Earthstone Energy, Inc. (ESTE) Q1 2023 Earnings Call Transcript

Earthstone Energy, Inc. (NYSE:ESTE) Q1 2023 Earnings Conference Call May 4, 2023 1:00 PM ET

Company Participants

Clay Jeansonne – Director, IR

Robert Anderson – CEO, President

Steven Collins – EVP & COO

Mark Lumpkin – EVP & CFO

Scott Thelander – Vice President of Finance

Conference Call Participants

Scott Hanold – RBC Capital Markets

Neal Dingmann – Truist Securities

Subhasish Chandra – Benchmark

Charles Meade – Johnson Rice

Jordan Stewart – Golden Tree

Jeff Robertson – Water Tower Research

Operator

Good afternoon, and welcome to the Earthstone Energy’s Conference Call. [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.

I’ll turn the call to Clay Jeansonne, Director of Investor Relations. Thank you. You may begin.

Clay Jeansonne

Thank you, and welcome to our first quarter 2023 earnings conference call. Before we get started, I’d like to remind you that today’s call will contain forward-looking statements within the meaning of federal securities law. 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 annual report on Form 10-K for the year ended December 31, 2022, our quarterly report on Form 10-Q for the quarter ended March 31, 2023, and the first quarter of 2023 earnings announcement. This document can be found in the Investor Relations 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. Reconciliation of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement issued yesterday.

Also, please note information recorded on this call speaks only as of today, May 4, 2023. Therefore, any time-sensitive information may no longer be accurate at the time of any replay listening or transcript review.

Today’s call will begin with comments from Robert Anderson, our President and 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’ll now turn the call over to Robert.

Robert Anderson

Thanks, Clay, and welcome, everyone. Thank you for taking the time to join us today after what I suspect has been a really busy morning for you all. Earthstone entered 2023 strategically advantaged with an enhanced and increased scale in the premier Permian Basin through the deep and high-quality inventory and a strengthened financial position.

This strategically advantaged position is clearly apparent by the solid results we posted once again. I’m pleased to say we are off to a great start this year with these strong results forming a solid foundation to build upon during the remainder of 2023. Slide 5 of our investor presentation that has been posted on our website highlights the significant performance increases we have achieved compared to the first quarter of 2022.

Earthstone’s operational excellence continued during the first quarter of 2023 with total production surpassing our internal forecast and consensus estimates. Our low decline, stable production base and strong new well results drove our production outperformance for the quarter.

We reported first quarter production of 104,450 Boe per day, with oil over 46,000 barrels per day. We have now had two quarters in a row with production approaching 105,000 Boe per day and continue to showcase the quality and productivity of our inventory. Steve will highlight several wells that drove our strong quarterly outperformance.

The strength of our operational performance was also reflected in our strong financial results. Near-record level production, combined with our low cost structure, led to adjusted EBITDAX for the quarter of $267 million. This robust EBITDAX and rigorous capital investment discipline led to the generation of free cash flow of approximately $42 million in the quarter. This free cash flow for the quarter allowed us to continue to execute our plan to reduce debt, lowering our debt to just under $1 billion with a similar amount of liquidity, which Mark will highlight further.

The strong overall performance we posted for the first quarter clearly represent the merits of our focused proven acquisition strategy. At Earthstone, we continuously focus on creating long-term value for our shareholders while fostering a culture of doing the right thing, public confidence and our reputation are valuable assets. As such, we place critical focus on reducing our environmental impact and conducting business and interacting with our employees, contractors, land owners, suppliers, governmental entities, the public and the communities in which we operate responsibly and ethically.

We are also committed to providing our employees and contractors with safe working conditions in an environment conducive to creativity, continuous improvement and maximizing job satisfaction. We believe providing ESG-related information and metrics to our shareholders and other stakeholders is essential while communicating how we plan to progress over time.

Regulators have continued to increase the threshold by which we must operate and we are investing the necessary capital to do so. In order to communicate with our stakeholders in a transparent and open manner, we are working on our inaugural ESG report. We expect to have our report published by sometime next quarter.

