Earthstone Energy, Inc. (NYSE:ESTE) Q2 2023 Earnings Call Transcript

Earthstone Energy, Inc. (NYSE:ESTE) Q2 2023 Earnings Call Transcript August 3, 2023

Operator: Good afternoon, and welcome to the Earthstone Energy’s Second Quarter 2023 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. 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 second 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 June 30, 2023, and the second 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, August 3, 2023. Therefore, any time-sensitive information may no longer be accurate at the time of any replay listening or transcript reading. 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 good afternoon, everyone. Thank you for taking time to join us on what has been probably a very busy day for you all. Earthstone’s operational excellence continued during the second quarter, with production setting record levels for the company. We reported second quarter production over 105,000 BOE per day, with the oil component of our second quarter production over 44,000 barrels per day. We have now had three quarters in a row with production approaching or exceeding 105,000 BOE per day. This record level of production volume has us now tracking well above our original stand-alone full year guidance. Our low decline, stable production base and strong new well results drove our production outperformance for the quarter.

This record-setting production level once again continues to showcase the quality and productivity of our inventory, and the strength of our underlying asset base. Steve will highlight several wells that drove our strong quarterly outperformance here in. The execution of our disciplined operating plan and the strength of our operational performance translated directly into strong quarterly financial performance, culminating in approximately $239 million of adjusted EBITDAX and about $42 million of free cash flow for the quarter. Over the past few years, we strategically positioned the company as a significant operator in the Permian Basin with more than $2.5 billion of acquisitions completed. A key piece of our strategy has been the initial entrance into the Northern Delaware Basin in February of 2022 through the acquisition of Chisholm and the addition to that position with the acquisition of Titus last August.

For the past 12 months, we have been searching for the next complementary asset acquisition to our New Mexico deals, while we integrated and executed on our development plan. This quarter’s results really show what we can do with these assets. Our recent announcement and pending close of the Novo acquisition supplements this strategy with our asset base shifting further to focus on the prolific Northern Delaware Basin to which the large majority of our capital activity will be dedicated going forward. With four of our five rigs focused on the Northern Delaware Basin, we expect to see continued improvement in capital efficiency. We believe the Novo transaction has all the right qualities to add significant shareholder value for Earthstone and all of our stakeholders.

I just want to spend a few minutes highlighting several of those qualities. First, we are high-grading and deepening our portfolio of future inventory in the premier Northern Delaware Basin. Noble adds 200 high-return derisked low breakeven oily drilling locations, Upon closing, we will hold over 1,000 future drilling locations with approximately twp-thirds of those in the highly economic Lea and Eddy counties of New Mexico. We currently estimate an inventory life of approximately 13 years at our current rig base providing years of high-quality drilling inventory and future profitable growth for Erste. Second, Novo significantly enhances our scale and operational synergies. We estimate fourth quarter production in the range of 130,000 to 135,000 BOE per day.

This represents an increase of nearly 30% growth compared to our second quarter reported volumes. This production level will propel us into being one of the top producers in the Permian mid-cap group. The proximity of this asset to our existing assets should allow for synergies with a constant focus on operating efficiencies and costs. Third, Novo increases our financial scale. Looking into 2024, the Novo transaction will meaningfully increase Earthstone’s financial scale through higher EBITDAX, but perhaps even more so a significant expected increase in our free cash flow generation as we intend to maintain our five-rig drilling program. We expect free cash flow to increase by more than 60% in 2024 as compared to our Earthstone standalone plan before we agreed to acquire Novo.

Fourth, we will maintain our financial strength and low leverage profile. Even though we will finance the transaction with all cash, and we will not issue equity, we will not sacrifice the balance sheet. As stated when we announced the acquisition, in the fourth quarter being the first full quarter with Novo, we expect to meet a forecasted 1.1x leverage ratio based on the last quarter annualized adjusted EBITDAX, and we expect to further deleverage to below onetime debt to adjusted EBITDAX in 2024. And finally, we will create a stronger, more resilient Earthstone. The Novo transaction will meaningfully strengthen our operational and financial base. We will have over 223,000 net acres in the Permian Basin with proved reserves of 460 million barrels of oil equivalent.

