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Good morning and welcome to Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions]. As a reminder, this conference call is being recorded. Joining us today from Earthstone are Robert Anderson, President and Chief Executive Officer; Mark Lumpkin, Executive Vice President and Chief Financial Officer; Steve Collins, Executive Vice President and Chief Operating Officer; and Scott Thelander, Vice President of Finance. Mr. Thelander, you may begin.
Thank you, and welcome to our fourth quarter and full-year 2021 conference call. Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of federal securities laws. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in our fourth quarter and full-year 2021 earnings announcements and in our Annual Report for 2021 on Form 10-K. These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement issued yesterday. Today's call will begin with comments from Robert Anderson, our CEO, followed by remarks from Steve Collins, our COO, and Mark Lumpkin, our CFO; and then we'll have some closing comments from Robert. I will now turn the call over to Robert.
Thanks, Scott, and good morning, everyone. We appreciate you joining us today for our fourth quarter and full-year 2021 conference call. It has been a few months since we last spoke to you. And we have been pretty busy since then continuing our corporate strategy of creating shareholder value through accretive acquisitions, organically growing with the drill bit, managing our balance sheet and delivering strong financial results. The dedication of all our employees is evident by the results delivered in the fourth quarter, and for the full-year 2021, and so far in 2022 as well, including what is now a total of six acquisitions that were closed or announced. And my gratitude goes out to all of our employees for what we have accomplished. We continue to demonstrate our ability to acquire and integrate accretive and well located assets that generate meaningful production and cash flow and continue to drive down our overall cash costs. With the Chisholm acquisition behind us now, we have closed five acquisitions since the start of 2021, not including the pending acquisition of Bighorn, which is expected to close in mid-April and we're extremely pleased with the results. Our high-level of acquisition activity positions us to achieve our goals of being a much larger scaled, low cost producer with a more robust high margin drilling inventory and lower reinvestment needed in order to maintain combined production levels. We are truly transforming Earthstone into a bigger and better company that is built to last. As we look ahead to 2022, we remain focused on integrating these assets, generating substantial free cash flow, continuing to strengthen our balance sheet and identifying operational synergies. As planned, we closed on the Delaware Basin acquisition, our largest deal closed to-date in mid-February. We've already begun integrating these assets and are excited about what this means for our daily production rates and free cash flow generation capacity. These assets expand our operations into the Delaware Basin, generate significant production and cash flow from existing wells, and with us now running two rigs in the Delaware Basin, further unlock the potential of this acreage. Importantly, the Delaware Basin assets provide us with the opportunity for additional growth. Thanks to a high return drilling inventory that consists of over 414 gross operated drilling locations. Additionally, we are on track to close on our Bighorn acquisition in mid-April and excited about the impact this asset will have on our company. This will be the latest in a series of highly accretive acquisitions with Bighorn being the largest in terms of both incremental production and incremental cash flow. Also, given the low decline rate and maturity of these assets, we anticipate additional capital investment on this acreage to be relatively low. And we have identified areas where operating synergies could further reduce lease operating expenses as there is overlap with our existing assets. With the Bighorn assets included, we will have more than quadrupled our daily production rate and should end 2022 approaching 80,000 BOE per day with a greatly expanded acreage footprint, and all of this achieved over the past year-and-a-half. We expect that this additional production, our four-rig drilling program, and the strong commodity prices to enable us to generate significant free cash flow while only reinvesting about half of our EBITDAX. The magnitude of our future cash flow generation gives us some flexibility as well to consider a number of uses for our free cash flow including debt reduction, further acquisitions and may include shareholder returns. As I mentioned, the two most recent acquisitions that we've announced are the largest in our company's history. However, with our success in using equity and cash and structuring the consideration of these acquisitions, we remain positioned to be below our targeted one time debt-to-EBITDA leverage ratio by year-end 2022. We're proud of the continued strength of our balance sheet, and we won't consider transactions that would jeopardize this strength. While we continue to pursue potential acquisitions, opportunities that fit our criteria, the size of our latest deals dictate that we make efficient integration a high priority in the near-term, and you'll hear more about that. Steve will provide some additional details on our integration and our drilling activities in a moment, but first, I just want to touch on our capital budget. As a reminder, we continue to run two rigs in the Midland Basin and are now running two rigs in the Delaware Basin. We plan to continue this pace in both basins given our strong drilling inventory and cash flows. We are currently allocating a capital budget of $410 million to $440 million for 2022 to operate our four-rig program, which generates substantial free cash flow. Our capital budget also accounts for some of the cost pressures that we are continuing to experience and expect for the foreseeable future. We expect that cost inflation will remain a challenge and although our team has been doing a great job of working to mitigate these impacts, with operational efficiencies, the impacts are real, but they are manageable. Now with that, I'd like to turn it over to Steve Collins to provide an update on operations.