Now I’d like to turn the call over to Steve Collins to provide an update on operations.

Steven Collins

Thanks, Robert. Good morning, everyone. First quarter was another outstanding quarter for the operations group. We maintained our rig count at five during the quarter with three in the Delaware Basin, two in the Midland Basin, drilling a total of 16 gross wells and 12.4 net wells we put on production a total of 15 gross and 12.8 net operated wells.

As Robert mentioned, our operations team brought some great wells online during the quarter. We have shown the areas and results of these wells on Page 12 of our updated corporate presentation, which is available on our website.

Let me highlight a couple of those pads. We completed the Jade 34-3 Fed pad, where we have approximately 52% interest on acreage acquired from Chisholm in the Northern Delaware Basin in Lea County, New Mexico. The wells targeted the first and second Bone Spring intervals. The four wells had an average IP 30 rate of 1,240 Boe per day from laterals averaging 9,900 feet with an average oil percentage of 91%.

In Eddy County, in Mexico also acquired from Chisholm, we completed the Dark Canyon 1522 State Com 2-well pad that delivered an average peak IP 30 of 1,422 Boe per day which is approximately 69% oil. The average lateral length of these two wells is about 7,050 feet, and we hold 100% working interest in these wells.

At our El Campeon project on New Mexico, Texas State line, we recently drilled two of the six wells scheduled for the project and have two additional wells slated to start early May. Lateral lengths for the six wells will range from 9,400 to 10,000 feet. We have significant ownership interest in these wells and expect the first well to start producing in August. These are the first wells drilled across Mexico, Texas State line.

In early February, in the Midland Basin, the WTG 5-234 2-well pad in Raven County was put on production. We have 100% working interest in the Wolfcamp Upper and Lower B wells that have an average lateral length of approximately 9,850 feet. The wells had an average peak IP 30 rate of 945 Boe per day and the production stream was around 77% oil. This project continues to highlight the strength of our Reagan County acreage.

At Earthstone, given our efficiency mindset, we take pride in increasing value by improving the operations of acquired assets. I want to highlight a new slide on Page 13 of our investor presentation. Since taking over operations on one of our recent acquisitions, we have improved drilling and completion efficiencies significantly. Our drilling practices have increased the feet drilled per day by 34% versus the previous operator.

We have also provided a case study of four actual wells drilled two by the previous operator, the other two by Earthstone. The Anaconda 11:14 2-well pad had a total measured depth averaging 21,000 feet. The two wells were drilled from spud to TD in about 32 days. Our PaxiSouth [ph] federal 2-well pad had a total measured depth averaging approximately 23,000 feet and was drilled from spud to TD in only 18 days, a decrease of 46% while averaging an extra 2,000 feet in length, a solid improvement from the previous operators’ performance.

We’ve also improved efficiency significantly on the completion side. We have increased the frac stages pumped per day to 8.5 in the Delaware, which represents a 16% improvement over previous operator. This has allowed us to get wells on production sooner and lower completion costs.

We’ve also changed the completion design and flowback strategy since acquiring the Northern Delaware assets. The amount of sand pumped has increased while the same time – at the same time, reducing the amount of water used. We’ve also modified our flowback strategy. The combined changes have yielded impressive results, increasing cumulative oil production by more than 30% over a 7-month period. These examples highlight our ability to integrate and make improvements to acquire assets which are value drivers for shareholders.

As in the past, we will continue to be laser-focused on reducing costs on our recently acquired assets and across our existing asset base. LOE for the quarter was higher than expected. This was due to a number of items, including higher compression costs, increased labor costs and EHS regulatory and environmental initiatives throughout our operating areas. We are focused on reversing this trend and have our team working through their specific areas of responsibility to achieve this.

Turning to service costs. We are starting to see some good news on that front. Rig rates are showing signs of softening, and we are beginning to benefit as our rig contracts come up for renewal. We also see a softening for cementing services and the cost of production casing. In short, we’re cautiously optimistic that service cost inflation is starting to abate, which we may see a little bit in the second quarter results, but more likely to be realized in the second half of the year.