Upon closing, we will have a production profile of over 130,000 BOE per day and an inventory of over 1,000 locations, representing approximately 13 years of drilling inventory at our current five rig pace. All of these factors lead to generating significant free cash flow loan growth making Earthstone stronger and more resilient. Given the profile of the Novo transaction, we strongly believe this is a value-creating transaction for Earthstone. We will continue to focus on the small things that make a difference in our business as well. For instance, we have divested over $100 million of non-core assets in the past year, including more than $50 million in the second quarter of this year. This continued housekeeping will improve our margins and streamline our operations.

Lastly, I want to highlight our inaugural sustainability report, which was published last week, and can be found on our website. We are committed to providing ESG-related information and metrics to our shareholders and other stakeholders. With that, I’ll turn the call over to Steve to provide an update on our operations.

Steve Collins: Thanks, Robert. Good afternoon, everyone. As you can see from our second quarter results, it was another outstanding quarter for the operations group. We maintained our rig count at five during the quarter with three in the Delaware Basin and two in the Midland Basin, allowing us to spud a total of 21 gross wells and 16.9 net wells and put on production a total of 17 gross, 12.5 net operated wells. As Robert mentioned, our operations team continued bringing some great wells online. We have shown the areas and results of these wells on Page 11 of our updated corporate presentation, which is available on our website. Our earnings release highlights a couple of pads that we recently brought online in both the Delaware Basin and the Midland Basin.

I’ll give a high-level summary of those results. In the Delaware Basin, we brought online two pads both in the state line area, which average — with an average IP 30 of approximately 1,800 Boe per day on one pad and 1,900 Boe per day on the other pad. In the Midland Basin, we brought online a pad a few weeks ago in Irion County, with the IP 20 was over 1,000 Boe per day and around 86% oil. We also brought online two Wolfcamp D wells in the Midland County in mid-July that are still flowing naturally, but are looking good with average daily production over 800 Boe per day and close to 90% oil on a Boe basis. As we mentioned the Novo announcement, we will be transitioning from a rig from our Midland Basin acreage to the Novo acreage and shutting down the rig that Novo is operating.

Novo should finish drilling in August, and we expect to move one of our Midland rigs in September to the Novo asset. At Earthstone, we take pride in increasing value by improving the operations of our acquired assets. Given that mindset, we remain highly focused on overall operating expenses. We made significant progress on reducing LOE during the quarter, lowering LOE per Boe by $0.23 versus the first quarter. This was achieved through lower costs for repairs, maintenance and chemicals during the quarter, partially offset by higher gathering, processing and transportation costs and slightly higher work over expenses. We will continue to focus on reducing our LOE per Boe, and I can assure you that our entire team is working through their specific areas of responsibilities to achieve this goal.

We are starting to see some good news on the service cost front. Rig rates have shown signs of softening, and we are beginning to benefit as our rig contracts are renewed. Over the past month, we renewed contracts on two of our five rigs and negotiated price reductions of 10% to 15% and we expect that trend to continue as our remaining three rig contracts roll over in the next two months. We also see a softening for cementing services, pressure pumping and the cost of production casing and tubing. We are cautiously optimistic that we have seen the high point on service costs. We won’t see those flow through our results in any material way in the current quarter and don’t expect to see the full impact of those reductions until 2024. I want to provide a little color on the cadence of our expected well counts for the next few quarters.

For the third quarter, we expect to spud 24 gross wells or 18.1 net wells and 17 gross wells or 14 net wells put on production. And for the fourth quarter, we expect to spud 24 gross wells or 16.7 net wells and 30 gross wells or 22.9 net wells put on production. With that, I’ll turn it over to Mark.

Mark Lumpkin: Thank you, Steve. As usual, I’ll focus my comments today on providing some additional details on some meaningful metrics and key highlights, but I would want to remind you that a detailed breakdown of our results is available in our earnings release and in our 10-Q. So let me start with some have financial results. Adjusted net income for the second quarter was $76 million or $0.53 per share. Adjusted EBITDAX was $239 million, and free cash flow was $42 million all driven, as Robert mentioned, by record levels of daily production. Now let me take a minute to walk you through our debt and cash balances as of quarter end, which incorporates several significant transactions during the quarter. At June 30, we reported having slightly over $1 billion of debt, which is comprised entirely of two tranches of senior unsecured notes.

