Earthstone Energy, Inc. (NYSE:ESTE) Q4 2022 Earnings Call Transcript

Earthstone Energy, Inc. (NYSE:ESTE) Q4 2022 Earnings Call Transcript March 9, 2023

Operator: Good morning, and welcome to Earthstone Energy’s conference call. . 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 now turn the call over to Clay Jeansonne, Director of Investor Relations. Please go ahead.

Clay Jeansonne: Thank you, and welcome to our fourth quarter and full year 2022 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 assurances 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, and the fourth quarter and full year 2022 earnings announcement. 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. 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. March 9, 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 turn the call over to Robert.

Robert Anderson: Thanks, Clay, and good morning, everyone. I appreciate you all taking time to join the call or listen via the web. Over the past few years, even prior to COVID, Earthstone’s board and management team recognize the importance of scale and we have been on a mission to strategically position the company as a significant operator in the Permian Basin, and as you all know, the most prolific and lowest breakeven onshore basin in the United States. We went down a targeted path of identifying, evaluating and executing upon strategic opportunities to grow our business prudently. Our success in these efforts, including during this past year, where we invested over $2 billion directly reflects our outstanding employees’ hard work and perseverance.

I’m also excited about the many opportunities we see that will allow us to continue growing our business for our shareholders’ immediate and long-term benefit. However, to be clear, we are not targeting a particular size or production level, but rather we are focused on creating additional value. I’m exceptionally proud of the company we’ve built over the last few years and the entire team we have assembled, who have been responsible for the success we saw in 2022 and will lead us into the future. Our focused consolidation efforts have materially repositioned the company and provided our shareholders with an investment in a much larger entity, underpinned by a solid asset base with more than 10 years of future drilling locations and a substantial operating footprint in the Permian Basin.

Not only during the fourth quarter but throughout 2022, our team has performed — has outperformed expectations and achieved new company heights. This includes record full year production levels, record adjusted EBITDAX and a generation of over $500 million of free cash flow. The success our team achieved in 2022 was clearly amazing. Earthstone continues to demonstrate that we are a proven acquirer with the ability to integrate these substantial assets and put up great performance metrics quarter after quarter. As I mentioned, 2022 was a transformational year for our company. With the closing of 3 significant acquisitions totaling more than $2 billion, and I’m pleased to report that we have successfully integrated all of those assets into our business.

These 3 acquisitions have delivered over 575 high-quality, high-return locations. The quality and productivity of this recently acquired inventory are clearly apparent in our fourth quarter oil production levels. Our production has increased to almost 105,000 barrels of oil equivalent per day in the fourth quarter of 2022, which is an increase of approximately 250% year-over-year. The record-setting production level was driven by a number of significant new wells that came online and supported our strong fourth quarter performance. The oil component of our fourth quarter production topped 46,700 barrels per day which exceeded the midpoint of our oil guidance range by 9%. Steve will highlight several wells that drove our strong quarterly outperformance.

As a result of strategic acquisitions and targeted development activities on our existing acreage, we saw an approximate 1.5 times increase in our year-over-year proved reserves. Reserves increased to about 368 million barrels of oil equivalent under SEC guidelines, with a proved developed component of about 72%. The value of those proved reserves stands at $4.6 billion at strip pricing and the proved developed component alone is valued at more than $3.6 billion, which is more than our current enterprise value of about $3 billion. In addition to driving value from our asset base, we always look for additional opportunities to create value per share. In early October, we returned approximately $44 million to our shareholders through the proactive repurchase of 3 million shares of our Class A common stock from Warburg Pincus, reducing our share count by about 2%.

The private equity investors in Earthstone have continued to support our consolidation strategy. They will continue to focus on the remaining shares they own while seeking to maximize the value of their investment. As Warburg has done previously, we expect them to manage future sales in the same prudent manner. NCAP, as our largest shareholder, has been with us now on 3 separate occasions. And with their current investment in Earthstone, they too are focused on continuing to see us grow shareholder value further. Our focus on creating debt-adjusted per share growth for all of our shareholders is clearly exhibited on Page 6 of our earnings presentation. Since 2020, we have increased production and proved reserve value on a per share basis by 185% and 289%, respectively.

And finally, the strength of our balance sheet has been and will continue to remain a top priority at Earthstone despite using a considerable amount of debt to fund over $2 billion of acquisitions in 2022, our focus on a conservative balance sheet management and our utilization of free cash flow to pay down debt results in us ending the year with a lower leverage on a last quarter annualized debt-to-EBITDAX ratio than the level at which we entered the year. Growth and reduced leverage, how’s that for a 1-2 punch? Looking ahead, our 2023 plans call for a 5-rig program with 3 rigs active in the Delaware Basin, focusing on our Stateline area during the first part of the year and 2 additional rigs in our Midland Basin properties. Previously reporting guidance, our plans call for an investment of approximately $750 million, and we expect to deliver production of approximately 100,000 BOE a day for 2023, both at the midpoint of guidance.