With that, I’ll turn it over to Mark.

Mark Lumpkin

Thank you, Steve. As usual, I will focus my comments today on providing some additional details on meaningful metrics and key highlights and leave the detailed breakdown for you to find in our earnings release and our 10-Q, which were both distributed yesterday.

Turning to our financial results. Adjusted net income for the first quarter was $109.1 million or $0.77 per share and adjusted EBITDAX was $266.9 million. Free cash flow for the first quarter was $41.8 million.

On March 31, we had $452 million outstanding under our credit facility and total debt was just under $1 billion. Our debt to last 12 months adjusted EBITDAX ratio was 0.8 times. In the near term, we plan to continue to use free cash flow to reduce debt. We are thankful for our long-standing banking relationships, and we welcome the three new banks that recently joined our bank group.

The $200 million increase in our electric commitments, which occurred in March, took our electric commitments from $1.2 billion to $1.4 billion. We really feel like this support underscores our bank group’s recognition of the financial strength of Earthstone and the high quality and sizable asset base we have built over the past several years. This increase to our electric commitments provides us with significant financial flexibility and optionality for the future with close to $1 billion of undrawn revolver capacity.

From a production standpoint, we are pleased to significantly exceed our internal forecast and Wall Street consensus estimates, achieving production of 104,450 barrels of oil equivalent per day, which was comprised of 44% oil, 30% natural gas and 26% natural gas liquids. We have guided to our 2023 production of 96,000 to 140,000 barrels of oil equivalent per day.

From a cadence standpoint, notwithstanding what was a really strong first quarter, our year is unfolding as expected, and we do still anticipate a step-down in production levels in the second quarter with the second quarter most likely be in our lowest production rate for the full year and also our lowest oil cut for the year. We expect production to pick back up by around midyear, with the second half of the year likely increasing from the second quarter daily production rate.

As Steve mentioned, our lease operating expense was a bit higher than expected with LOE coming in at $9.36 per Boe for the quarter, which was about $0.74 per Boe above the midpoint of our guidance. Starting out the year high relative to our guidance puts us in a position of working hard to get back in that range, and our team is working really hard to accomplish that goal.

From a cash G&A perspective, our first quarter expenses were just under $13 million, which is right in the range of our full year guidance on an annualized basis and represents a call on a per Boe average basis of $1.38, which compares very favorable to our peers.

Moving on to CapEx. We invested $202 million in the first quarter, which is right in line with our plan and consistent with our expectation that CapEx would be a slightly bit more half weighted than back half weighted.

For 2023, we still expect to invest between $725 million and $775 million of capital with the second quarter CapEx is expected to be somewhat similar to what we saw in the first quarter with slightly lower CapEx in the second half of the year. Please see yesterday’s earnings presentation for more detailed information on our 2023 guidance, which has not changed.

With that, I will turn it back to Robert for closing comments.

Robert Anderson

Thanks, Mark. Looking ahead, we will continue to prioritize debt reduction with our expected substantial free cash flow. Having said that, we continue to believe scale matters in our business, and we will look forward and look for accretive assets that will increase our size while simultaneously creating additional shareholder value.

We believe we have built a company that offers an attractive value proposition to investors, including having a solid balance sheet with one of the highest free cash flow yields at one of the lowest enterprise value to EBITDA multiples in the E&P sector and a current valuation that is significantly below our total proved reserves, which stand currently at $4.6 billion and is $1.7 billion higher than our current enterprise value.

Our deep inventory, long history of operational excellence and consistent performance position Earthstone to continue outperforming for years. Our team has a long history of creating value for shareholders. We will continue to work diligently to ensure that the long-term value we have created for our shareholders is ultimately recognized.

I’d now like to turn the call back over to the operator for the Q&A portion.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold

Thanks, All. You’ve had some pretty solid performance in the last couple of quarters. And obviously, without the, I guess, we call it the noise of acquisitions in the numbers. It looks – it’s really much more evident. And it looks like the well performance you have really reinforces that.