We had no borrowings on our credit facility, and we had approximately $50 million in cash at quarter end. These debt and cash balances are inclusive of our having paid a $75 million deposit toward the Novo acquisition, having issued $500 million face amount of new senior unsecured notes and having received over $50 million in net proceeds from selling noncore assets. From a leverage standpoint for the quarter, we posted an LTM leverage ratio of 0.8 times. We do expect the Novo transaction to close on August 15, and we estimate a downward purchase price adjustment of approximately $100 million to $120 million. Upon closing and incorporating the estimated purchase price adjustment in our July 31 debt and cash balances, we expect to have net debt of roughly $1.8 billion or perhaps a little bit lower than that.

We have with this all laid out on Page 25 of our new investor deck that was published on our website yesterday. After closing on Novo, we do intend to utilize significant free cash flow to pay down borrowings under our credit facility in the near term. Also upon closing the Novo transaction, the elected commitments on our credit facility will increase to $1.75 billion, which should leave us with close to $1 billion of undrawn credit facility capacity. From a production standpoint, our second quarter results really were fantastic because we had record average daily production of over 15,000 BOE per day, and that was comprised of 42% oil, 32% natural gas and 26% natural gas liquids. As you know, this significantly exceeded our forecast in both our full year production guidance and our informal second quarter production guidance and really was driven largely by better-than-forecasted well performance which really applies both to new wells that came online during the quarter, during the first quarter, but also to PDP in general.

Our year-to-date average daily production of 105,000 BOE per day has exceeded the top end of our 2023 production guidance. Last August, if you recall, we closed on the Titus acquisition, which similar to Novo had significant flush production, and we did anticipate the time seeing some decrease in our daily production rate in 2023 relative to the fourth quarter of last year. Given the lower combined rig count post close and on Titus. As we sit here today, we’ve now reported three full quarters that’s closing on Titus, and we’ve essentially held production flat right around 105,000 BOE per day which again includes the record production for the second quarter. And I would just point you to page five of our IR deck where we’ve laid this out of what our guidance has been on production over the past six quarters and what actual results were.

And you can see how we’ve been able to maintain the 105,000 BOE per day since closing on Titus. This is really a — this is really attributable to both the quality of our asset base and our efficient operations, and we’re really pleased that this is working out as well it is, and we’re able to hold production at those levels. We’re looking forward to closing on the Novo acquisition in the next couple of weeks, which really continues our pathway of high grading our asset base, which, as you know, is now largely focused on the Northern Delaware Basin. Full details of our updated guidance is in our earnings release. and investor presentation, but I did want to provide some color today on production and CapEx guidance in particular. Including and assumed closing date for Novo of August 15th, we’re guiding towards third quarter production of 115,000 to 120,000 Boe per day in to fourth quarter production of between 130,000 and 135,000 Boe per day, both 41% oil.

Given Novo’s flush production profile, we do expect some decline in production as we head into 2024, relative to the fourth quarter of this year and we do expect production will fall below 130,000 Boe per day, which is the low end of our fourth quarter guidance range. We’re not really in a position to get much more granular than that, but we do expect after some initial decline in production in the first half of next year, that pressure will flatten out during 2024, especially on the oil side. Moving on to our CapEx guidance. We invested $174 million in the second quarter, which is a little bit lower than anticipated, and I’m pleased that we’re tracking well on CapEx. As you can probably see from the math, we’re right at $375 million of CapEx spent year-to-date.

So, that’s exactly 50% of our midpoint, $750 million guidance range from the beginning of the year, which we are maintaining here. During the second quarter, we did spend a little bit less on infrastructure. Some of that will shift in the third quarter. But net-net, we still expect to invest between $725 million and $775 million for the full year, as we previously guided are reaffirming now. And we also expect this to be a little bit more weighted towards the third quarter versus the fourth quarter, something like a split if you’re assuming the midpoint of $375 million would be roughly $200 million in the third quarter and $175 million in the fourth quarter, partially related to some completion activity we’re picking up in progress from Novo upon closing here.

I would say all things considered. We feel really good about the CapEx plan. And it looks like we’re going to complete three to four more net wells by the end of the year than we had previously planned, and we’re going to be able to do that within the same capital budget — so we feel like that’s a very positive element of how things are going from an operational and spending standpoint. Taking a sneak peek into 2024 and assuming the same five rig program throughout the year, we do expect that full year capital expenditure should be a little bit lower than 2023 and we’re starting to see some of these service price reductions come into play. As Steve mentioned, most of those won’t really hit until 2024 and even some of benefits we’ve got contracts run through about the first quarter.

