still within our capital program this year. As Eric's prepared remarks suggest, 2Q will be up. If you think about our $150 million to $170 million guidance for the year, obviously we've spent about $32 so far. The second quarter and third quarter will probably consume roughly $100 million of that guidance amount, and then it'll fall away in the fourth quarter as we take a stimulation break. Does that help with the guidance? Yeah, that's exactly what I was looking for. Thanks, buddy. Thanks, guys. Great. Nice quarter. You bet, Neal. Our next question comes from the line of Mike Scialla from Stifel. Morning, Mike. Morning, everybody. Hi. I want to see, Eric, you talked about a little bit in your prepared remarks, but I want to see if there's any more you can say on the integration of the HighPoint assets at this point, maybe relative to the $150 million of synergies you identified last fall with the announcement of the deal. Thanks, Mike. It's going really well, as I mentioned in the prepared remarks, mostly ahead of schedule. Let me give you a couple of just examples of that. The sum of the two companies' total headcount would have been, if you simply added the two companies up and didn't rationalize any roles at all, would've been 233 total bodies. That's all of HighPoint plus all of Bonanza Creek. We calculated a steady state run rate of a combined company of 144 bodies. The difference is 89 bodies. Obviously, people are expensive and one of the main kind of value generators of consolidation. To put a fine point on the pace here, 48 of those 89 RIFs took place at close. Since that time, we've added another 18 to that, we've got a total of 66 out of 89 total RIFs that have been scheduled, have already taken place, and we're barely 30 days past close. Three-quarters of the RIFs, and those kind of long-term people savings are already beginning to accumulate. I'd say that is fairly aggressive, ahead of schedule we had put in front of us. I'm pleased that the team has been able to act that aggressively. It's never easy to do. These are friends and colleagues, and it's hard work. Nevertheless, necessary because that's what the investment community demands of consolidation. Another example of savings that are ahead of schedule, HighPoint had two offices in Denver. They had a Denver tech center office, that came with the Fifth Creek acquisition, and four floors at a downtown tower. We have now effectively reduced, call it 4.5 floors in Denver to one floor. We've taken 80% of the real estate costs out of the combined company. As it turns out, Mike, one of the things that you probably might suspect, but I'll say it to be clear, those real estate savings were not included in our $31 million synergies, that puts us way ahead of anticipated. The reason they weren't included is because, we didn't have any way to handicap how we were going to be able to carry the HighPoint business through BK and reject those contracts. Let me stop there and say, if you've got any other questions, happy to talk more about kind of the operating side of the business, RMI, the gathering system, and so on. Let me stop there with those two examples, Mike. Yeah, it's helpful, Eric. Appreciate that. Also, just looking at your NGL realizations, they look really strong at over 40% of WTI in the first quarter. I just want to get your thoughts on how that market looks for the remainder of the year. Hey, Mike, this is Brant. Yeah, obviously NGL prices were very strong, have been most of the winter. They remain strong. I don't know if we're tracking at close to 50% of WTI, looking at this morning's prices on Mont Belvieu, they still are close to that. There is a steep backwardation in that market, similar to WTI. I think going forward, we're going to trend slightly down, I think they'll remain strong at least through the spring. Of course, a lot of that is due to Asian demand for propane specifically, naphtha cracks have widened as well. I think there's a good fundamental strength in the NGL market. I don't know if I would model it at mid-40s, maybe model it 35%-40% of WTI going forward. Okay. Thanks, Brant. I know it's difficult to do, is there any thought around trying to hedge any of those prices? Yeah. The deepest market is the propane market, and that is the most important for us. It's about 40%-45% of our value of the Y- grade barrel for us. If we chose to hedge, we'd probably use propane swaps. The collar market in the NGLs is really too thin to do anything of size, so we might layer in propane hedges. Got it. Okay. Last one from me. I saw where you put an ESG committee in place on the board. I know you're already exceeding some pretty stringent emission standards. Just want to see any thoughts on what kind of initiatives the committee will be looking to implement for Bonanza. Thanks, Mike. I appreciate you recognizing that. It's something we've given a lot of thought to. Obviously, the investment community expects responsible operators to have ESG committees in place. We've always taken our responsibility for stewardship of environmental resources, people resources, water, land, air resources, all of that. We've always taken it very seriously. The ESG committee helps formalize some of those measures. We're still in the process of establishing kind of the key performance indicators. It's going to be aimed more around kind of the global metrics as you've started to see, and I've started to recognize. There's half-dozen or so kind of key frameworks for global climate change and the proper measures. There's still a lot of room to work within various frameworks and establish what is most meaningful to various operators. For us, obviously, air emissions are very, very important. The CDPHE does a good job in maintaining oversight along the Denver Front Range. As you know, this Front Range area is an EPA nonattainment. It's serious nonattainment and likely heading to severe nonattainment, in terms of ground-level ozone. We're way ahead on EPA Title V