And my question is, ultimately, as you take a look out over the next – and I think you said about 10 years of inventory, can you give us the sense of how confident you feel in the quality and the depth of that relative to what you’ve drilled here recently?

Robert Anderson

Yes. Thanks, Scott. It’s a great question. Obviously, we have a portfolio of assets, and we are maximizing the value of our co-development or resources in the front part of a multiyear plan here of 10 years. So as we get out to year 7 through 10, it probably looks a little different. But definitely, over the first few years of our plan, we expect that what we’ve been drilling will have similar results for the next several years.

Scott Hanold

Okay. And I guess my follow-up is on M&A, obviously, you gave some pretty good color on how you think about it. But maybe more specifically, what does the market look like right now? Do you find that bid-ask spreads are reasonable? And are there more opportunities in the Delaware versus the Midland at this point?

Robert Anderson

The market will always speak and deals always seem to get done. So somehow the bid-ask spread gets overcome. And we’ve seen deals here recently where there’s some kind of earnouts and things like that to help the buyer and seller mutually agree to get something done. So it’s always a problem that we, as buyers have to negotiate around and we’ll be creative as anybody to try and get deals done if that’s what it takes. There’s a good pipeline of opportunities in both the Delaware and the Midland at the moment.

And I think that will stay true for the next 12 to 18 months as private equity-backed teams as well as noncore assets get pushed down the food chain, you might say or people need to monetize for whatever reason. So we’re pleased with what we’re seeing right now, and our guys are pretty busy looking at a number of different opportunities.

Scott Hanold

Yes. And I would assume that you all are in pretty much every data room or opportunity. I’m just kind of curious, there have been a couple of decent sized deals that have happened on both sides of the basin. And I would assume you looked at it. Just at a high level without being too specific, do you find that your price was sort of the reason that you all didn’t come out on top on some of those? Or was it something else?

Robert Anderson

Price is probably the biggest driver in a lot of transactions. Now let’s be honest here. We’re not looking at deals that are $3 billion, $4 billion, $5 billion, right? I mean there is a limitation to — even though we like to look at those, how much we could actually go out and do. So in the deals that we look at, usually, it’s price that’s driving the answer, and we’re focused on adding value accretively to this whole Earthstone business that we’ve created over the last 2 years, and we don’t want to do something that’s going to change our stripes.

Scott Hanold

All right. Thank you.

Operator

And our next question comes from the line of Neal Dingmann with Truist Securities. Please proceed with your question.

Neal Dingmann

Robert, I guess, pretty straight quarter. Given what you said about having, I believe, nearly the lowest EBITDA multiple and highest free cash flow of the Intergroup which our estimates would totally support and having this balance sheet, why not expedite the shareholder return then versus kind of late in the year or next year?

Robert Anderson

Yes. Good question, Neil. And it’s something that we, as a Board and management team talk a lot about, we just haven’t made that direct commitment yet because we’re going to continue paying down debt even though the balance sheet is in good shape and our leverage is under one time. And we’re continuing to look at all these opportunities. So I want to make sure that the time is right when we do that because it’s a commitment that you make that you probably can’t break.

And we’re pretty good at keeping our word when we’re going to do something. So we’re just not ready. A little bit of it could be our size to at $2 billion market cap, is that the right size to initiate or institute something. So I’d say keep watching sooner or later, that probably is something that we come to a plan, but we’re not ready to do it this quarter, for sure.

Neal Dingmann

No, that’s understood. And you guys certainly always do what you were going to say. So I appreciate that. And then secondly, just on when you look on service costs out there, the way I want to ask that is, it seems like you and others maybe are starting to see a little bit of softness. If you get that and it’s — so you got to end up some savings that you and Mark don’t have in the plan, would you just sort of stockpile those savings, put them on the balance sheet? Or would you continue to keep the plan as active, which would result in even higher activity?

