Earthstone Energy Inc

F:BSC2

Earnings Call Transcript 2021-Q2

[Operator]

Good morning, and welcome to 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 of Operations; and Scott Thelander, Vice President of Finance. Mr. Thelander, you may begin.

[Scott Thelander, executive]

Thank you, and welcome to our second quarter conference call. Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Securities Exchange Act of 1934 as amended. 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 the earnings announcement we released yesterday in our Form 10-Q for the second quarter that we filed yesterday and in our annual report on Form 10-K for the year ended December 31, 2020. These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday. Also, please note, information recorded on this call speaks only as of today, August 5, 2021. Thus, any time-sensitive information may no longer be accurate at the time of any replay or transcript reading. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website and also by telephone replay. You can find information about how to access those in our earnings announcement released yesterday.

Today's call will begin with comments from Robert Anderson, our CEO, followed by remarks from Steve Collins, our Executive Vice President of Operations; 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, executive]

Thank you, Scott, and good morning, everyone. I know it's been a busy couple of days, and we appreciate your time today while you join us for our second quarter 2021 conference call. Our strong second quarter results reflect our continued positive momentum and the impact of our ongoing consolidation strategy. We have now closed 3 meaningful acquisitions this year for a total of $360 million and resumed our drilling and completion program, even adding a second drilling rig and all of this activity while adding only minimal G&A. While these acquisitions closed -- with these acquisitions closed and our drilling program well underway, we enter the second half of the year expecting to hit a daily production rate by year-end that should be nearly double our 2020 daily average production rate, while only increasing our outstanding share count by 30% and with a minimal impact on debt to trailing EBITDAX. We have also generated over $100 million of free cash flow in the past 12 months, with $60 million of it coming this year. We continue our efforts to increase per share value with our financial results, which we expect will continue to be recognized in our stock price. Through these acquisitions, we have added complementary assets that have helped us to increase our operating scale, continue our operating efficiency improvements at economic upside from high-quality drilling locations while maintaining strong liquidity and lower leverage. All of these enhance our primary mission of increasing per share value. Efficiency and cost management continues to be a key focus for our team. For example, we recently drilled our initial wells on the IRM assets acquired in January of this year, and we are pleased that they came in ahead of schedule and below our cost estimates. This adds to our confidence in our ability to efficiently integrate these acquisitions and effectively develop our growing drilling inventory. As you know, with now having closed 3 acquisitions this year and with the combined assets bringing significant cash flow, we recently increased our 2021 capital budget by $40 million in conjunction with the addition of a second full-time rig, which is now drilling away. We don't expect to see much, if any, production impact on 2020 volumes from the second rig, yet with the increased cash flow we are achieving, we do expect to continue to generate significant free -- positive free cash flow and look forward to production and cash flow impact at the second rig in 2022. After completing an internal review of our midyear reserves and adjusting for the Tracker acquisition, proved developed reserves at strip prices as of July 1 have a PV-10 value of approximately $1.1 billion and 83.6 million BOE or barrels of oil equivalent. Considering the total proved reserves consisting of proved developed and proved undeveloped, while giving no credit for the tracker drilling locations at this point, we have a PV-10 value of approximately $1.7 billion and 133.6 million BOE. Compare these numbers to our market cap today of approximately $750 million. Proved developed reserves compared to the end of 2020 have more than doubled with the acquisitions and our drilling activity this year. And the end of 2020, we had 40 million barrels of oil equivalent using 50 barrel per barrel flat oil prices, so quite an achievement in the first half of this year. We generated almost $54 million of adjusted EBITDAX in the second quarter, up approximately $10 million from the first quarter due to higher commodity prices and higher production volumes, resulting in almost $100 million of adjusted EBITDAX in the first half of the year. We estimate that production in the second half of 2021 will be between 25,527 BOE per day, up from 21,525 BOE per day in the first half. And we intend to continue to work to add additional scale that will further enhance our cost efficiencies and lower our per unit cost structure. Now I'll turn the call over to Steve to provide an update on operations.