facilities in the engineering and application of Title V principles and applications. I feel really good about that. The ESG committee is going to help us formalize what are the metrics that are important to Bonanza Creek, important to our constituencies on the ground, COGCC, CDPHE, our shareholders, and the global shareholder community in general in oil and gas. Specific KPIs we're still working on, to be really honest, because it's pretty complicated when you look at the various metrics out there that we can draw from. Let me stop there. I'm happy to answer more questions on that front, Mike, but I want to stop and see if you've got a specific one that I can follow up on. No, that's helpful color. Appreciate that, Eric. That's all for me. Thanks, guys. Thanks, Mike Scialla. Thanks, Mike. Our next question comes from the line of Nicholas Pope from Seaport Global. Morning, guys. Hey, Nick. How's it going? Wanted to touch a little bit on the new assets. You added a slide here on just the performance of Bonanza Creek versus HighPoint and similar areas. I was hoping you could maybe dig into that a little bit. What's the biggest components of improving what you see as the ability to improve well performance? What's going to be the biggest drivers of that list that you laid out? Also, in terms of spacing, maybe touch a little bit on Bonanza Creek versus HighPoint, where things might be on a relative percentage of optimally drilled or remaining inventory on comparable acreage. I'll let you. Yeah. Thanks, Nick. Let me touch quickly on the real value drivers, or if you do a regression analysis on various factors that drive well performance, that regression will allow you to explain something like 60%-80% of the variation between wells in a given comparison set or sample set. Those regression models almost always point to geology, which is duh, Greager, rock matters. That's important. When you normalize or you stabilize the sample set for geology, what is really important is the amount of time or the amount of distance or lateral footage that has landed and remains in the best rock. That requires active geosteering. I think everybody talks about geosteering, but there's a difference between heel to toe, drill it as fast as you can, and active geosteering, which uses real-time at-the-bit logging while drilling data to evaluate the highest quality reservoir and remain in the highest quality, highest porosity and permeability, and oil saturation at all times. Then once you've done that, you've got to drill, case, and cement in a way that you've got adequate zonal isolation with a large monobore. One of the key differences between the way Bonanza Creek operated and the way HighPoint operated was HighPoint tended to set intermediate casing and then run production casing inside of that. That naturally restricts the size of the production casing, generally to about a 4.5 in nominal production casing. We don't set intermediate casing, which results in a monobore with 5.5 in high collapse P110 production casing. That, combined with a really high-quality primary cementing job that provides the zonal isolation, allows you to drive 100- 105 bbl a minute into the wellbore, delivering a lot more horsepower and a lot more kinetic energy to the rock, which drives greater fracture surface area, larger stimulated reservoir volume, and better stimulations. Generally speaking, our higher intensity stimulations cost a little bit more. If you spend 5% more on total D&C CapEx, but you yield 100% better or twice as good a well, I think the economics are pretty clear. That's what we're trying to demonstrate on slide 11. We've done a head-to-head well performance comparison. We've done a historic three-year comparison across all of Wattenberg where we share like acreage, then we've given you a map there on the left to describe the acreage. The primary driver is, of course, stimulation intensity, but it requires that you construct the right wellbore architecture at the outset, because if you don't, then you can't deliver the energy to the rock and overwhelm the reservoir and deliver the fracture surface area, which drives unconventional shale performance. There's gas lift. You have to have good low pressure gas gathering operations at the surface because if you don't have low gathering system pressures expressed at the wellhead, then the reservoir has to buck higher pressure to get to sales across the meter. Low gathering system pressure expressed at the wellhead allows the reservoir to perform better, unload better, faster, and so on. You combine all of these things with gas lift energy from the outset, combined with the fact that we apply active reservoir pressure management to maximize the oil sweep to the front of the curve using the solution gas drive energy, which I've talked about in the past, and I'm happy to talk about here. That really does outline kind of the three or four key metrics that our regression analysis would point to driving performance. Nick, I'm going to end the what drives well performance and the difference on slide 11. I want to pivot to spacing and stacking, because that's another key element. We have an operation. We obviously operate in a wildly variable commodity price environment, and the volatility of a realized pricing means you've got to maintain optionality as far into the development cycle as you can. Generally, what that means for us is we will permit as many wells as we believe we can subject to regulatory scrutiny and other restrictions at any given DSU. What that does is allows us, because of the long lead time in development planning, if you increase the number of wells permitted into a DSU, then you have the option to, of course, set surface and drill all of those wells. Provided the commodity price doesn't support that, you can skip slots or you can set surface and drill only the production intervals necessary. What I'm trying to say is you create optionality deeper into the cycle by permitting more