Thanks, Robert. Good morning, everyone. We've been operating two drilling rigs in the Midland Basin since the third quarter of 2021. Details of those operations can be found in our February 16 operations update. In 2021, we turned to sales a total of 19 gross, 15.4 net operated wells. And due to our drilling schedule shape out, where we factor in operations and reservoir dynamics, our 2021 operated program average lateral length came out to 5,500 feet. And while the results of the wells brought online in 2021 have been encouraging, we're excited about our 2022 Midland Basin program, where we expect to bring online 40 gross, 36.7 net operated wells with an average lateral length of approximately 9,500 feet. On the LOE side of things for 2021, I'm very happy to see our goals of being a low cost operator continue to manifest itself. We saw LOE per BOE under $5 for the fourth quarter, and under $5.50 for the full-year. My team works very hard at reducing costs and production downtime in the field in order to increase overall margins and drive cash flow generation. Now moving on to current activity. In the Midland Basin, we just brought online five gross, five net wells on our Nickel Saloon pad in Upton County. These wells targeted the Wolfcamp A, Wolfcamp B and Wolfcamp C zones, with an average lateral length of 10,100 feet. And while these wells are still cleaning up, early signs like to be very encouraging, particularly some Wolfcamp C wells that are making over 1,200 BOE per day. Wolfcamp A and B wells average approximately $684 per foot to drill and complete, which is at the lower end of the range for the 2021 estimate for 10,000 foot wells that we've discussed with you in the past. We are currently in the process of completing six gross, also six net wells on our Hamman project area where we have an average lateral length of 7,700 feet and targeted the Wolfcamp A, Wolfcamp B and Wolfcamp C zones. These wells are expected to be online in early to mid-April. Additionally there's another six gross or 4.8 net Midland Basin wells that are drilled and waiting to be completed. We're all very focused on efficiently integrating the newly acquired Chisholm assets into our operations, where we have hired the majority of the field staff providing consistency in operations. We will continue with the two rigs currently operating in the Chisholm acreage in the Northern Delaware Basin and New Mexico. We just finished drilling a two well pad in our Anaconda project where we hold a 42% working interest, and will average 10,000 foot laterals targeting 3rd Bone Spring zone. In two well pad in our Minis project where we hold a 96% working interest and will average 7,500 foot laterals targeting the Harkey zone within the 3rd Bone Spring. Completion activity on both of these pads will start in the middle of March and we expect to have these wells online early in the second quarter. One of the rigs is now drilling a two-well pad on our Ram [ph] project in which we have 86% working interest. And the other rig is drilling a two-well pad in our Delaware project, in which we have a 62% working interest. Both pads are located in Lea County are targeting the 1st and 2nd Bone Spring zones. In late January and prior to the closing of the Chisholm acquisition, a total of five gross, 3.2 net wells returned online and all located in Lea County and targeted to the 2nd and 3rd Bone Spring Zones. Our 2022 capital program of $410 million to $440 million provides for a continuation of the four-rig program, two rigs in the Delaware Basin and two rigs in the Midland Basin, and we expect to bring online a total of 58 gross, 48.3 net operated wells in 2022. We also expect to participate in some non-operated Midland Basin projects that should total $25 million of capital and bring online an incremental 4.2 net wells. Additionally, we have budgeted another $25 million for land, infrastructure and workover project. And now moving on to the Bighorn acquisition, given the acreage is more developed than our other acreage, we don't anticipate spending a material amount of capital on the assets outside of these smaller workover projects that are already baked into our full-year capital budget. As a result, we expect to see significant free cash flow coming from the Bighorn acreage should commodity prices remain at a level we're currently experiencing. And as we've laid out in our public guidance, once we have the benefit of a full quarter of Bighorn production, we expect to see total production for the company to be around 78,000 BOE per day, and are currently forecasting low-single-digit production growth annually on a go-forward basis, under our four-rig development program. And now switching over to the cost side on both drilling and completion activities as well as field and lifting costs. We're currently seeing many of the same inflationary pressures as our peers with service prices and raw materials increasing in real time, and expected to increase by 15% similar to what we saw in 2021. As expected service companies are pushing to increase prices as demand increases. To offset this we have locked in long-term contracts where it makes sense on things like frac sand and production tube, we continue to source less expensive supplies and services that are protected from supply chain disruptions. By adding both Chisholm and Bighorn to our asset base, which have higher field operating costs and our legacy position, we expect LOE per BOE to be higher than where we have been historically. And our guidance for the full-year of 2022 of $7.25 to $7.75 of LOE per BOE reflects that. However, once we've had a chance to get our arms around both assets and apply our own operating expertise to procedures, we are confident that our team will find ways to reduce these costs, and create additional value on both assets. We maintain a very thoughtful and disciplined approach the way we handle consolidation, and the execution of our operations. We will closely monitor our pace, make sure we fully understand the newly acquired assets and promptly apply any learnings that we may have gained throughout the process. With that, I'll turn it over to Mark.
