Earthstone Energy Inc

F:BSC2

Earnings Call Transcript 2019-Q3

[Operator]

Greetings and welcome to the Earthstone Energy Third Quarter 2019 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the conference over to our host, Mark Lumpkin, Executive Vice President and Chief Financial Officer. Thank you. You may begin.

[Mark Lumpkin, executive]

Thank you, and welcome to our third 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 in 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 quarterly report on Form 10-Q for the third quarter of 2019. 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, November 7, 2019, thus, any time-sensitive information may no longer be accurate at the time of any replay. 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 on our earnings announcement released yesterday.

Today's call will begin with opening remarks from Frank Lodzinski; followed by an overview of our current and upcoming operations by Robert Anderson; followed by remarks from me regarding financial matters and performance; and concluding with remarks from Frank Lodzinski.

I'll now turn the call over to Frank.

[Frank Lodzinski, executive]

Okay. Thank you, Mark, and thank you to everybody for joining this call. As Robert and Mark are going to explain in some detail, we had a very solid third quarter, and we're very well positioned for an excellent fourth quarter and moving into 2020.

We're very pleased with our substantial progress, strong production, strong balance sheet and our continued progress to constantly improve our metrics. Our cost metrics and our operations. I believe that we're showing the market that a small company with good management and outstanding operations can be efficient and actually quite competitive with larger companies that have greater scale.

We continue to focus both on operating cost and operating efficiencies in our efforts to drive stronger well returns and ultimately, shareholder value. The environment for acquisition or mergers remain very challenging, but we continue to chase transactions in the Permian and possibly the Eagle Ford that'll be accretive. In the absence of a significant transaction, we continue to improve our inventory of locations through smaller acreage acquisitions and trades that result in longer laterals and increased economics. The wells we expect to drill and complete in 2020 will all be longer laterals.

Finally, based on current commodity prices and our current expectations for our 1-rig operated program in 2020, we forecast our operating cash flows will exceed our capital expenditures during the second half of that year.

We do appreciate your joining, and I'll now turn it over to Robert.

[Robert Anderson, executive]

Thanks, Frank, and good morning, everyone. As we stated all year long, our 2019 capital program is heavily weighted to the second half. We were very active in the third quarter, running 2 rigs and a completion crew in the Midland Basin, while running 1 rig and a completion crew in the Eagle Ford. As a result, we spud 11 wells and completed 8 in the Midland Basin. In the Eagle Ford, we drilled 4 wells and completed 3 and started completions activity on 4 additional wells. Midland Basin completions included 5 Mid-State wells in Midland County, which were completed during the third quarter and brought online in late September as well as 3 TSRH wells in Reagan County that we completed in the third quarter and subsequently brought online in October. The 7 Eagle Ford wells at our Pen Ranch project, were in the process of being completed over quarter end and were also brought on in late October.

We're pleased to achieve third quarter production of 12,181 BOE per day, with no significant contribution from the new operated wells brought online at the end of the quarter. Key factors driving this performance are the larger-than-expected production impact from nonoperated wells that came online during the third quarter and less production downtime compared to prior quarters. Additionally, we've seen lower-than-expected decline rates on our existing producers.

We now have over 30 days of production from the 5 Mid-State wells, which came online in late September. These approximately 10,000-foot lateral wells, targeting the Wolfcamp A and B intervals, have average peak 30-day rates of 1,290 barrels of oil equivalent per day, with about 88% oil cut. The 3 wells in our TSRH unit with -- which were approximately 12,000-foot laterals targeting the Wolfcamp B Upper and B Lower zones were brought online in October and have not yet reached peak 30-day rates, but are producing in line with our pre-drill expectations.

Additionally, during the third quarter, we had 3 gross nonoperated wells, in which we have meaningful working interest of 35% to 40%, were brought online in Howard County. These wells are all approximately 10,000-foot laterals, with 1 well targeting the Wolfcamp A and 2 wells targeting the Wolfcamp D. The Wolfcamp A well achieved a peak IP30 of approximately 2,381 BOE per day, with 88% oil. This well has been online now for approximately 90 days and has averaged 2,159 BOE per day, with 87% oil over this time frame, which is a fantastic well. The 2 Wolfcamp D wells, a first for us, have achieved peak 30-day rates averaging 969 BOE per day, with 86% oil. So we are pleased with these well results also.

As a result of the continued success we have had from the Wolfcamp A on this acreage and now successful Wolfcamp D wells, we expect some expansion of our drilling inventory in Howard County at year-end. You may recall that in prior calls, we have advised that our acreage was not densely drilled, and we were proactively addressing potential depletion and parent-child issues. We are pleased with the impact of adjustments we have made this year already with regards to our well spacing in certain areas, and we are making progress at understanding how to optimally develop our acreage position.

This is particularly evident in the results of our recent TSRH initial production, which we did space a bit wider at approximately 1,100 feet between wells in the same landing zone compared to previously drilled wells on this block, which were at approximately 925 feet. Our initial results at TSRH, and granted, this is only about 20 days of production, looked better than the 2018 wells. And as we get to year-end, we'll probably provide some additional information.

By adjusting our spacing early in the life of the project, we believe we will maximize development and economics. You should note that historically, we have intentionally spaced our proved undeveloped locations at wider spacing in order to be conservative in our development planning.