Robert Anderson

We’re probably not ready to have higher activity yet. New Mexico is a great asset for us. We’ve got 3 rigs running Steve might beg to differ some days, but I think it’s working pretty efficiently. We do have — always have something going on in the field. But we’re walking pretty good now. And at some point, we’ll get to a position where we can run and maybe we add activity. But again, a lot of permitting time lines that you’ve got to rely on and the infrastructure, all those components need to fit together really nicely.

And right now, we like the optionality that we have running 3 rigs. You go to a higher level of activity, and that could limit your optionality in some cases. So right now, we’re going to stick with what we got, deliver the free cash flow. And if we get it some extra, we’ll pay down some more debt. And hopefully, we’ll be able to find some transactions we can spend that money on.

Neal Dingmann

I’m glad to hear it. I appreciate both the financial and operational optionality you have. I think it’s a leading characteristic.

Robert Anderson

Thanks, Neil.

Operator

Our next question comes from the line of Michael Scalia with Stephens Inc. Please proceed with your question.

Unidentified Analyst

Yes. Good morning, everybody. Just want to follow up on the last question on your activity. And you mentioned some of the constraints on the Delaware side. When do you think you could tilt more toward the Delaware? Is 24 possible to lean more on Delaware versus Midland — or is it further out than that?

Robert Anderson

It’s possible, Mike, to do something in ’24. We’re permitting wells for the middle of ’24 already. It has to do with some capital we’re spending this year on the infrastructure side and just making sure that we’ve got all everything lined up that we need to. Plus, again, it’s going to be a balance between commodity prices and service costs. And there’s no reason to accelerate into a high service cost environment if the commodity prices don’t aren’t beneficial to us. So there’s a lot of balls we’re juggling right now, and it won’t likely happen this year to accelerate activity out there, but it could in 2024.

Unidentified Analyst

Okay. And I just wanted to ask another question on your acquisition strategy. It sounds like there’s a lot of things in the pipeline that you’re looking at. If it looks like you’ve been able to buy things in the past at kind of PDP value. If you don’t get the right price, is there an opportunity now given you’ve got a pretty good sized footprint in both the Midland and Delaware.

Wondering if there’s an opportunity to pick up like small interest around the area where you’re not necessarily buying these larger marketed packages but smaller pieces where you could replace a lot of the drilling inventory that you’re drilling up every year.

Robert Anderson

Yes. Good question. And we do focus on that as well as the larger packages, whether that’s trying to do a trade with somebody, so we can bulk up in an area that we’re planning to drill a year or 2 from now or just flat out buy out either partners or smaller operators or what have you. So every rock is overturned for us to look at acquiring more assets within our footprint and maybe even expand our footprint a little bit. But in both basins, we’re looking at all options to increase our inventory

Unidentified Analyst

Appreciate the answers. Thanks, Robert.

Robert Anderson

Thanks, Mike.

Operator

Our next question comes from the line of Subhasish Chandra with Benchmark. Please proceed with your question.

Subhasish Chandra

Hi, Robert, maybe, Mark, as well on this question. Can you just review the nonrecurring CapEx this year, if it’s changed at all, I think, on the infrastructure side? And would you hazard to guess as to what sort of deflation you might see in ’24, keeping the program flat?

Mark Lumpkin

Sure. I’ll try to hit that one, Subash. So first, if you look at our guidance, the midpoint of our total CapEx of $750 million, and we sort of lay out what portion of that is D&C in both the Delaware and the Midland and then what non-op-D&C is. So if you back that out, it’s about $92.5 million, that’s other stuff. So of that, Yes. The infrastructure is a decent chunk of that and we are spend that through the course of this year. That is a bit elevated relative to what we would expect in 2024.

But I don’t think it’s going to subtract like $30 million or $40 million relative to next year. From a like deflation standpoint, I’m not sure that exactly think of it as deflation, more so just a little less required activity. I mean there is stuff that we’re doing in Delaware, in particular, this year that is sort of onetime events. And I would say that’s probably $20 million of the 92.5.