With all that, I’d like to now turn the call over to Steve to provide an update on operations.

Steven Collins: Thanks, Robert. Good morning, everyone. The fourth quarter was another outstanding quarter for the operations group. We had a busy quarter, spending a total of 21 gross and 16.3 net wells, and we put on production a total of 16 gross and 12 net operated wells. As Robert mentioned, our operations team brought on some — brought online some really great wells during the quarter. We have shown the locations and results of these wells on Page 11 of our updated corporate presentation which is available on our website. I want to highlight a few of those pads. In early October, in the Midland Basin, the TSRH East 4-well project located in Reagan County, Texas, was put online and is producing from the Wolfcamp A and B zones.

These wells were drilled with lateral lengths of approximately 14,300 feet. The wells had an average peak IP30 rate of 1,054 BOE per day per well, and production stream was around 80% oil. The project highlights the strength of our Central Reagan County acreage, and we expect similar results in this area in 2023. We completed the Jade 34-3 Fed pad on our acreage acquired from Chisholm in the Northern Delaware Basin in Lea County, New Mexico. The well is targeted first and second Bone Spring intervals with laterals averaging 9,800 feet. The 2 wells averaged 1,019 BOE per day for the first 35 days and the production stream was 85% oil. The year started out on a high note with another Lea County, New Mexico, pad also acquired from Chisholm. The Squeeze 2 ST Com, 3-well pad had an average peak IP30 of 1,606 BOE per day, which was approximately 82% oil.

These are very strong results, especially considering the wells have an average lateral length of 4,560 feet. And finally, I’d like to highlight one pad that we’re drilling now. We recently spud the El Campeon Fed Com 432H. This will be the first of 6 wells we plan to drill this year that will cross the state line of New Mexico and Texas. We will have significant ownership in these wells, which will be drilled with laterals from 9,600 to 10,000 feet. As most of you know, this area is known for having some of the best rock in the country, and we look forward to seeing the results late in the third quarter. I want to thank the land team for their hard work and dedication in navigating a complex process to obtain this multistate permit. As in the past, we will continue to be laser-focused on reducing costs on our recently acquired assets across our existing asset base.

Given our low-cost mindset, we will continue to increase operational synergies with personnel and systems to lower overall LOE per BOE as well as focus on improving production run times. Given our continuous focus on cost, we sold our asset and closed that transaction for approximately $21 million in the fourth quarter. had about 780 vertical wells, a high operating cost of roughly $10.50 per BOE and only 850 BOE per day of production. Finally, I want to thank the operations team for their tireless efforts as we continue to execute opportunities to reduce costs, increase run times and improve capital efficiency on our expanded operational footprint and begin to implement our 2023 capital budget. With that, I’ll turn it over to Mark.

Mark Lumpkin: Thank you, Steve. I will focus my comments today on providing additional details on some meaningful metrics and key highlights, but I’ll also refer you to our earnings release and our 10-K for a more detailed breakdown of results. Starting with the income statement. Adjusted net income for the fourth quarter was $147 million or $1.04 per share. Adjusted EBITDAX was $338 million and free cash flow for the fourth quarter was approximately $134 million, bringing our free cash flow for the year to $509 million, which was a company record. We’ve continued to utilize free cash flow to repay credit facility debt, paying down approximately $122 million in the fourth quarter. As of December 31, 2022, we had approximately $515 million outstanding under the credit facility, which is now down a bit below that.

And total debt at that time was a bit under $1.1 billion. Our debt to annualized adjusted EBITDAX ratio for the fourth quarter, as Robert mentioned, was 0.8x, which is ahead of our plan and down from 0.9x at year-end 2022. Looking ahead, we plan to continue to utilize our free cash flow to reduce debt with that being earmarked for credit facility repayments. From a production standpoint, we are pleased to surpass the midpoint of our fourth quarter guidance range by approximately 4% and by 9% on the oil midpoint achieving production of nearly 105,000 barrels of oil equivalent per day, which was comprised of 45% oil, 31% natural gas and 24% natural gas liquids. As Robert mentioned, we have guided our 2023 production at 96,000 to 104,000 BOE per day.