So, we’ll see continued decreases in the service costs throughout the year — throughout the remainder of this year and really into the first half of 2024, based on what we can see and think right now. Let me turn to the expense side before I wrap it up and hand things over to Robert. From an LOE standpoint, as Steve mentioned, the $9.13 per Boe for the quarter was a $0.23 per Boe improvement over the first quarter. And as Steve mentioned, his team is working hard to optimize LOE costs, including, as we incorporate the Nova assets into Earthstone. We did put some guidance for the second half of $8.75 to $9.25 per Boe and really would expect that to be a little bit higher in 3Q and a little bit lower in 4Q. From a cash G&A perspective, we incurred about $12 million of expenses in the second quarter, which brings us to $25 million year-to-date, which is when you annualize it at the bottom end of our prior $50 million to $55 million for the year range, and it represents the cost on a per Boe basis of $1.27, which compares very favorably to our peers.

With that, I’ll turn it back over to Rob for closing comments.

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Q&A Session

Robert Anderson: Thanks Mark. We believe we have transformed Earthstone into 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 pro forma valuation that is significantly below our total proved reserve value which stands at $5.4 billion, which is $1.4 billion higher than our pro forma 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 our shareholders. We will continue to work diligently to ensure that the long-term value we’ve created for our shareholders is ultimately recognized. With that, I’d like to now turn it back over to the operator for any questions.

Operator: Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first questions come from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold: Yes. Thanks. Good afternoon. I was wondering if you could give us a little color behind those 1,000 wells you have in terms of like what is the lateral length of those? And as you bring all these assets together and continue to kind of look at opportunities to enhance efficiencies and returns over time, how much opportunity is there to extend those laterals to like swaps, Bolt-Ons or obviously, tactical kind of M&A?

A – Robert Anderson: Scott, Thanks. Good question. I’m going to really generalize here. But what we put in probably at the beginning of the year in terms of our guidance and footages there, which are a little bit longer in the Midland Basin and a little bit shorter in New Mexico. So we’ll go 9,500 to 9,000 feet for the two different areas, probably stands about the same. Most of the Novo wells, 7,500 to 10,000-foot laterals. So we’re going to fall into that bucket again. So that’s the first half of your question, so it’s about the same. And we can probably come up with a little bit more granularity there, if it would be helpful for you. Secondarily, the ability to extend laterals is — continues to get tougher and tougher as offset operators develop their asset, and we develop ours.

We will look to make trades. There could be some opportunities remaining in our Chisholm acreage, along with some of the tightest acreage and perhaps even in this Novo where we can do some trading around acreage and maybe improve some lateral lengths and increase efficiencies, things like that. But for the most part, I’d say we have what we have and our job now is to go out and find bits of acreage where we can go develop smaller units, but still very economic.

Scott Hanold: Understood. Thanks for that. And maybe a little bit of context around what you’re doing on the cash OpEx. I mean it seems like it’s been a bit stubborn in terms of trying to work it down. Can you give some context of some of the efforts you’re putting in place to see that drop. And I think the Novo’s assets do have a lower LOE. So it will probably mix it down, but just on the base assets, just things that have been a little bit stubborn and what you’re doing to kind of make improvements there?

A – Robert Anderson: Well, from a high level, and then I can let Steve dive into the details. It is stubborn because you have some things that are contracted like compression, for instance. And all our compression contracts, for the most part, were up at the beginning of the year, and I can tell you they didn’t go down. They went all went up. And labor is a fixed cost. So whether it’s our guys or labor that we use in the field, that’s not going down. So where we use that labor, including our own team, we’re continuing to see some increases there and will continue to see increases over the year. I’ll let Steve address the things that we have done and where we are seeing some savings.

Steve Collins: We worked hard to renegotiate sand contracts, workover rigs, like Robert said, compression and field labor stay about the same or increase. Part of that is left over from the supply problems back from COVID. But we worked hard on chemicals field, not our field labor, but contract field labor and workover rigs, and we’re balancing out by working hard to get those down.

Mark Lumpkin: Hey, Scott, one thing I would just add, this is Mark speaking too. We don’t report GP&T separately from LOE. So it is embedded in LOE. And as we do our internal benchmarking against our peers, like that’s one apples to oranges pieces because a lot of folks don’t include that in their LOE. And I’ll say that was another piece earlier this year caused us a little bit by surprise because a lot of these GP&T contracts have inflation, escalators relative to CPI. I mean, I want to say like on that basis alone, the first quarter increased our LOE by $0.20 per BOE relative to the model. Like that’s sticky. That’s not going away. That’s just the reality of the inflation linked to the contract. But it does sometimes when you’re comparing across peers, if you don’t include that or some folks might even have part of that embedded in their revenues. It is a bit of a non-apples-to-apples basis.