Subhasish Chandra

Okay, Mark. So if I sort of understood that, what would be the sum total of the 2? And also, when I think of — do you think of these as sort of truly nonrecurring? Or is there sort of that nonrecurring — the recurring nonrecurring element that we sometimes…

Mark Lumpkin

Well, I think of the 92.5 that is not directly Delaware, Midland, D&C, probably $20 million of that is truly nonrecurring. So if you want to say, next year, it’s 72.5 versus 92.5% this year, I think that’s directionally close.

Robert Anderson

But also there’s a piece of non drilling in your 92.5 right. So take that out because it’s sort of a — I mean, we have some identified and some view of what’s happening on our non-op development program, which is truly optional for us. We don’t have to spend that capital. We can go nonconsent on AFEs or we could sell them. So back that out as well and your $30 million, $40 million, $50 million of sort of recurring infrastructure or non-D&C?

Subhasish Chandra

Got it. Okay. And I guess, to the point on your non-op and tying that to maybe some of the service costs, I’m not sure if it’s deflation, as you said. But the Permian has been in a bubble. Do you think some of this looseness is Permian specific? Or do you think it’s just some of that sort of dry gas stuff that’s making its way to the Permian? What are you sort of seeing in the non-op activity?

Robert Anderson

I don’t know that, that has really any bearing on the non activity being more or less if that’s kind of where you’re going with it or whether it’s deflation or costs coming down or what have you. But it’s definitely – we’re seeing some equipment move around a little bit, and we’re seeing service companies talk about spending more time in oily basins from gassy basins, and they’re trying to keep all their people employed and all their equipment working, right? So it makes sense that some of that is going to filter its way to the Permian.

Subhasish Chandra

Okay. Yes, Robert, I guess, right. And how much do you think it’s Permian-specific activity levels dropping?

Robert Anderson

Well, there’s some of that. As private guys have sold to public companies and you’ve seen this multiple times over the last maybe 12 months, but at least the last 9 months, the privates are running multiple rigs and the public buys it, and he’s not going to run as many rigs on it. So there’s some of that. My view is if they are high-spec rigs, they’re being picked up by somebody and lower-spec rigs are headed to the yard or laid down.

So there’s – we’re seeing – definitely seeing some of that. We’re seeing some availability of services that probably a year ago, Steve, we weren’t able to get on anybody’s docket for a frac company if we — even if we wanted to for a period of time. But now I think that’s — there’s some alleviation going on in services.

Mark Lumpkin

We’re upgrading some response.

Subhasish Chandra

Thanks for the color.

Operator

Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade

Good afternoon, Robert and hello to the whole Earthstone team there. I’d like to ask a question, actually, you guys to go into more detail on the El Campion project. And a couple of things I’m curious if you’d share is what zones you’re targeting with those six wells? What whether you’re — what the spacing is and whether they’re designed to test kind of inter zone or intra or inter zone spacing. And more generally, my impression is that’s one of the most prolific areas of the Delaware Basin. So this seems it seems like it will be an important pad result for you guys, but do you see it the same way?

Robert Anderson

I absolutely see it the same way. We bought the tightest assets because of — I mean this was really the key driver to it is the inventory and the rock quality there. We’re drilling wells in the first, second, third Bone Spring and Wolfcamp Upper Wolfcamp section. So we’re drilling all of them and we’ve — every one of those zones has produced either on this acreage or directly offsetting it. So it’s not like we’re testing anything new here.

We’re typically four wells per bench or target zone. Sometimes that can be one more or one less. It depends on thickness directly on the location. It could also be whether we got an existing well, we need to back off spacing a touch. But really, the pads are set up and the acreage is set up to do 4 wells quite easily, and that’s what we’re executing on.

Charles Meade

Thank you, Robert. That’s it for me.

Robert Anderson

Thanks, Charles.

Operator

Our next question comes from the line of Jordan Stewart with Golden Tree. Please proceed with your question.