From a production cadence standpoint throughout the year, we expect to be in the upper half of that range, starting out the year through the first quarter with momentum carrying over from some really strong results in the fourth quarter of last year. We expect a bit of a step down in the second quarter on production levels based on completion timing. And we expect that the second quarter will be our lowest production quarter of the year with production normalizing more in the second half of the year after a lower second quarter. Moving on to capital expenditures. We invested $180 million in the fourth quarter, which was in line with our guidance range. For 2023, we expect to invest $725 million to $775 million of capital with our D&C capital representing over 85% of the total.

We expect our D&C capital expenditures to be fairly evenly distributed throughout the year. However, we expect the $72 million to $75 million in non-D&C CapEx in 2023 to be a bit more front-half weighted with about 80% of that in total expected to be invested in the first half. Most of this CapEx is related to infrastructure projects that will provide for a more efficient program later in 2023 and in future years. Next, let’s briefly discuss general and administrative expenses. Cash G&A of $13 million for the fourth quarter was slightly higher than guidance due to an increase in head count and a higher than typical cash bonuses intended to reward our employees for an exceptional performance and results in 2022. Stock-based compensation for the fourth quarter was $20 million, bringing the total to the year — for the year to $35 million.

A good chunk of that amount in the fourth quarter, over half of it, was a onetime expense related to the impact of vesting in performance units that were originally issued in January 2020 that hit max payout of over — of 200% based on stock performance over that 3-year period. Going forward, we expect a more normalized level of quarterly stock-based compensation expense somewhere around half of what we reported in the fourth quarter, but it does remain impacted by movement in our stock price. On the hedging front, we are currently hedged about 40% for oil and gas and for 2023 based on the midpoint of our guidance. Our utilization of collars and puts in addition to some swaps provides us with not only significant downside protection, but also provide upside pricing exposure as well.

I would also highlight that we are heavily hedged on WAHA basis, which limits the impact of the potential widening of our gas differentials in both 2023 and 2024. And you can find our updated hedge position in the earnings presentation we posted to the website. For more detailed information on our 2023 guidance, which was originally released in mid-February, but being reaffirmed with this release, please see the earnings presentation as well. With that, I’ll turn it back to Robert for closing comments.

Robert Anderson: Thanks, Mark. Looking ahead, we will continue to deploy our substantial free cash flow, like Mark mentioned, on reducing the outstanding debt on our credit facility. But we also believe scale matters in our business, and we will continue to look for accretive assets that will increase our size, while at the same time, creating additional shareholder value. In closing, in less than 2 years, we’ve transformed Earthstone into a leading E&P with stable production, with a base of approximately 100,000 BOE per day that provides for a low-cost operating structure and a deep inventory of high-return future drilling locations that further support our efforts to maintain, but perhaps grow production over the long term.

We believe we have built a company that offers an attractive value proposition to investors, including having one of the highest free cash flow yields at one of the lowest enterprise values to EBITDA multiples in the E&P sector. And a current valuation that is significantly below our total proved reserve value of $4.6 billion, which is $1.6 billion higher than our current enterprise value. Of course, none of this would have been possible without our best-in-class employees. Their constant dedication and hard work have propelled us to become the premier Permian’s mid-cap operator today. This is supported by our leading lowest all-in cash cost business, as important has been the continued commitment and support of our shareholders. With that, operator, we’ll turn it over for Q&A.

Q&A Session

Operator: . Our first question comes from the line of Neal Dingmann with Truist Securities.

Neal Dingmann: Robert, my first question is on asset allocation, specifically, you all anticipate keeping 3 rigs in the Delaware and 2 in the Midland for this entire year, and then maybe something kind of specifically on that, do you view within the Delaware your Titus acreage to be among the best. I’m just wondering, is it a single rig you’re going to continue to run there? So maybe just a little bit of color on potential plan for the year? And I don’t know if you want to rank the assets, but just maybe specifically on that Titus because I think that’s quite good.

Robert Anderson: Yes, Neal, thanks. Good question. We right now are just going to continue our plan, which is 3 Delaware Basin rigs and 2 Midland Basin rigs and don’t see us veering off that anytime soon. Towards the end of the year, as more availability of permits or things change in New Mexico, could we adjust? Sure. But that will be an audible we wait till later in the year. So all our guidance is based on that split. Rightly so, the Titus acreage along the state line is some of the best acreage in our portfolio or in anyone’s portfolio for that matter. It’s just great rock. We’ll spend quite a bit of capital and a lot of drilling down there in the first part of the year. And then rigs will move north and drill on Chisholm acreage. And then I think we transition back down there later in the year. But it is good rock. We’ll spend some time and capital there and really look like Steve said, look forward to the results of all these wells we’re drilling down there now.