wells per DSU, and then exercising that option as you set surface, then as you drill out production, and then deeper into the cycle, you can even retain optionality that Dynamo provides for maximizing economic returns based on stimulation design, even as we zip wells together toe to heel. Spacing and stacking are price dependent, and they're commodity price dependent, and even a really good hedging strategy can't take all the volatility out of realized pricing. In order to help blunt the effects of the volatility that does carry through, we maintain optionality as deep into the process as possible using this kind of Dynamo plus development optionality approach. I think it's somewhat unique to our eastern rural acreage because of the way the acreage lays out, but also because of our relationships and the Dynamo optionality. That's great. That's extremely thorough. Very helpful. Thanks, Nick. At this time, if there are any other questions, you can press star one on your telephone keypad for any questions. We do have a question from the line of Phillips Johnston from Capital One. Morning, Phillips. Yeah. Hey, guys, thanks. Just one for me, actually. We look back at the November guidance when the deal was announced. You guys were expecting combined volumes to sort of trend in the 47,000-48,000 a day range throughout this year, and we're now obviously looking at something closer to the 40-44 range for the rest of the year. It looks like your recent well results continue to show strong performance. I'm wondering if your base PDP decline rate has maybe been a little steeper than expected, or are there other factors to consider? Obviously, we've had some timing deferral of wells, but at some point, you would expect that to normalize. Thanks. Yeah. Thank you, Philip. It's a great question, and no doubt, we did make significant structural changes to the development plan between the November ninth announcement and the April fifth guidance. It's one of the unfortunate consequences of a five-month period between announcement and guidance. Nevertheless, essentially, that difference between, let's call it for the sake of argument, 47 MBOE down to 42 MBOE a day between November and April. That really was the result of our deferring 22 wells that were built into the production performance plan when we made the announcement in November. three pads, 22 wells. That's the Helton, the Sebring, and the AEF pad. All three of those pads were delayed to 4Q and two pads from 1Q to 1Q. The result of that, obviously, is the fact that we saw or realized $35 million more cash at closing without a change in our 2021 CapEx. More importantly, it means we were able to capture value by, in kind of referring to those slides earlier in head-to-head performance between legacy HighPoint performance and legacy Bonanza Creek performance. We wanted to put our combined teams' stimulation capabilities on those 22 wells, and we're confident that we're going to drive higher rates of return, more growth in the future, and higher levered free cash flow. We did so even knowing that it was probably going to be something a little bit difficult to explain. If you think about 22 wells deferred in that period of time, even 250 or 300 BOE a day for 22 wells easily explains the full year 5,000 BOE across that time horizon. We believe over the long arc of time, it's value accretive, even given discounting and backwardation of the strip, because we're likely to almost double the performance in the UR of those wells by applying more intense stimulation designs and better reservoir pressure management. Let me stop there and just see if that helps explain the structural change to the schedule, then I am happy to pick up on the conversation around 4Q and 1Q. Yeah, no. I think that completely explains the question. Thank you very much, Eric. Thanks, Phillips. Our next question comes from the line of Noel Parks from Tuohy Brothers. Hey, good morning. Hi, Noel. Hey. Well, congratulations on the deal close, and just had a few things I wanted to run by you. I think last quarter we were talking about, in terms of the service cost, that the completion market, stimulation market, was tightening up. I believe your current frac crew is under contract, if I remember right. As that contract begins to age, I'm just curious, can you just talk about each company's relationship with its service providers and what might be on the table as you continue on and your current agreement gets towards expiration? Yeah. Thanks, Noel. It's a good question. Generally speaking, there's a bit of upward pressure on all things steel in the space, and frankly, around the world. You probably know that. Within our basin in particular, we've got OCTG acquired for the balance of our 2021 program and well into our 2022 program. Frac horsepower is also experiencing some upward pressure. The thing I'd like to say, and I'm pleased that our operations team, they took advantage of our free agency on 15 DUCs that we put into the schedule. We carried 30 in that we were going to operate at Legacy Bonanza Creek. We added 15 more to the plan for 2021. Those 15 were not committed under contract yet. We went out to RFP and we held the line, in fact got better than the 2021 frac pricing for the balance of those 15. We actually put a little bit of downward pressure on our aggregate horsepower and total frac services costs by adding the 15. We did so by driving some competitive tension into our fracture business, our fracture stimulation business. It meant that we had to divide it up amongst some other service providers, but we did so in order to be certain that we could deliver the highest value to our shareholders. We managed to hold frac services in line, at least for 2021. I do believe in general, there's some upward pressure. Noel, this is Brant. I think also, obviously, fuel costs are up, so that does impact how we think about inflation pressure. That's right. Yeah, you're fueling 25,000 horsepower-30,000 horsepower, and