Thank you, Steve. As I did last quarter, I'm not going to repeat a bunch of numbers and metrics from the earnings release or 10-K, which you can find on our website. And as a reminder, there is our full-year guidance also on our website from our February 16 operations update and also in our investor deck. So let me begin with some details around our balance sheet and the impacts of M&A activity on the balance sheet. As of year-end 2021, we had a borrowing base on our credit facility of $650 million. With borrowings of $320 million at year-end, we had approximately $330 million of undrawn capacity. Based on our debt at year end, and $85 million of adjusted EBITDAX for the quarter, our fourth quarter debt-to-EBITDAX was 0.9x. As we announced in mid-February, our borrowing base and elected commitments were increased from $650 million to $825 million upon the closing of the Chisholm acquisition. And as of March 1, just to give you guys an idea of where we stand, post-Chisholm, we had $652 million of outstanding debt and $1 million of cash, leaving us with about $174 million of undrawn borrowing capacity in cash. And related to the Bighorn acquisition, we did borrow approximately $50 million to fund the deposit. So that is reflected in the outstanding debt of $652 million as of March 1. Further, we secured commitments on our credit facility to increase the borrowing base and the total commitments by an additional $500 million at the closing of the Bighorn acquisition, which will bring our borrowing base and elected commitments to $1.325 billion. To reiterate what Robert touched on earlier, we're optimistic that we'll achieve our targeted one times or lower debt-to-EBITDA in 2022. Our ability to make acquisitions using a mix of debt and equity has enabled us to add significant scale while minimizing the incremental impact on leverage and also minimizing equity dilution. Our fourth quarter EBITDAX of $85 million was 31% increase on a quarter-over-quarter basis and a new quarterly high for our company, driven not just by the strength in commodity prices, but also lower LOE per BOE as Steve mentioned and our ability to control G&A costs. We added $28.5 million of free cash flow in the fourth quarter, which brought us to $107 million of free cash flow for the full-year and we expect to substantially increase this free cash flow number in 2022 with the additions of both Chisholm and Bighorn. With the addition of the Chisholm assets and the pending Bighorn assets, we expect free cash flow to be a multiple in 2022 of what we saw in 2021. As a result, we'll be in a strong position to consider the best uses of our future free cash flow. In the short-term, we expect to utilize free cash flow for debt repayment, but as we delever further, we should then be able to consider a shareholder return program. From a production standpoint, we came in above our fourth quarter guidance with about 3,200 barrels of oil equivalent per day, which was 43% oil, 30% natural gas and 27% natural gas liquids. When looking at 2022 and all the moving parts related to the timing of the closing of the Chisholm and the Bighorn acquisitions, we've laid out a detailed production guidance that again, can be found in our February 16 release or in our investor deck. But just to hit high-level summary on that, we did break down a little more granular to make clear what our expectations are for the first quarter and the rest of the year. And for the first quarter, we expect production to be somewhere between 35,000 and 37,000 BOE per day with a 44% oil cut. That includes approximately half a quarter of Chisholm and none of Bighorn which we don't expect to close until April. In the second quarter with the closing of Bighorn and Chisholm in our reported results for the full-year, we expect to produce approximately 70,000 to 74,000 BOE per day with about a 41% oil cut. And finally for the second half of the year, that will step up further as we get a full quarter, a full contribution from both Chisholm and Bighorn and we expect the second half production to be somewhere between 76,000 and 80,000 BOE per day with an oil cut of about 41%. So on a full-year basis that build up equates to production, somewhere between 64,250 barrels a day of production, and 67,750 barrels a day of production comprised of about 41% oil, 33% natural gas and 26% NGLs. Total cash G&A for the fourth quarter and full-year 2020 were $6.3 million and $20.9 million respectively, which also came in a little bit lower than the midpoint of our guidance. For 2022, we're guiding to full-year cash G&A of approximately $31 million to $34 million, which implies a cash G&A cost of $1.35 per BOE based on the midpoint of our guidance, which would be a 40% decrease on a per unit basis compared to 2021's $2.31 per BOE of cash G&A. On the LOE front, as Steve mentioned, we had an exceptionally low cost fourth quarter with LOE per BOE of $4.94 coming in about 16% lower than the midpoint of guidance. And this resulted in