Neal Dingmann: Great details. And then maybe, Mark, for you. Could you just — I want to make sure I heard right on the CapEx, did you say — maybe talked about cadence — CapEx cadence, I guess, I would call it. Did you say what, 75% or so would be in the first half. I’m just wondering, again, what — maybe talk about the — how you see sort of throughout the year, the spending allocated and then obviously, what you talked about the result in production given that.

Mark Lumpkin: Sure. Yes. Thank you. So let me clarify that a little bit. It’s not 75% of our D&C CapEx, that’s the first half. The D&C CapEx is fairly evenly distributed throughout the fourth quarter. But in addition to that, we’ve got $72 million to $75 million of non-D&C CapEx and that is more front-half loaded. So let’s just say, if we were talking about $75 million, it probably looks something like $30 million, $30 million, $12.5 million, $12.5 million instead of being evenly distributed. So like as a whole, we’re slightly more front-end weighted, but not drastically, we’re at 75%. I mean you can do the math on that. If you really take the D&C CapEx and about it before, that’s going to be directionally close enough. But — just need a little bit more of the non-D&C in the first and second quarter of the year versus the third and fourth quarter.

On the production side, we did hit a really nice number in the fourth quarter, and it was about 5% above what our guidance was. And it surprised us. I mean there are some reasons things went well, and that has carried over in the first quarter. Not saying we’re going to hit that same number in the first quarter, but do expect it to be above 100 a day. And in the second quarter, just sort of looking at where we are, it’s probably closer to 100 or a bit below 100 a day. And then the second half looks like it should be just a tad higher than however, second quarter shakes out. Now I’m saying that looking 9, 10 months down the road, that’s what it looks like right now. Obviously, feel more confident in the first quarter and second quarter, and the third and fourth quarter could move around a little bit.

But generally speaking, we expect to start off relatively well in the first quarter, dip a bit in 2Q and then pick back up somewhere between probably 1Q and 2Q.

Neal Dingmann: And Mark, that $75 million non-D&C, is that non-op? Or is that — what exactly is that? Have you all said.

Mark Lumpkin: No, it’s not non-op. There is some non-op in our budget as well. It’s laid out in the guidance. It’s largely infrastructure and capital workover. I think probably 20% or 25% of it is capital workover and that just happens to be a little bit more front-weighted too, but the bulk of the $72 million to $75 million is infrastructure, and it’s really designed to accelerate some of the things we’re doing in Lea County, in particular, in the Delaware more broadly speaking. And as you know, Lea County is fantastic rock, and we’ve got 3 rigs there most of the year and lots of other rigs are in the area. It is tight from an infrastructure standpoint. And we made a decision sometime later last year and definitely by January this year that we’d spend a little more money to create some more optionality on takeaway really on the water, oil and gas gathering and processing standpoint.

Neal Dingmann: I’m glad you’re doing that and not to belabor, but is that more onetime? Or is this because you’ve just bought these assets, some of those on Titus and others, is this something you would see continuing annual? Or I don’t know, maybe Robert wants to comment on — Steve, just on what they would see kind of on a go forward. I totally get — and appreciate you all doing that this year, early this year. I’m just wondering, is that something we would think annually, you would have this or more kind of onetime is the nature?

Mark Lumpkin: I think, Neal, I mean, we’re a little conservative. Our model for next year is basically the same number. I think practically, there is a decent element that’s sort of a onetime thing and really it’s the first half of this year. So I don’t know that it’s going to cut in half next year, but it’s probably down 1/4 or maybe 1/3 based on everything we know right now.

Robert Anderson: Neal, what we’re trying to do is just make sure we create options for ourselves and control our destiny and don’t get hung up by different service companies or what have you, vendors who can drive our business, we need to drive our business ourselves.

Neal Dingmann: So Robert, does this give you assets that, at some point way down the line, you could monetize? Or you’ll end up — these are proprietary infrastructure assets that you would own? So I just want to try to make sure I understand what you…

Robert Anderson: Yes. I think they go with the wells, Neal, is the way to think about it. Like we’re not building out a giant midstream entity here. It’s infield gathering and central delivery points that just make our life a lot — more in control.

Operator: Our next question comes from the line of Charles Meade with Johnson Rice.

Austin Aucoin: This is actually Austin Aucoin, Charles’ associate. Quick question. How attractive is the current A&D landscape? And second, what would your appetite be in equity in the transaction?