[Steven Collins, executive]

Thanks, Robert, and good morning, everyone. During the second quarter, we completed a 3-well pad in Midland County, comprised of short laterals, of which we have a 70% working interest. We also drilled 4 wells on the Pearl Jam pad in Midland County, where we have a 95% working interest. The Pearl Jam wells, also short laterals are the company's first wells drilled on the recently acquired IRM acreage. As Robert mentioned, we are very pleased with how smoothly these operations went. That rig is now drilling at a 4-well pad in Western Reagan County on our West Hartgrove unit, where we have 87% working interest. Having picked up a rig in March after nearly a 1-year hiatus, our team has hit the ground running, and we are excited to be back to drilling and completing wells. As Robert mentioned, we just deployed a second rig, which we had placed in Upton County on a 5-well pad. We're excited about having a full drilling and completion schedule going forward, particularly once we begin completing the wells drilled with the second rig, which we expect to do late in the year. So far, we are very pleased with our drilling and completions operations and are particularly pleased to have the IRM assets fully integrating, having recently drilled our first pad on those assets. We began completion operations on those wells this week. We have taken over operations on the Tracker assets. I was out Midland this week to start the process of implementing the Earthstone culture at the Tracker properties as well as initiating completion operations on the Pearl Jam pad. Due to a combination of factors, our completion schedule this year is heavily weighted towards short laterals. The 20 gross wells are -- we expect to bring on this year, we'll have an average completed lateral length of around 5,200 feet. While these wells are in really good rock with attractive economics, there is no doubt that capital efficiency has decreased with a shorter lateral weighted program. The 30 wells we expect to spud this year will have average 6,800 foot laterals. The longer laterals are more weighted to the back half of the year. This sets us up well for next year, when we expect the average lateral length to be much more heavily weighted to longer laterals with expected average completed lateral length closer to 9,000 feet. Let me take just a moment to address cost inflation. We have some upward pressure on all areas of operations, like steel prices for casing, frac cost increases and increases in items such as chemicals and trucking. We had some of these items included in our range of capital costs for the updated guidance. We are working hard to offset these increases with efficiency gains from less days on locations while drilling and completing. Steel prices are up approximately 20%, and our frac cost per stage is up 14% since the beginning of the year. We expect these costs to level out here and only expect minor increases in other areas as oil prices have stabilized in the $70 range. We have seen some savings in lease operating expenses as we implement our procedures based on our experience of best practices from our existing operations. However, we do continue to see increases in trucking and fuel prices. Again, we will target additional efficiencies in these new assets in order to offset higher costs. With that, I'll turn it over to Mark.

[Mark Lumpkin, executive]

Thank you, Steve. As usual, we'll start with financial side with a recap of the balance sheet and liquidity position, and then we'll go into some other financial details for the quarter. As you know, maintaining strong liquidity continues to be a key focus for us, especially as we further increase the scale of our operations and remain poised to take advantage of new opportunities in the A&D world. Once the closing of the Tracker acquisition on July 20, the borrowing base of our revolving credit facility increased from $475 million to $550 million. Looking at the quarter end, cash balance and debt balance as of June 30, we had a cash balance of $0.5 million and a debt balance of $241.4 million outstanding on the credit facility borrowing base of $475 million. Adjusting for the closing of the Tracker acquisition in July, we would have had an estimated $0.5 million in cash and $301 million of long-term debt outstanding under our credit facility with a borrowing base of $550 million. On that adjusted basis, with the $249 million of undrawn borrowing base capacity and about $0.5 million in cash, we had total liquidity of near $250 million, which is just a little below 50% availability under the new borrowing base. For the second quarter, we generated $28.4 million of free cash flow, which when combined with the $31.8 million we generated in the first quarter brings us to a little over $60 million of free cash flow in the first half of the year. We expect to continue generating free cash flow in the second half of the year, and we'll continue to utilize free cash flow to pay down debt. Through the first half of the year, which is prior to the impact of Tracker, our total debt to annualized adjusted EBITDAX was 1.2x. We believe we are well on our way to achieve our targeted goal of having leverage below 1.25x at year-end 2021, including adjustments for all of our acquisitions. Further, with the expectation that we will see significant production growth in 2022, while utilizing free cash flow to reduce debt levels, we fully expect to be below 1x leverage by year-end 2022. Excluding acquisitions, our accrued capital expenditures totaled $22.8 million in the second quarter, bringing year-to-date capital expenditures to $32.6 million. Based on running 2 rigs for the balance of the year and turning 20 gross operated wells to sales, our recently revised 2021 capital budget fits at a range of $130 million to $140 million. As Steve mentioned, we do have some room for cost inflation and that -- then they imply $102 million of second half CapEx at the midpoint. And I can assure you that our operating team is laser-focused on maximizing cost efficiencies. Now looking at the second quarter of 2021 financial metrics and starting with the top line. Revenues for the quarter were $89.7 million, with oil controlling 79% of the revenues. From a production standpoint, in the second quarter, we achieved record sales volumes of 22,716 barrels of oil equivalent per day, which were comprised of approximately 52% oil, 24% natural gas and 24% natural gas lipids. Now moving over to commodity prices for the second quarter. Our realized prices for oil were $65.47 per barrel of oil before hedges and $52.39 per barrel after hedges. For natural gas, we realized $2.29 per Mcf before hedges and $2.19 after hedges. And for natural gas liquids, we realized $24.31 per barrel, and we don't have any hedges on our natural gas liquids, so that's the same realized price pre and post hedge. That brings us to a total BOE equivalent of $43.38 before hedges or $36.38 after hedges. Of course, we've not enjoyed writing hedge settlement checks this year, but our consistent discipline on hedging is a key part of our risk management strategy. And while it's been painful in a rising commodity price environment, our hedging strategy greatly benefited us in 2020 and was really critical and position us to be able to make the IRM and Tracker acquisitions we have in 2021. On the expense side, on a per unit basis, our all-in cash costs, which includes LOE, gathering, processing, transportation costs, production and severance, tax, cash G&A and interest expense, came in at $11.65 per barrel of oil equivalent for the second quarter, which was down from $12.66 per barrel of oil equivalent in the first quarter. Our lease operating expense was $5.68 per barrel oil equivalent compared to $5.93 per barrel of oil equivalent in the first quarter. And as you have seen, we have revised our guidance range for LOE in the second half, downward to a range of $5.35 to $6 per BOE, which is a significantly lower range of guidance than we previously had provided. On the general and administrative expense side, our adjusted cash G&A expense was $4.8 million or $2.30 per barrel of oil equivalent in the second quarter, which compares to $2.76 per barrel oil equivalent in the first quarter. Our continued growth in production, while maintaining relatively flat cash G&A, which came in just under $10 million for the first half has allowed us to continually improve our cost structure. It was not that long ago that we were seeking to achieve combined LOE plus cash G&A costs of below $2 per BOE, and we just came in under $8 per BOE in the second quarter. From an income standpoint, we reported a GAAP net loss in the second quarter of $15.8 million or a loss of $0.20 per share, which included unrealized losses of $36.7 million on our derivative contracts. Our adjusted net income, which excludes the impact of unrealized derivatives was a profit of $20.3 million or $0.26 per diluted share in the second quarter. And as Robert said, we reported very strong EBITDAX of $53.7 million in the second quarter, which was up approximately 22% from the first quarter. With that, I'll turn it back over to Robert for closing comments.