achieving full-year LOE per BOE of about $5.45 per BOE. For 2022 and reflecting the assets acquired with higher levels of LOE, our guidance for LOE is in the range of $7.25 to $7.75 per BOE as Steve mentioned. As we look ahead to 2022 from a capital expenditure standpoint, we're targeting a reinvestment rate of not much more than about half of our EBITDAX pro forma for Bighorn and that provides a significant free cash flow generation while largely holding total production flat throughout the year pro forma for all the acquisitions. And this of course, includes the assumed timing of the Bighorn acquisition in mid-April. On the hedging front, as we did in our last call, our plan for 2022 has been to be a bit less hedged than we have in the past. Pro forma for Chisholm and also for the Bighorn acquisitions were a bit over 50% hedged on both oil and gas from May onward. As it relates to the recent closing of Chisholm and the pending Bighorn acquisition, the production of the respective assets from the effective date through the closing date and really a bit beyond that is unhedged and we have and will benefit from those significant increase in commodity prices versus what we had assumed at signing. This effectively lowers the cash paid at closing and on the Bighorn acquisition, in particular, we expect a reduction in the purchase price to be over $100 million, assuming the mid-April closing date that we're targeting. With that, I will turn it back over to Robert for closing comments.
Thanks Mark. As you can all tell from our results, as well as our guidance for 2022, 2021 was truly a transformative year for Earthstone. But we believe the best is yet to come. We enter 2022 in a better strategic position to optimize our operations, generate substantial free cash flow and deliver significant shareholder value. Our ability to get acquisitions done using equity as a meaningful component of the total consideration to sellers demonstrates confidence in our team's execution and validates our strategy, while also bringing benefit to the long-term strength of our balance sheet. These six acquisitions that we've closed or announced in the past year-and-a-half, have expanded our footprint by over 220,000 acres, and have given us an increase in our total proved reserves to today where we sit at approximately 330 million barrels of oil equivalent with a PV-10 value of $4.5 billion using March 1 NYMEX strip pricing. When you consider just the proved developed value it's $3.2 billion, which shows the resiliency of the business we have built with these transactions, and illustrating our ability to continually complete attractively priced acquisitions with significant upside potential. Commitment to our core beliefs and strategy remain regardless of market conditions or commodity prices, we put all potential acquisitions under a technical and financial microscope and prioritize shareholder value above all else. This will not change in 2022 as we operate as a much larger entity. And as you have heard, we are prioritizing the successful integration of our recent acquisitions. However, we will also focus on building scale in an accretive manner, and we'll continue to consider complementary assets that fit our acquisition criteria, and allow us to maintain the strength of our balance sheet. We will continue to operate responsibly in every community or area where we have assets and people. And finally, we will put Earthstone in the best position possible to maximize per share value for each and every one of our stakeholders. Now with that operator, we'd be glad to take a few questions.
Thank you. We will now be conducting a question-and-answer session. [Operator Instructions]. Our first question comes from the line of Neal Dingmann with Truist. Please proceed with your questions.
Good morning, all. Robert, question as you guys have obviously done a fantastic job not only scaling up but doing that well now having a great free cash flow profile so I know in the past, you've mentioned a good bit of that free cash flow using the scale versus paying that either for the dividend or a buyback. I'm just wondering, now you and Mark, and the team sit down and look at it. Certainly have the scale; you certainly have still the free cash flow. How do you think about it today or more the near-term thoughts about free cash flow?
Yes, that's a good question, Neal. And there's not an absolute answer just yet. We've got to get Bighorn close. I'd like to have a couple quarters of execution under our belt, and then start considering what our other alternatives are for free cash flow as well besides just paying down debt, or thinking about shareholder returns of some sort, but also looking at maybe other opportunities to spend that cash flow. So all of those are on the table. And we'll just continue throughout the year after we get Bighorn close and see how the environment is when we look up after a couple of months, a couple of quarters of operating all of this stuff at once.