Robert Anderson: I’ll end on — you’re right, Novo probably will help us out a bit. But I guarantee that Steve and his team will continue to look for other opportunities to reduce costs. And when you look at it on an all-in cash cost basis, our G&A per BOE continues to be working in the right direction and down, and we will continue to work hard to lower our fixed cost side of our business.

Scott Hanold: All right. I appreciate the context from all you. Thank you.

Operator: Thank you. Our next questions come from the line of Neal Dingmann with Truist Securities. Please proceed with your question.

Neal Dingmann: Thanks for the time. Maybe, Robert, a little bit on to the last question you were just talking about. My question is kind of two-fold here. You mentioned about possible divestures. And if you’re successful with divestitures, I just wonder how much you think that might be. Combine that with what it sounds like you can certainly, with all the new properties and the new scale, get well-product — improved well productivity, all this leads us to believe certainly could be under, if not even before, by mid next year, one-time, would you and Mark think about it might be too early to talk about, but where are you thinking about shareholder return, you’re starting to get well under one-time at that point.

Robert Anderson: Okay. Neal, you asked a lot of questions in there. I’ll start from the backwards and shareholder returns. It’s on our mind. I don’t think anything’s changed. You got it right. We get under one-time, we get our revolver paid down to some amount next year, and we start thinking about what we can do on the shareholder return front, and we haven’t given up on continuing to evaluate different opportunities or options for that. But again, like we’ve said in the past, we will focus on creating value. And if we see the right opportunity come our way, we’ll figure out a way to make it work and acquire more assets as it makes sense, and we’ll try and see if we can balance that with shareholder returns at some point.

Neal Dingmann: Okay. And then just maybe a quick one for — the second part of that, just on divestitures, what’s — how sizable can those be?

Mark Lumpkin: Probably not too much different than what we’ve already done. In total, over the next 12 to 18 months, it’s another $100 million perhaps. Maybe it’s a little bit more. Oil prices continue to go up, maybe that helps us out a bit. It’s not sizable, but are things that would streamline our operations for sure. And we don’t know if we’re going to be successful in selling assets, but we’ll sell what makes sense to sell.

Neal Dingmann: Got it. And then maybe a quick one for you or Steve. Just very noticeable on those top two wells, I appreciate you kind of have that slide that list all the wells and some of your top wells and both in that sort of portion of Eddy County. Again, what’s the plan to drill in that area? And is there anything unique about those two wells?

Mark Lumpkin: Nothing unique. We’ve got lots of wells like that. We love all those wells equally. I think we’re going to finish up some drilling on that Stateline area, later this month, next month, something like that, and we’ll be completing some wells probably in the late third quarter, fourth quarter and bringing on another, I can’t remember exactly that’s three wells or four wells, something like that…

Steve Collins: Four wells in the quarter

Mark Lumpkin: Four wells would be at the end of the quarter, will get started. So we’ve got some more lined up. And then we’ve got probably, hopefully some — a few other surprises in Lea County as we complete wells there that we’re working on now.

Neal Dingmann: I would like your surprises. Thanks guys.

Operator: Thank you. Our next questions come from the line of Subash Chandra with the Benchmark Company. Please proceed with your questions.

Subash Chandra: Thanks. Hi, Robert. Question on — now that you’re here, right, whatever here is 135,000 BOE product. Are you thinking any differently about building the business and running the business, for instance, like the Wolfcamp D, is there going to be more for lack of a better term, exploration and what you do more of a focus on maintaining or increasing the inventory count versus PDP type transactions, things of that nature?

Robert Anderson: Yes. Subash, we are now definitely more focused on inventory than straight PDP and it all depends on what the seller has. I mean we’ve looked at deals where there’s still outsized PDP component compared to inventory, but it’s got really good inventory. So we spend time looking at that and see how it fit in our development plans and portfolio. But we are even like the Wolfcamp D, there’s a whole bunch of other zones out there we can talk about, those aren’t exploration, and we’re not an exploration company. We’ll take low risk development opportunities and go exploit those that make sense in our development plan. The Wolfcamp D is like that, the Jo Mill and it places the loader Spraberry is the same in the Midland side of the basin and then you get into New Mexico and there’s the Avalon and deeper benches in the Wolfcamp and shallower benches above the Avalon.