[Robert Anderson, executive]

Thanks, Mark. Our having closed on $360 million of highly attractive deals so far this year is representative of our ability to execute on our growth strategy by using our strong financial position to increase our scale with high-quality accretive acquisitions. Capturing meaningful value for our shareholders remains our #1 priority. And as can be seen by these deals, our operating statistics through the first half of the year and our conservatively managed balance sheet. We are continually seeking additional attractive consolidation targets and are confident in our ability to effectively integrate further asset acquisitions.

We have worked hard to maintain the strength of our balance sheet throughout these recent acquisitions, and we will continue to pursue accretive consolidation opportunities that add valuable scale to our operations while maintaining our strong cost structure and clean balance sheet. Now with all that, operator, we'll be glad to take a few questions.

[Operator]

[Operator Instructions] Our first question comes from Jeffrey Campbell with Alliance Global Partners.

[Jeffrey Campbell, analyst]

My first question is regarding cost inflation, your forecasted all-in frac costs on Slide 12, actually haven't changed since guidance provided on Slide 5, '21. So even though you highlighted some cost inflation today, it appears that it's still within your prior forecasted range. Is that correct?

[Robert Anderson, executive]

Yes. That all stays the same, Jeffrey. We had a little bit of pushing in there from the beginning of the year, and things have stabilized. So we hope that we don't see any major increases between now and the end of the year.

[Jeffrey Campbell, analyst]

Okay. Great. I was wondering if you could add a little bit of color regarding the location of the wells and completions that you're currently generating with the second rig.

[Robert Anderson, executive]

It's in Upton County, sitting right next to some other wells that we completed earlier in the year, offsetting the Ratliff and Benedum area. So it's right at the county line between Upton and Reagan County line. So it's in our really good, high-quality rock area. And that's where the second rig is running right now.

[Jeffrey Campbell, analyst]

Okay. And the last one that I'll ask is, you noted that you intend to add additional scale. I just wondered if you could expand on what your options are in that regard.