that's not a small thing. Sure. Well, thanks. I guess another sort of, I guess you'd call it another integration question, if you will. Given the importance of the relationships with the state and the regulators, I'm just wondering what the combined, I don't know if you put that under, like, the government relations umbrella. The combined team or the combined effort from legacy HighPoint and you now, what does that look like? Do you have people in place who have sort of familiarity with where things stand with the different tiers of permits you're seeking and so forth? And also who have the relationships with the regulators that you've nurtured for so long? Yeah. It's a good question. We did bring some of the best and brightest talent from HighPoint's EHS and regulatory compliance team into the organization. We've, I think, improved through the process. We've improved the workflows, the talent of the organization, and there's a lot of depth of understanding across both sets of assets with regard to permitting and regulatory, both CDPHE and COGCC. HighPoint and Bonanza were each other's largest working interest partners, so we understood a great deal of what they were working on already. Some of the compression, for example, and operated gathering systems were unique to HighPoint, and we needed to understand sort of the unique permitting relationships there. I think we've got a very solid handle on that as part of the integration work. Obviously, Hereford was also unique. We've got the right people working on the Hereford asset base and continuing to develop relationships across all these assets where we needed to build new people into the organization. Great, thanks. That's all for me. Thank you, Noel. Thanks, Noel. We do have a follow question from the line of Mike Scialla from Stifel. Hey, Mike. Yeah, thanks. Hey, Brant. Just to add one follow-up. Eric, you talked about some of the wellbore architecture differences between the Bonanza and HighPoint wells. I believe those 22 wells you delayed completion on were DUCs, so I'm just wondering if you will be able to use the larger production casing and higher intensity frack on those, or is it too late in the process to complete those wells the way you'd like? Yeah, it's a shrewd observation, Mike, and you're absolutely right. That's one of the things that we wanted to take. In fact, it's one of the key drivers for us wanting to take the combined teams' modeling and design capabilities and apply to those 22 wells. Those are drilled and completed, cased and cemented, or sorry, drilled and cased and cemented, and subject to stimulation. They are mostly four-and-a-half inch casing designs. What we're going to need to do is, you won't be able to drive 100-105 bbl a minute down that four-and-a-half inch casing. The friction loss is just too high. We're going to have to pull back the treatment rate and constrain and drive the kinetic energy delivery into the reservoir through smaller TFAs, smaller perforation, total flow areas, and constraining through stage and perf architecture, the pressure drop, and drive the intensity not so much through higher rates, but through constrained exit and smaller TFAs in terms of the perf clusters. It accomplishes the same objective, but it slows the pace down a little bit because you have to constrain the stages a little bit more, slightly smaller stages, lower TFA or total flow area in the perf clusters in order to generate the high intensity pressure drop, the extreme limited entry conditions. You can generate the same intensity, but it requires a little bit different engineering, and we wanted to make sure that the combined teams had a chance to do the proper modeling to ensure that we were maximizing the economic returns of those opportunities because they were different from the more traditional high rate, high intensity stimulation in 5.5 in wellbores that we're more accustomed to designing to. The other thing I want to point out is there was a real opportunity to optimize infrastructure tie-in. For example, the Helton and Sebring are close in proximity to RMI, and had HighPoint invested in tie-ins and facilities on those two pads independently, there would've been incremental facilities and tie-in dollars spent that aren't necessary and likely to achieve an inferior total outcome. The real opportunity is there to create value by deferring and getting the combined team to look at both facilities design as well as stimulation design. Let me stop there, Mike. Yeah, it's helpful, Eric. Just one follow-up to that. Do you have any history of the higher intensity frack in the four-and-a-half inch production casing, or would you say a little bit of risk to doing that and trying something new? No. As a matter of fact, surface intermediate and 4.5 in production casing was the standard leading up to 2013- 2014, when we began to recognize as an industry that rate extreme limited entry and kinetic energy to overwhelm the rock was the way to drive well performance. What we have to do is we have to look back in time and figure out fluid systems that can accommodate it. This is physics. It's pretty well understood. I'm not concerned that we won't get the well performance. It's just going to take a little bit more time and energy to understand thoroughly how to develop those stimulation designs. We'll take the time necessary to deliver the kinetic energy. That might mean a little bit longer stimulation periods as we zip toe to heel, simply because you've got to constrain the energy in smaller stages because you have lower rates. It's not a question of whether or not you can deliver the energy to the reservoir, it's how you concentrate the energy to the reservoir. Got it. Very helpful. Thanks. Thanks, Mike. No other questions in the queue. Ryan, thank you. I want to thank everyone for joining us this morning, and thank you for your support of Bonanza Creek. Everyone have a nice day. This does conclude today's call. You may all now disconnect.