All those things are proven in certain areas. And then we’ve got good geologic reasons to believe they’re going to work in other areas where we have drilled them. So we’re excited to add those kind of locations into our portfolio, but we’re not going to go out there and explore for 25,000-foot vertical wells to see the next gas play or something like that. That’s not our game.

Subash Chandra: Got it. And do you have any sort of theories or ways that you want to tackle the disconnect between your multiple and now what’s size, the fact you have a pan Permian presence, some of the, I guess, old excuses have gone by the wayside as why your multiple is what it is. But how do you think internally about tackling that deficit and getting something closer to PDP value?

Robert Anderson: Yeah. That is a great question, and we wrestle with it probably every day. And the one thing that we can do is we can continue to perform. And we just did another deal or in the process of closing another deal. So I think folks need to see that we’ve done another good transaction, and I believe they will. The results are pretty impressive on that acreage position. And I’m confident that our team can operate it and maybe even shave off some costs. We’re starting to see some good efficiencies and efficiencies that are sticky. They’re staying with us — and I think as we continue to show those results, investors will take notice and probably can’t avoid taking a hard look at Earthstone. We do have some larger inside ownership with EnCap and Post.

They are sticky investors. And then we’ve got other investors who have hold large positions that over time, they’ll probably sell off some of their shares, and that will be great for trading volume and liquidity and allow folks to get in our stock at the appropriate time. So we work really hard every day to prove to the market that we bought good assets and we can execute on those.

Subash Chander: Terrific. Sounds like a plan. Thank you.

Robert Anderson: Thanks, Shubash

Operator: Thank you. Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Charles Meade : Good afternoon, Robert and Steve Mark and the rest of the Earthstone Crew. Mark, going back to your comments, I want to see if I understood correctly, it sounded to me like you were attributing most of the I guess the beat or most of the outperformance versus your plan was coming from the Tides assets. And if that’s the right understanding, are there some reasons that you would point us to for why that’s not going to continue?

Robert Anderson: Yes. So that’s a few questions. Those are great questions, and I know I spent a bunch at once, and I was — as I was sitting here a lot on how long we’re going I was wondering how we can start in the next time. But thinking about Titus, I wasn’t really attributing our ability to hold production flat for the past three quarters at 105 a day two ties. That’s just the timing of the benchmark. And that was the first time in 7 quarters we didn’t do a new acquisition. So we’ve now actually had three full quarters with no acquisitions. So since then, we’ve held production flat at 105. I mean, back then, our model was, if I’m thinking about this right, our guidance for 4Q last year was 98,000 to 102,00 million BOE per day, and we came in at almost 105,000.

And then candidly, we — our midpoint of the guidance, pre-NoVO is 100 a day this year. our model was lower than the $104 million something that we did in the first quarter and certainly lower than the $105 million we just did this quarter. It’s not related to Titus per se. I would say really, it’s related to capital efficiency and being able to turn drilling and completion dollars into better wells than we had anticipated. And then I would say on top of that, the PEP has declined less like thinking specifically about the second quarter, and we had this call in May, I was pretty darn nervous about EBIT 100 a day. And as I told you, we had just shut in a bunch of stuff in Lea County that was heavy oil and like — literally overnight lost 4,000 barrels a day of oil.

The BOE is higher than that. And really, what’s happened is that hit like it was. We had downtime that was higher than normal in 2Q, and it came out almost exactly like we expected. So we started looking at, well, hey, how are we 105 a day and really kind of the same oil content that we had expected. It is a function of two things. I mean some of the early wells, but not every single well, but on average, our early well results are better than what our model has been. And then secondly, even just looking at the PDP. The PDP decline rate on call it wells that were online by year end or maybe even like by late first quarter, they didn’t decline as much as we had forecasted. So net-net, we do probably have some conservatism around some of the forecasting as it relates to type curves, but we’re really encouraged that they’re doing better than we expected.