[Robert Anderson, executive]

Well, it's a pretty active A&D market currently for lots of reasons, oil prices are up. So sellers are feeling pretty good, although forget about what's happened maybe in the last week. But -- and I think people are trying to take advantage of where the market is right now. And so there's lots of deals on the market. And so our deal flow is pretty high, and our teams are really busy. And I think it just gives us optionality of future opportunities to look at and kind of pick and choose what makes sense for us. So we feel like -- we've proven we can integrate assets. Steve and our team have done this a lot through a long number of years and a lot of different deals. So each one is a little different each deal, but we think we can continue to integrate assets effectively and manage more under this management team. So we're going to continue to keep beating the bushes and try and find opportunities to grow because I think that's what will make us attractive to investors as we continue to build a really nice business.

[Jeffrey Campbell, analyst]

And just as a quick follow-up to that. So I want to just hog the whole thing here. You recently did a deal on the Eagle Ford, and there's been some more consolidation there recently. Is the Eagle Ford a place that you would still look for opportunities? Or are you really focused on Midland at this point?

[Robert Anderson, executive]

Midland is our first focus area, we'll call it. But having a footprint in the Eagle Ford and having a great operating team there makes it easier for us to look at deals versus if we weren't in that basin. We love the play, and there has been some consolidation. And I think similar to the Midland Basin, there's still a lot of private companies who are looking to monetize as well as public or larger companies who are looking to sell assets. So we want to participate if it makes sense.

[Operator]

Our next question comes from Neal Dingmann with Truist.

[Neal Dingmann, analyst]

And I was going to mention, I'm not only going ask about M&A because by now, I just assume you guys are going to keep cranking out a few accretive deals a year. So Robert, let instead -- let me turn things right over to capital discipline. I'm just wondering, given next year, you've talked about the 2 rig program, the low cost. I think obviously, the hedges drop off a bit. And if we have these solid prices that could continue, by my math, you guys could start cranking out, I don't know, even potentially over $25 million quarterly free cash flow. Could you speak to your thoughts on redeploying this capital, whether does it make sense to -- for more growth to generate even more free cash flow? Or there I might even say share buyback, I'm not always a fan, your shares seem incredibly cheap versus your asset value. So again, I'm just wondering once you get to that potentially time next year if things are going as such, what is your thought?

[Robert Anderson, executive]

Yes. We consider all this, Neal, as you know, whether we should consider some kind of shareholder return or use cash flow to continue to build scale. And I think, first and foremost, for us, outside of paying down debt and getting leverage well below 1x is continuing to build scale. I think it -- sub -- I don't know what the right number is, $2 billion or $5 billion market cap. You have limited options for investors and getting bigger. And if we can build this same kind of profile of a company at $2 billion plus, having low leverage, lots of liquidity and a good business with low-cost structure, I think that will continue to attract new investors into our stock and create shareholder value, which this is what it's all about. So I think next year, we would consider it, but that's not the first place where we would consider putting excess free cash flow.

[Neal Dingmann, analyst]

Yes. Absolutely. I think it makes total sense. And then my second, maybe even for Mark, is just more on your hedging philosophy, kind of, again, back to what I was thinking about for next year, if things continue to go as such. I mean, your -- I mean, balance sheet continues to be, of course, very, very conservative. So I'm just wondering, again, if some of the hedges roll off next year, would you consider just leaving less hedges? Would you go to more callers, maybe even consider puts like I know some larger companies are doing? Or would you stay as highly hedged as you've had in the past?

[Robert Anderson, executive]

Well, let me take the first stab, and then Mark, you can chime in a little bit. First of all, we're going to be disciplined, and we're going to have some regular hedging program that we're going to do. We're just not doing it to forecast prices, right? We're protecting balance sheet, capital obligations or our capital program and our overhead. And we're going to have some level, and that number could be less than 80% like we've historically had with a bullish view on oil prices, but also lower debt and a good environment. But at the same time, we're all about risk mitigation. So around hedges -- I mean, sorry, around acquisitions, we're definitely going to want to hedge some PDP value. Mark, I'll let you expand.

[Mark Lumpkin, executive]

I think you got it. That's great.

[Operator]

Our next question comes from Scott Hanold with RBC Capital Markets.

[Scott Hanold, analyst]

If we could pivot back to that second rig, and I think you said that was on a 5-well pad. Could you give us a little bit more color? Or when do you expect to turn those wells in? Is it going to be like all at once? Or will it be staggered? And could you remind us the working interest on those wells?

[Robert Anderson, executive]

So it will be all at once. Well, staggered over a couple of days, how about that? Scott. This is a 5-well pad. And we typically -- we'll frac them all at one-time and bring them all on. And when I say at one time, it's over continuous operations and bring them on all at one-time or continuously until they come online. But I think our plan right now is they don't get started fracking until the late this year, so they wouldn't come on until early next year. And it is a 5-well pad, like you mentioned.