And does that include I mean again look I think your shares; I think a lot of folks who are incredibly straight, but obviously the float an issue. So is -- I don't know a question for you or Mark, part of that is, is that an option?
Of buying back shares is what you're asking, I think Neal.
That's right. Yes, that's right. That's right.
It is an option. I mean all alternatives are sitting out there for us, we don't have to do anything, there is no gun to our head either way and we'll consider that as we consider a shareholder return program at some point down the road.
Okay. So I guess that's where I was going this last question is just when you look at where your shares and I'm sure you Mark run kind of how your thoughts on asset value on those versus what you're seeing in the market? Do you think there's one is looking quite a bit more attractive in our deals, I guess another way just asked about M&A are deals now starting to get more expensive given the strip. And your best method is your shares over deals that, I'm glad you get the deals that you did. I'm just curious on how you see deal prices out there today versus kind of how your shares are trading?
Yes, there's basically a huge disconnect. As you can imagine, we think there's a lot of value in our stock that isn't being appreciated. I would say that it's really tough to do M&A or A&D transactions in a price environment like this, we need some stability. I don't know when that's going to happen. Nobody's probably buying or selling based, or nobody's buying on the current strip price for $100 for 2022. We'll be very cautious about the way we look at transactions and definitely use something other than the current strip price, at least in the near-term and maybe back into the curve is about right. So it's going to take some stability in the market to make the A&D market a little bit easier.
Thank you. Our next question is coming from the line of Jeffrey Campbell with Alliance Global Partners. Please proceed with your questions.
Good morning and congratulations on the recent flurry of successful acquisitions. Robert, kind of picking up on what you just said about commodity volatility, have to ask this confluence of world events and the current very high oil prices. Is there any temptation to increase capital investment in the future subject to any gating items that you might want to identify?
Good. I thought you were going to ask something about, are we considering doing a bunch of hedges now at this price, which we talk about that all the time?
No.
Activity wise, yes, activity wise, I think we need again a couple of quarters of execution on the Delaware asset, make sure that we're all really comfortable that we can run before we start walking, which we'll get there. I'm convinced that won't be an issue. We just need some time. Not that there's any issues today. But before we ramp up production, I mean, ramp up activities there, I just want to have a couple of quarters of as flawless as you can get. On the Midland side, we could. But again, I think we're focused on getting our balance sheet and our leverage ratio under one by the end of the year. And with the improvement in prices, or the increase in oil prices, maybe that happens a little sooner. And so we could think about it. So it is some things we're looking at in terms of accelerating activity. But we're not going to pull the trigger on that in the near-term for sure.
Okay, that's very helpful. And I think you've already sort of alluded to this, but let me ask this question anyway. On Slide 15, you illustrate a capital program that is significantly weighted to the Midland Basin, is this what we should broadly expect over the next several quarters or in a year or two? Or could the Delaware Basin attract more capital as you gain familiarity with operations there?
I've actually had this conversation driving in this morning with one of our guys in terms of planning and as you know, the Delaware Basin, the northern portion is on federal acreage, it takes a little bit longer to plan out programs there. It's great, Rob good economics. I wouldn't be surprised in a year that we have more activity there, not maybe in dollar cents, but definitely more activity than we have today. Maybe we're drilling bigger pads or what have you, but it's a great place to spend capital. And after we get a little bit more familiarity, like you said, we could spend some more capital there for sure.
Okay, great. Then this could go into the thinking too hard category, but on the same slide. You illustrate a rig plant in Irion County. I just wondered if this suggested might be attracting some capital in 2022.
It is. It's actually we're drilling a five-well pad down there right now and drilling two different intervals in the Wolfcamp. We'll see how those turn out, economics look good. Our data from offset wells that we now own look good, so that's why we put a rig down there, it won't stay there for the whole year, it's going to drill, like I said, a five-well pad and then we'll move out of there and we could move back towards the end of 2022 with and drill another pad.
Okay, great. And so last one, I'll ask, I am going to approach the return to capital to shareholders a little bit differently. If you can provide some color on what you see as the relative merits of a dedicated dividend, or a special dividend, or share repurchases, I think that would be helpful insight.
Okay. Well, let me just say one thing first, the buyback is probably the lowest alternative, because we're two-thirds held by some really good shareholders and investors and board members. How about that? And then the other two, I'll let Mark chime in here, because I've been doing all the talking.