It’s not really just the tightest assets. I mean, they certainly are a part of it. I would say that Delaware, generally speaking has just looked better than what we modeled. And it’s a little bit — we’re sitting here telling you that the fourth quarter is going to be 130, 135 a day. And we think that’s pretty reasonable. We’re also telling you it’s going to drop next year. I recognize that we told you that last year, it never actually dropped. So you might think we’re being too conservative. We don’t think we’re being too conservative. I mean, if that turns out to be the case, fantastic, but we’re adjusting real time as we’re seeing some things outperform relative to prior expectations.

Charles Meade: That is a helpful elaboration, Mark. Thank you for that. And then my follow-up, and perhaps this is for Robert or Steve, I’m curious about the Wolfcamp D results. And there’s two things that are — at least two things that are notable to me. But I wonder if you could just give us a bigger context. One, it’s a high oil cut, at least we don’t have a lot of Wolfcamp D results to look at in the industry, but my recollection, that’s a higher oil cut than what we’ve seen from some other results in Midland County. And then the second piece, if you could kind of put into context the rate, which isn’t a — it doesn’t seem like a bar and burner rate to just on the face of it, but that — it’s not an artificial lift and maybe — what — and I recognize you want to keep them off you’d like to have it flow naturally. But at some point, when you put it on artificial lift, where might that rate go?

Robert Anderson: Okay. Let me start by giving you just a little bit of info on the Wolfcamp D. So — if you’ll recall, our first deal in the basin, we bought Lynden Energy private — a public company that operated by CrownQuest. We participated with CrownQuest and Wolfcamp D wells, primarily in Howard County. This was several years ago, really good results. Since then, CrownQuest has drilled a lot of Wolfcamp D wells both in Midland County and on the Midland Glasscock County Line. And so this was an easy initial development for us being in the right area. We’ve since seen good Wolfcamp D development for initial development in Reagan and Upton Counties. And some of it has been there for a while, a very large operator in the basin, drilled a three-well Wolfcamp D pad in Reagan County several years ago.

And now there’s been some privates both in Upton and Reagan who have developed the D. So we see it in lots of places. We’re going to continue to watch what these private operators’ results will be in these 2 areas up in an rated, and we see that as an opportunity to add some additional development for us in the Wolfcamp B — it’s just at this point, ours haven’t been on long enough to see meaningful amounts of gas. We’re not exactly sure where that’s going to head on this block of acreage. But we’ve got plenty of data to compare this versus other Wolfcamp D developments, and we’re pretty pleased. Steve, you can talk about the artificial lift side of it and what happens when we go on lift. I think it’s going up, but…

Steven Collins: Yes, it’s going up, I can’t tell you how much. It’s going to go up and the pumps are going to be big enough to handle quite a bit of fluid. Those pumps are ready to go. We started out about 2,000 pounds of flowing pressure here, and we’re down to about $750 million — so they’re coming close. I’m going to think that in the next 3 or 4 weeks, we’ll be — all it’s got to do a stumble a little bit if it heads 3 times, I wouldn’t a pump in it. So we’re ready to go. I had that conversation before I walked in here. But yes, it’s high oil cut, but that’s also good because those ASPs are going to be even that more efficient. So I’m looking forward to doing it.

Q – Charles Meade: Right. Well, I’ll stay tuned on that. It will be interesting. Thanks for the details.

Steven Collins: Thanks, Charles.

Operator: Our next questions come from the line of Michael Scialla with Stephens. Please proceed with your questions.

Michael Scialla: Robert, you said you plan to stay at the 5-rig program for next year. And Mark, you said that you expect production to decline in the first half from fourth quarter level than plateau, I guess, in the second half. And it sounds like that would result in less CapEx this year given the lower contracted prices. you’re getting on your rigs and other deflation — do you have a sense of what you’d need to spend to keep production flat? And do you have any desire to do that?

Robert Anderson: I’ll tell you what, Michael, one thing we don’t do is buy these high declining private equity-backed companies and try and keep production at the peak. Novo and Titus are 2 examples of those and great examples, and we don’t mind letting those come down and we’ll fix the right capital plan for us and develop the asset. So like we’ve said, and Mark did a good job after we bought Titus, we let it come down, and we’ve had 3 quarters of 105,000 BOE a day and if we hadn’t done Novo, I think we’ve been pretty consistent in our message that we keep production flat with our rig count at the time and our capital at the time. So I think that stays kind of the same thing here once we get to flush out of the Novo asset.

Michael Scialla: That makes sense. So the 5-rig program seems like operationally where you want to be right now?

Robert Anderson: For now, that’s right. Yes. Works really well to have four rigs for us running in New Mexico.