[Scott Hanold, analyst]

Yes. And the [indiscernible] for just in lateral lengths on those?

[Mark Lumpkin, executive]

Yes. Scott, just to add...

[Robert Anderson, executive]

Go ahead, Mark.

[Mark Lumpkin, executive]

Yes. Those are 10,000-foot laterals, and that is a 100% working interest. And I would say, just looking at our program, generally speaking, our average pad sizes for wells, we just brought on something late in June. That was 3 wells. I think the rest of the completions we have this year are actually all 4-well pads. As Robert mentioned, those are all from the existing or the first rig we deployed. And those are actually all short laterals. So we've got 12 short laterals that we should bring online in the second half of the year really from probably mid- to late September into December. And then once we get to next year, as we've outlined, we get to a lot longer average lateral length. I think we're more like 9,000 foot average lateral length next year versus this year with the heavy weighting towards the short laterals. We're not much higher than 5,000 feet. So we're looking forward to that and certainly from a capital efficiency standpoint, it will be nice to see the impact of that.

[Scott Hanold, analyst]

Yes. And so presumably, I mean, obviously, with some of those 4-well pads coming in September, December this year. And then that 10,000 foot lateral, 100% working interest pad, 5-well pad coming on early next year. I mean, that should probably present a pretty good opportunity to see a big uplift in production in 1Q 2022. Is that a fair way to think about it?

[Robert Anderson, executive]

I think that's a fair start. Also just to add , we obviously just put out updated guidance a couple of weeks ago when we announced the close of the Tracker deal. And for the second half, it's a bit of a stair-step in terms of we are a bit over 22,000 BOE a day in the second quarter. If you sort of take what our second half guidance is, the third quarter doesn't have a full quarter of tracker. And there's, to your point, not really much in the way of completion activity that will hit in the third quarter, if at all. So you get a bit of a stair-step from 2Q to 3Q to 4Q. And it's fair to say early next year, particularly as we start bringing on some long laterals. You would see it maybe another step change upward in 1Q.

[Scott Hanold, analyst]

Yes. I mean, it feels like it's going to probably push in excess of 30 a day. Is that -- am I thinking about that right?

[Robert Anderson, executive]

Yes, we should just link to that ballpark. I would also say, just from a oil content standpoint, our guidance is a little below 50% for the second half of the year. That's probably even -- well, it may not be that different between 3Q and 4Q. But as we bring on wells in 4Q, it does get oiler. So we do expect to kind of get back over 50% oil content, when we start getting multiple pads coming online, especially in the next year.

[Scott Hanold, analyst]

Okay. No, that sounds great. It's a nice start to next year. And then I'll ask a little bit on M&A. And what are you generally seeing in the conversations? I mean, obviously, it's been a robust market out there, but do you find that sellers are trying to push price a little bit more? Can you continue to be fairly accretive with transactions out there right now?

[Robert Anderson, executive]

We hope so. I think you're seeing with improved prices and kind of moderated service cost inflation now that in certain instances, upside is being ascribed value. And so to be competitive in a process, we're going to have to look at the upside and figure out whether it fits into our inventory and how soon and whether it makes sense to have to pay something for that upside. But I think that's where you see certain deals and certain sellers having the ability to push the prices. They've got really good inventory. And we've got good inventory. And if we can find areas that will compete for capital, then that makes sense. And we push our price a little bit based on inventory.

[Operator]

Our next question is a follow-up from Jeffrey Campbell with Alliance Global Partners.

[Jeffrey Campbell, analyst]

Yes. And kind of following up on some of the things that Scott was asking, just -- it's probably obvious but I should ask it anyway. Are you planning to continue a 2-rig program in 2022? And is there any possibility we might get a third rig at some point during the year if we continue to have the supportive commodity environment we have now?

[Robert Anderson, executive]

We're definitely planning for a 2-rig program. We've contemplated what does the 3 rig program look like, and you can imagine we have run sensitivities and all that. But at this point, Steve will probably kill me if I said, "Hey, I want to go to a third rig. We just got the second rig running." So just like we did with one going to 2 rigs, we'll probably get 2 rigs running. We'll see how our program is working out in the efficiency and getting the rust out of the second rig and then consider it based on circumstances next year.

[Operator]

[Operator Instructions] Ladies and gentlemen, we have reached the end of the question-and-answer session, and I will now turn the call over to Robert Anderson for closing remarks.

[Robert Anderson, executive]

I appreciate everybody joining us today, and we look forward to continuing the discussion with you next quarter. Have a good day.

[Operator]

This concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.