Yes. I was just going to say, Jeff, we've got a ton going on right now. And we're kind of nose to the ground in terms of getting Chisholm integration completely done. Getting Bighorn close, as Robert mentioned, getting a quarter or two on our belts, things operating pretty quickly. Those are great questions in terms of, hey, if you're thinking about shareholder returns, where do you get? We do think about that. But we are not at a point where we're really even doing any real analysis between one option versus the other, that will naturally come if things go as we think they will later in the year. We don't really have any strong opinion one way or the other on regular dividend if so what size versus special dividend, et cetera.
Okay, great. Well, that's fair. And it's pretty hard to complain about what you're doing presently. So stick to your knitting. Thank you.
Thank you, Jeff.
Thanks, Jeff.
Thank you. Our next question comes from the line of Scott Hanold with RBC. Please proceed with your questions.
Yes. Hey you all mentioned that deferred program gets you into that single-digit growth rate over the next few years. And as you kind of big picture think about longer-term the strategy, what is the strategy you guys want to sort of develop like what do you think the optimal mid to long-term pace for you all is?
It's probably in the single-digits, Scott, somewhere, but depending on how things work out in New Mexico, and if like I'm viewing that, we're really excited about the -- what's happening out there with results, then we're going to spend more capital out there, and maybe we have a little bit higher growth. But today, where we sit, running four rigs for the foreseeable future, it's just low-single-digit growth, and throwing off a lot of cash and getting our leverage below one and all the things we've already kind of talked about.
Scott, when we run our models, it's static, it's not assuming further acquisitions. And we've certainly made some very significant steps here in the past year-and-a-half. When we think about things going forward on a status quo, that's sort of what things look like, but we don't think we're done on the acquisition front. Are we pausing a bit to digest things? Absolutely. And do we feel different about acquisitions when oil is hitting 120 on the screen than when it's hitting 60, absolutely. But there's still a ton for us to do to get to the decision points, anything in terms of adding a rig or dropping a rig or moving a rig around. So we're thinking about all these things, but it's just a little bit premature for us to really go stick our flag in the ground of what we think the next even two or three years looks like.
Okay. And then could you just give a little bit more color on the E&D market right now, it does sound like you're -- well and let me ask you the question this way. Do you find that there is more opportunities, a bigger opportunity set in the Delaware now than the Midland and like what is the biggest kind of issue between the bid ask spread right now, is it just the PDP at strip price or do current parts want to get paid for inventory plus strip PDP?
Yes, that's a loaded question with a lot of pieces to it, Scott. So, my view is that there are a lot of opportunities in Delaware Basin; it's less consolidated than the Midland Basin. But they both have a number of things that are sitting on our board that we look at and consider as opportunities. With the volatility that we've seen in the last month activity is stalled. I won't say it's slowing down or it's not accelerating, for sure. But there's deals that are kind of stalled out because of where prices are. And I suspect that the bid ask, and then there's the deal flow is sort of slow to advance -- come out as, as much as I thought it would be in the first quarter when we're working on December kind of activities and A&D things. I think that difficulty is just, we don't mind leaning in and paying for inventory. But you're going to do that at a much lower than current strip price. And then PDP becomes a problem when you got this much volatility and the buyer universe isn't going to put on a near-term price deck of $120 so that that creates just a difficult A&D market.
Okay, makes sense. And then just quickly, I think last quarter, you made the comment that OFS inflation, you're seeing 10% to 15%. Can you remind us what's in the budget? So I'm just kind of curious on like, how that's changed in the last say three to four months?
Yes, there's definitely some further inflation baked into the budget. If you look at what we've put off there from a 2020 capital side, just from a Midland side, you can sort of back into $800 per foot completed on the Midland side. Rob or Steve just mentioned, we just finished something up, that was a bit under 700. They're absolutely higher now than they were 36 days ago, or 90 days ago. So we got a little bit more baked in there. I mean it's sort of about 10% to 15%, throughout the year we're baked in. And certainly with prices like they are, there's no great way to feel confident as bookings, but we do have some inflation built in.
Thank you. Our next question is coming from the line of Charles Meade with Johnson Rice. Please proceed with your questions.
I appreciate your commentary on inflation and I thank you for being so clear on that. But I also wanted to ask a belated question on service availability and really the question is, how concerned are you about service availability in this environment? And I'm thinking particularly, perhaps on frac fleets because you guys are not, a little bit shy of running one rig continuously, on either side of the basin as it looks for me. So what's up is that what we should be worried about or just something you worry about at all?