Jordan Stewart

Hey, guys. Thanks for taking the question. I guess, first, just looking at the hedge book, it looks like you guys didn’t really layer on any incremental hedges. Curious to get your latest thoughts on the strategy would have expected potentially layering some in after the OPEC cut, but how should we be thinking about the hedge book going forward? And when do you start layering in hedges in ’24? And to the extent you could discuss the structure of those hedges?

Robert Anderson

Sure, Jordan. I’m happy to take that. First, let me just start with sort of where we were at the beginning of this year or around the end of next year. We were about 40% hedged on both oil and gas. And I would expect by the time we get into January, we’re probably somewhere close on both oil and gas. We did actually layer in some 2024 volumes right after the OPEC announcement. I think that was 3 weeks ago. If you see, there’s 2 100 barrels a day of collars that we added actually second half of 2023 through full year 2024. That’s our sort of start on the 2024 program. I would expect by the time we talk again in August, we’ll have leverage some more hedges on.

I want to say last year, August, we were probably 15% to 20% hedged for 2023. And I’m not committing to be in 20% in August, but I do think you’d expect to see us having layered on some more hedges by then. We have employed a variety of structures that give us downside protection but also some upside. We’ve done some puts in some cases in the past, we did collars and prices fell and we converted the callers into puts. In some cases, we’ve bought put to it’s probably been close to a year since we did that. And then we’ve done swaps as well. I think you can expect us to see us a mix of that going forward.

On the gas side, it’s a little bit situational. Last year, you could get such big upside on a color. We did almost exclusively callers are probably the back — probably the last 12 months from now. And that sort of optionality isn’t quite the same as it was. So I’m not sure that we’ll do swaps or collars there. But we are cognizant that the year is passing by, and we tend to like to chip away. We do tend to put some volumes on when we see a jump like we did a few weeks ago. And again, we’d expect that every quarter, we’re adding some hedges for next year. I mean candidly, we patent really planned on adding any more 2023 hedges. But when prices jump like they did, we went ahead and added some oil hydros for the second half of this year as well, which actually helped the price into ’24 as we got the benefit of the higher second half of ’24 – ’23 applied toward kind of the full year trade, if you will.

Jordan Stewart

Great. And you mentioned at the top, hey, at the start of the year, you were 40% hedged the ultimate goal starting August working through the end of the year to get back to that level of hedging? Or how do you think about ultimately where you want to be?

Robert Anderson

Yes. I mean I wouldn’t say we’re rigid on that. And certainly, like things could evolve. But I think that’s a generally fair way to think of kind of our strategy and intentions. And I think everyone in this room would be pretty surprised if we were significantly more significantly less hedged than about 40% by the time we get into next year.

Jordan Stewart

Great. That’s helpful. One more for me. You made a comment on the Q2 production being the weakest in the year and the oil cut being below is just high level, is that going to be like a single-digit quarter-over-quarter decline? Or just helping us quantify a little bit more that cadence change and the oil kind of change would be really helpful.

Robert Anderson

Yes, absolutely. So first of all, that is largely driven by our activity in the Delaware Basin. And if you look at our daily production, it almost seems like the data production new when we went from March 31 to April 1 because right around there, we had a pretty big step change downward in production, and that is more oily. That’s all related to our frac schedule and timing of having to shut some wells in just the timing of turning lines.

And that’s going really exactly as planned. I mean, I’ll tell you like right now, I think we’re probably 5,000 barrels a day lower oil production in April than we were during the first quarter. That’s completely in line with our expectation. April should be the low month. We’ll start to see some volumes pick up as some other wells come online in some of the wells that were shut in to return to production.

Like if you made me guess, our guidance is $100 is the midpoint, plus or minus 4,000 a day. We are obviously at the top end of that for the first quarter. I still think that we’ve got a good shot at beating the for the day 100 a day for the year. But I would guess like the very best cases were 100 barrels a day and, call it, 42% or 43% oil for 2Q. And it may be a little bit lower than that or it could be a little higher, but there’s definitely a significant step down that we’re going to see.