Michael Scialla: Yes. Okay. And on the Novo acquisition, if it does close here in the next couple of weeks, do you have a sense of what you’re going to do there in terms of the early development. And I know that you had highlighted when you did the acquisition, that Ovation pad — is that going to be kind of a model where you expect to get to with a lot of their acreage. I just want to see how the plan of attack is for the new acreage you’re getting?

Robert Anderson: Yes. I mean you heard Steve, the Novo rig that they got running right now will end — will complete its pad here, finish drilling its pad here sometime later this month, and we’ll move a rig over there so this done drilling a pad and after closing that it’s working on a pad in the Midland Basin. And we’ll develop it the same, but maybe not 22 wells or something all at one time. We’ll probably take smaller bite sizes there and develop anywhere from four to seven or eight wells at a time. It’s still a little bit of a work in progress. And this is a little bit of an art where you’ve got to take a Rubik’s cube and figure out which colors you want to match up and all that. And we’re working through that right now. But it probably won’t be as big as that 22-well project all at once. But larger project sizes are to come on the Novo project.

Michael Scialla: Great. Thank you.

Operator: Thank you. Our next questions come from the line of Noel Parks with Tuohy Brothers. Please proceed with your questions.

Noel Parks: Hi, good afternoon

Robert Anderson: Hey, Noel.

Noel Parks: Just had a couple. One thing, it’s encouraging to hear how you’re making progress on costs and that the vendor costs and so forth have shown some – given your – because it’s really very by base as we’ve been listening to companies during the turning season. So I’m just curious, do you sort of think this is going to be a normal sort of ebb in the sales side — I’m sorry, in the service cycle this time around. And the thing I was sort of wondering about is a lot of the tightness kind of did stem as effective COVID. But also looking forward, with associated gas in the Permian sort of being a bit of a wild card, depending on how oil is doing, just that there is transfer infrastructure challenges heading forward that might serve the store activity a bit. So, just any thoughts here on that would be great.

Robert Anderson: Well, I mean, there is always an ebb and flow, and there always seems to be a delay in cost coming down when prices have come down. And now we’re back up a few bucks and — so do we see some potential for costs just not coming down as fast. I think a little bit of it is supply and demand. There’s rigs that are leaving gassy basins in Haynesville is a good example and coming to the Permian. And so where operators can tell high-grade rigs, but — and maybe it’s at even a little cheaper price than lower quality or poor performing rigs or something like that. So I think it’s going to take some time. The pressure pumping is probably the biggest number that we’re all working really hard on. And if we can get some relief there, I think we’ll feel really good going into 2024.

Noel Parks: Great. And as your efforts in the northern Midland kind of intensified, just curious, what’s the electrical infrastructure situation look like up there? Is it adequate? Is it stressed?

Robert Anderson: Yeah. I think you’re probably talking about the Northern Delaware, right? Not the Northern Midland?

Noel Parks: Sorry, yes, Northern Delaware. Sorry.

Robert Anderson: Yeah. And the good news is there is infrastructure there. It’s not like we’re in no man’s land. And also the good news is we have the ability, based on our portfolio to change our activity and move things around. So when it does get backed up and it does from time-to-time, either on gas or water, we can see that. And we have the ability to move our plan around a little bit. And we’re planning accordingly. So there is some infrastructure. We’re spending some dollars. We’ve talked about it now for six or seven months that some of our capital plan this year is infrastructure. We got pretty aggressive in the timing of getting a lot of things done in the first half of the year. It’s slipping a little bit to the third quarter, but that’s okay.

We’re still ahead of where we need to be in terms of bringing new wells on and not having any infrastructure. So it’s getting better as we spend money up there ourselves and other operators in the midstream guys continue to see the benefit of adding capacity.

Steve Collins: Specifically on the electric side, with Titus and Chisholm, we’ve released almost 50 generators since we took over. So the electricity is coming. And we’re making that happen and that helps the LOE also quite a bit. It’s always there when you start, but we get it there.

Noel Parks: Great. Thanks a lot.

Clay Jeansonne: Operator, it’s the end of the day for a lot of folks. And we are backed up here because we have a business that we’re going to run. So we appreciate all the calls and all the questions. And we look forward to visiting with you next quarter.

Operator: Thank you. That does conclude today’s teleconference. We appreciate your participation. You may disconnect your lines at this time. Enjoy the rest of the day.