Robert Anderson: Yes. Good questions. We see that landscape is very attractive, still a lot of opportunities. We are very focused in the Permian Basin, both the Midland side and the Delaware side. And I think it’s going to be a relatively active year for our guys to review and evaluate transactions of various types. So we won’t be sitting around wondering where the next deal may come from. There is a pipeline of opportunities out there, and we’re busy already looking at things. Each deal probably needs to be evaluated from an equity — the use of equity and consideration independently. So there’s not a fixed answer. A lot has to do with who the seller is, a lot has to do with where our stock price is, where the commodity is at the time.

But I think our track record is pretty consistent that we’re going to want to use equity in most deals. Over the last 2 years, we’ve averaged 30% equity and 70% cash in all the transactions we’ve done. So I think it probably won’t get higher than that, but it sure could vacillate between 30% and 10% of the deal. So it just varies by deal.

Austin Aucoin: And as a follow-up, another strong quarter of strong results from the Delaware Basin, especially with the average lateral length of 4,500 feet. Do you see a path to be able to extend those laterals.

Robert Anderson: We — our land team is constantly trying to do trades where it makes sense, but a lot of cases, in that particular instance, we had wells on both sides of us or other operators who had their own development plans. And so we were locked out from extending those laterals. We’re definitely wanting to drill longer laterals everywhere we can, just capital efficiency, no telling what those wells would have produced at 10,000-foot laterals, but really strong economics there.

Operator: . Our next question comes from the line of Subhasish Chandra with The Benchmark Company.

Subhasish Chandra: Congrats again, finishing the year quite strong. I just hopped on, so if this was addressed before, I apologize. Now I guess that you sort of have multiple rigs going on? And — is there a development philosophy that you have whether it’s mowing the lawn, working co-development by zones, drilling the best wells, is there something that will guide your development budget now that you’ve secured all these assets?

Robert Anderson: Yes. Subhasish, great question. I would say that our historical track record will show you what’s going to happen in the future, and that’s — we’ve been co-developing for the last 5 years or however many years, we’ve been in the Midland Basin, and we’re doing the same thing now in the Delaware side. So we’re not going to just pick one zone and mow down a Wolfcamp interval from one side of a unit to the other and then think about coming back later. The most effective, efficient from a reservoir standpoint and ultimately a full pad development or economically, the best way to do it is co-develop. In some circumstances, you can leave out shallower zones or deeper zones because of the distance and you can come back later.

We’re going to drill a couple of Wolfcamp D wells in Midland County here shortly, and we’re going to be underneath existing Wolfcamp A and B and I think some Lower Spraberry wells. So there are unique circumstances where you can come back. But generally, we’re codeveloping everything that needs to be codeveloped at one time.

Subhasish Chandra: Do you plan any sort of exploration work in the Delaware, sort of delineating additional zones? You mentioned the in the Midland similar type stuff in the Delaware.

Robert Anderson: Well, I would hate to tell you that we’re doing great exploration work and lead you astray on the Wolfcamp D. There’s lots of Wolfcamp D wells around us in Midland County and other counties adjacent. So it’s really letting other operators sort of prove up the economics and the viability of certain zones. That’s the case in the Wolfcamp D. We’ve seen other intervals in the Delaware side for instance, the Avalon, which is a little shallower and some people have it — call it something different. But we’ve seen Avalon results that are fantastic. We need to maybe see a couple more wells closer to us in some circumstances where our acreage position is. But we’re not going to go out there and do a deep exploration well, we may target some of these other nontypical wells from time to time like the Wolfcamp D.

Subhasish Chandra: Okay. Got it. And just as my follow-up, and this might have been addressed before too, but your desired capacity appetite to sort of defend the stock in case of private equity sell-off, is there — can you frame that in any way? You obviously have a good amount of liquidity sort of — paint that picture a little bit.

Robert Anderson: Sure. I mentioned in our kind of prepared remarks that Warburg has sold a few shares along the way. It’s all public and filings and things of that nature. But we actually did participate in a trade that Warburg did in October, and we bought 3 million shares. The circumstance will dictate whether we do that again in the future if that opportunity is available to us. The undervalued nature of our stock right now makes that a great investment and somewhat of an easy decision depending on, again, where our stock price is. But we’re open to exploring that option as sellers want to come to the market such as Warburg.

Operator: That concludes our question-and-answer session. I’ll turn the floor back to Mr. Anderson for final comments.

Robert Anderson: We really appreciate everybody’s time today. We look forward to a very successful 2023 and glad that we got through the last few months of preparing our 10-K and appreciate your time this morning. And reach out to us if you have any further comments, questions or concerns, and we’ll do the best we can to answer those. Thanks a lot. Everybody, have a great day.

Operator: Thank you. This concludes today’s conference call. You may disconnect your lines at this time. Thank you for your participation.