And I don’t know that we’re going to hit the same production levels we hit in the first quarter in 3Q or 4Q. I mean we’ve got a chance of that for sure. But directionally, there’s a step change down like almost April 1 that you’ll see in this quarter’s results, but we do expect that to — from basically now through the end of the quarter, start ticking up and get somewhere probably and get north of 100 — south of $104 million for the second half of the year…

Jordan Stewart

Cool. That’s helpful. And then last one for me. I know LOE definitely is elevated this quarter. You said you’re working towards kind of getting back into that guidance range. Should we expect that to kind of manifest throughout the year and really materialize in the back half and Q2 should be pretty similar to Q1? Or maybe any more detail there would be helpful.

Robert Anderson

Sure. Let me maybe try to answer that one, too. Like from a guidance standpoint, Obviously, we didn’t put out a number, 825 to 9 for the year and think we’re going to be at 940 and change the first quarter. That was high and Steve talked to some of those reasons and like we’re seeing things that we can improve. I’m not necessarily expecting a step change in the second quarter. I mean some of the same underlying challenges were there, and they’re not going to like disappear overnight.

So like I think our hope is that we’re back to where we’re still within the range for the full year by the end of the year. But it’s not like we’re going to hit $8 a barrel in 2Q and all of a sudden, we’re back in the middle of the range. Like hey, probably, honestly, a really good goal would be if we were below 9% for the 2Q.

And I don’t know that that’s going to happen. I think that’s possibly a stretch goal. But we also don’t feel like there’s no chance that we’re going to end up within the range for the full year. But really, like practically speaking, we’re going to be shooting just to get under 9 for the full year, and that’s not going to happen in 2Q.

Jordan Stewart

Great. That’s really helpful color. Thanks, guys.

Operator

[Operator Instructions] Our next question comes from the line of Jeff Robertson with Water Tower Research. Please proceed with your question.

Jeff Robertson

Thank you. A question, Robert, on equipment. I think you all inherited 3 rigs in the Delaware Basin from the prior operators. Do you have an opportunity or a need to upgrade any of the rigs you have with maybe some of the equipment that’s moving into the Permian Basin?

Robert Anderson

Yes, Jeff, just let me remind you a little bit when we took over Chisholm, February of ’22, we inherited 2 rigs. And then we took over this [ph] They had three rigs running in total between Delaware Texas and New Mexico. And we inherited 0 rigs from them because they weren’t running any at the time.

So we picked up a separate rig, just so we could have 3 running in New Mexico, and they scattered out, right? They’re not necessarily on all this at one time or all in the same area at one time or even all in tightest at one time.

We did change out one of our rigs last fall and went to a higher spec rigs. So we were sort of ahead of the market at just making some efficiency moves last fall. So we feel really good with what we’ve got going right now in terms of our rigs and their quality.

Jeff Robertson

Just a question on managing the business, Robert, maybe this ties in with some of the production cadence that you all will experience in 2023. How does the scale of the company today impact the — maybe the willingness to tie up capital on bigger sized pads for a longer period of time. And therefore, your production is create some lumpiness from that?

Robert Anderson

Yes. And every — the life cycle of your business, when we were smaller and we tied up capital for 6 wells, it made a difference and it was really lumpy. If you went back and looked at some of our 2019, for instance, quarterly production numbers and how we were drilling wells and all that.

Today, much bigger, much more resilient, lower decline base production, sure does help and allows us to go develop like we’re doing at the Stateline area of Texas and New Mexico, a much larger capital investment before wells start coming back online. So we have that ability now. And if a pad of 3 or 4 wells is a week or two late, it probably doesn’t have that much impact on our overall production guidance or performance, right? So scale does matter and things like that as well as a whole lot of other things we could talk about all day long in terms of being a bigger company.

Jeff Robertson

Thank you.

Robert Anderson

Thanks a lot.

Clay Jeansonne

Operator, we appreciate everybody’s interest today, and we will be looking forward to speaking with you again after the end of the second quarter. Everybody, have a great day. Thanks.

Operator

And this concludes today’s conference, and you may disconnect your lines at this time. Thank you for your participation.