I don't worry about it. Steve's here, so he can answer it probably more completely. But I'll tell you, we've got a long relationship on our side with our frac pressure pumper. And all the ancillary services there. So they know our schedule, and we're sort of locked in for the year on that. And then on the Delaware Basin assets, obviously, we don't have that same history and track record, but they were using a large frac company. And again, they know what the plan is for the year and we're not going to deviate too much from that plan. So that side of it, other than the sand doesn't keep me up at night. Steve, what keeps you up at night?
Well, it is something to worry about, but you can let us worry about that. I think we're going to be okay. And what I mean is that we create these relationships like Robert's talked about and I hope that our culture and how we do business out there makes all these service companies want to come to us first. So far, that's been the case. I know it is on the Midland Basin pressure pumping side. We need to still go out and create those relationships in New Mexico. But you here every day and people are struggling to get services. So far we've been okay. And I expect us to keep being okay.
That is helpful inside your operation, Steve. And then this was perhaps for you because it goes back to your prepared comments, but I'll just thought to leave you guys. You mentioned the Wolfcamp C in the Midland Basin, I'm just curious, how prominently does that figure in the 2022 drilling plan in and how prominent is it in your overall inventory on the Midland Basin side?
We'll probably drill one or two more sea wells in 2022 as we get back to that Upton County area; it's a very low for us. It's a very localized geologic phenomenon that works really well in one area. This isn't -- you go back several years to a famous sea well in Reagan County that was drilled by an operator that is no longer in that same name. And the well was fantastic. Our wells are a little bit different geologically. And we've drilled some other wells in Reagan County or participated in wells in Reagan County in the sea that aren't the same. This is a little bit different, and we like it, but it's not a big piece of our overall inventory. It's not even a third of our Upton County inventory, so.
Got it. That's the detail I'm looking for. Thank you.
Thank you. Our next question is coming from the line of Subash Chandra with Benchmark. Please proceed with your question.
Yes, thank you. First one is on the borrowing base utilization pro forma for Bighorn. With the preferred -- convertible preferred trying to wrap my head around that, if you can help and then on -- and I think you mentioned that based on the timing, the actual acquisition cost will be lower from a cash perspective. How close to the $1.325 billion do we get with peak borrowings?
Sure. Maybe let me hit the convertible preferred first. So that's the pipe that we did around the Bighorn transaction. That's within Cap and Post Oak. And that's $280 million of cash they're putting in equity. Ultimately, that should get converted into Class A shares, a sequence event and timing and sort of NYSE approval standpoint requires that that goes to a shareholder vote. We have the vote already in hand, but that still has to formally happen. There is something that some lawyer could imagine that would cause that to not happen, but it's not anything you would consider any real practical risk. So that effectively is Class A common shares, but they won't get converted until sometime in probably the summer if that helps. On the borrowing base and liquidity, so right now, we've got about $650 million drawn. That includes our having paid a deposit. Total on Bighorn, we think the purchase price adjustment, which is basically 3.5 months of kind of free cash flow. We'll be over $100 million, so that's going to reduce the cash need at closing of Bighorn in April. We think, roughly speaking, on the day we closed Bighorn, we're about $1 billion, maybe just a tad higher, $1.025 billion of drawn RBL versus the $1.325 billion. And that's clearly high. We are monitoring the markets. And at some point, it probably makes sense to issue a high yield. We're going to keep looking at that. And that is on the radar. There's a lot more wood dropping other areas currently. But that is an option to where we could term out some of the RBL debt and have a lesser amount drawn on the RBL.
Got it. Okay. Excellent. The second is that from a reserve report, it seems to me -- so there was negative provisions but then there were strong extension discoveries. It seems to maybe there were some spacing elements on pre-book, but that was exceeded by fresh bookings. Is that the correct interpretation? Or how should I sort of put the performance revisions in the context?
You got it, Subash. I mean, it's -- you drill in areas and you got a type curve going into it, and it's based on all the data you've got, which a lot of times is different spacing and wells that are not offset by other wells. And then you go into an area and you're drilling what we call child wells or second wells in an area and they don't perform exactly like that type curve. So in some areas, it went down and in some areas, it went up. The sea is not a surprise. It's performed well. And then in other areas, we've got some nice enhancement in some new ads that we could make.
Okay. Got it. And finally, I think you expressed with -- to a number of the questions that were asked previously, that there is an optimal activity level that's higher than where we are four rigs. Do you think of the world this way like there's also an optimal production level at which whatever it might be, revenues coming in the door, ease of budgeting and working capital and all that kind of stuff a production number that you think is optimal? And just a follow-up on the optimal activity level, do we think of a six-rig program as being an optimal case?
We have not tried to optimize, because I'm not sure what we're -- what bells and whistles we would turn for a production number. Are we trying to keep production flat at 80,000 BOE a day? No, not really. It's -- a, we're inheriting two rigs on this Chisholm acquisition. We got our own two rigs. If we just keep the status quo, what does our model kind of look like? And like we've mentioned, a little bit of growth in production. So like we've already said, give us a couple of quarters of working in New Mexico and who knows what else we buy, but assuming we don't buy anything else, then we'll figure out what is optimum there based on our acreage position and how much activity we could have and the best reservoir development and things of that nature. I mean, we definitely have a plan. It's not -- we're not sitting here today without one. But to increase that plan, it takes a little bit of lead time, and we're working through that right now.
Okay. And if I could just ask that differently do you -- I know you guys are return-driven, right? So you may not look at the world this way. But is there a production number if you're looking at acquisitions at which you're like, okay, this is kind of a good steady-state base of operations, 100,000 a day, 150,000 a day. Do you think of the world that way?
No. I look at opportunities to create value. And if we can buy assets in Irion County at a nice discount and can operate them cheaper and get a bigger scaled business than I think we all benefit as an Earthstone stakeholder. I don't put a target out there and say, okay, we got to have 400,000 of acres or we got to have 15 years of inventory or we've got to hit 150,000 BOE a day. I think those are all outputs of your asset base.
Thank you. [Operator Instructions]. Our next question is coming from the line of Jeff Robertson with Water Tower Research. Please proceed with your question.
Thank you. Can you all talk a little bit about the LOE initiatives on both Chisholm, but maybe also on Bighorn where you think you can lower LOEs over the course of this year or maybe heading into 2023?
It sounds like you, Steve.
Well, we're in the process of learning that and figuring out, but I can tell you this that looking at what they're spending. For example, the Bighorn chemical program is probably 20%, 25% higher than what we run in the Midland Basin. So we'll dissect each category and figure out what they're doing and maybe we can adapt some of our principles and go from there. A lot of it is going to be mechanical. What's been done, what needs to be repaired that actually could increase production, which could help on the LOE per BOE side. So we've got a lot to figure out, but it's going to be taking what they're doing and incorporating what we know works best. The -- yes, I think that's it.
Hey, Jeff, if I can just add, like just from a big picture standpoint, on the Delaware Basin, the costs are just higher. And on the Bighorn assets, there's not a bunch of flush production because they've not been drilling other than having completed some DUCs, I guess, in the fall last year. Neither one of those are going to get down to what our kind of pre-acquisition LOE per BOE is. But I think what Steve is saying is that, hey, give us some time, maybe this sounds like a repeat record. But give us a quarter or two to get these things digested. And Steve and team are already looking not just in the Delaware Basin, but the Bighorn assets, too, which we haven't even closed on yet of ways to drive some of those down. We put out a range that we think is very reasonable. Steve's goal is absolutely to beat that range. But it's a little bit hard to go figure out exactly what you can do until you've got the assets in your hands, and you can have some ideas, but you've still got to have time to go execute on those things. And certainly, the goal is lower but it's going to take some time to figure out how much is really possible.
I'll add, there's also some synergies and just the geography out there. I mean, we literally have legacy Earthstone leases right next to Bighorn leases. So we'll be incorporating that in and consolidating routes and we're not going to trip over one lease to go to another lease. So we've got a lot to figure out on that, but I think there's going to be some efficiencies gain there.
So that's a better discussion to have in November as you've owned those assets for four or five months and really start to think about what you can do for 2023?
Yes. I should -- I won't be guessing by then. I'll know what I can do and what I can't.
Thanks. And one question just since you've talked about rig activity. Given Earthstone's current size, is four rigs the right number? Could you run five, could you run six comfortably without really stressing the operations team?
Well, Jeff, there's more to stress than just the operations team as you run more rigs. But four is a good place to start for us. But I think we have the capability, and ultimately, when we get these sort of integrated and people right-sized, we're going to have the ability to run more and whether it's five or six, we can continue to grow our staff and be able to do that. We've set the company up to manage a much bigger organization than we had two years ago, even a year ago. And we're making some strides now to even get it ready for the next expansion. So let's close Bighorn and then walk for a little bit, and then we'll pick up some activity I'll bet.
Thank you. There are no further questions at this time. I would like to turn the call back over to Robert Anderson for any closing comments.
Thanks, everybody. We appreciate your interest and the questions, and we'll talk to you again soon. Bye.
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