A little bit on operations. As expected, at the end of the third quarter, we released 1 of our 2 rigs working in the Midland Basin, letting go of the older legacy rig and continuing to operate the high-spec rig we deployed in June. The newer rig is continuing to perform well and is supporting our push to drive efficiency gains. We continue to target 15 days per 10,000-foot laterals, and have averaged 16 days per well, normalized to a 10,000-foot lateral over the last 10 wells drilled in Reagan County. We have recently finished fracking all of our Midland Basin wells that we had planned for 2019 and released the frac crew around 20 days ahead of schedule and expect to have these remaining 6 wells online by the end of the year.

Over the past few months, our completion team did a great job fracking these 14 wells. We went from averaging 8.5 stages per day at the beginning to 12.5 stages per day at the end, while dropping our cost per stage by about 8%. We actually achieved a couple of days where we were over 14 stages per day.

As Frank mentioned, we are constantly working on trades and acreage acquisitions to lengthen laterals, which will enhance our operating efficiency and increase well-level economics. The average of our lateral lengths this year are going to be over 10,000 feet, complement to our land team, who accomplished a trade in September, which will positively impact our 2020 drilling program and keep our lateral lengths towards this distance.

On the nonoperated side, we have 2 gross 0.7 net wells in Midland County that were brought online in October. We are also continuing to participate in additional non-operated activity in Martin County on a 15-well project. Drilling is expected to be finished in December, with completions beginning either late this year or the first quarter of 2020. In the Eagle Ford, we ran 1 rig throughout the third quarter, during which we finished the drilling of 4 wells on our 7-well Pen Ranch project and spudded an additional 3 wells on our Davis East project. And we brought all 7 of the Pen Ranch wells online in October. We have just recently started completion activity on the 3 Davis East wells and expect them to be online by year-end.

Lastly, let me just give some brief commentary on our production levels and commodity mix. As you know, we increased our production guidance in August to the current range of 11,250 to 12,250 BOE per day. With average production year-to-date a little over 12,000 BOE per day, and with increased production in the fourth quarter from all this new activity, we expect to be at the top end of the 14,000 to 15,000 BOE per day exit rate that we had provided in August.

Further, with our commodity mix year-to-date of 62% oil, 17% gas and 21% NGLs, we expect the mix to ultimately be somewhere near this level, but perhaps a little bit higher on the oil side with all these new wells coming online. Year-to-date, our existing wells have continued to hold rate better than our forecast from the beginning of the year. Although our oil percentage for the year is likely to be under our guidance, oil volumes are performing as expected, both on the existing producers and on all these new wells.

With that, I'll turn it to Mark.

[Mark Lumpkin, executive]

Thank you, Robert. Let me start with our financial metrics for the third quarter of 2019. Our revenues for the quarter, which does not include the impact of hedge realizations, were $39.2 million. Crude oil sales contributed $35.4 million or 90% of total revenues, and our production mix during the quarter was 58% oil, 24% natural gas liquids and 18% natural gas.

In terms of commodity pricing, our realized oil prices held steady at 97% of NYMEX, which equated to a realized price of $54.89 per barrel. Natural gas realizations improved from 4% of NYMEX to 32% of NYMEX quarter-over-quarter, resulting in a realized price of $0.72 per Mcf. Natural gas liquids prices remain pressured as we realized the price of $10.71 per barrel or approximately 19% of NYMEX oil prices versus 25% of NYMEX oil prices realized in the second quarter.

We've continued to benefit from a strong hedge book in 2019, with realized gains in the third quarter of $3.7 million, bringing our realized commodity hedge gains for the year to approximately $13.7 million. Our hedge position remains strong with hedges for the fourth quarter of 2019 equating to approximately 96% and 75% of the midpoint of our full year production guidance for oil and natural gas, respectively. We have continued to add to our oil hedge position with some incremental swaps added. In 2020, we now have 7,000 barrels of oil per day hedged on both WTI and Mid-Cush basis at an average net price of approximately $60 per barrel. We also now have a moderate level of hedges for 2021 at an average price including basis hedges of approximately $56 per barrel.

Similarly, we are well hedged through 2020 on the natural gas side on both the underlying commodity and on WAHA basis. Full details of our current hedge position can be found in our investor presentation.

We generated $29.8 million in adjusted EBITDAX in the third quarter. From an income standpoint, we reported GAAP net income of $26.1 million or $0.41 per adjusted diluted share and recorded adjusted net income of $11.6 million or $0.18 per adjusted diluted share. Additionally, GAAP requires us to disclose the amount of net income or loss associated with the controlling interest, which essentially reflects our Class A shares. Accordingly, from a GAAP perspective, we reported net income attributable to Earthstone Energy Inc. of $11.8 million or $0.41 per diluted share. You can also refer to yesterday's earnings release and our 10-Q for further information.

Now looking at our expenses, we reduced both our lease operating expense and cash G&A costs compared to the second quarter on both an absolute dollar basis and on a per barrel of oil equivalent basis. Total LOE of $7.3 million was down from $8.6 million in the second quarter, leading to an average of $6.48 of LOE per barrel oil equivalent in the third quarter, which was down from $7.44 in the second quarter and $6.61 in the first quarter. This was more in line with our LOE cost expectations versus the second quarter, which, as we discussed previously, was elevated for a variety of noncontrollable reasons. Our total cash G&A expense of $4.0 million was down from $4.8 million in the second quarter, leading to an average of $3.59 of cash G&A per barrel of oil equivalent in the third quarter, down from $4.13 in the second quarter and $5.01 in the first quarter.

Let me give a little further color on the cost side. On the cash G&A, with the unit cost year-to-date of $4.22 per barrel of oil equivalent, we are running below our full year guidance range of $4.50 to $5 per BOE. I would note that third quarter tends to be our lowest cash G&A quarter, and fourth quarter tends to be our highest cash G&A quarter historically. So just keep that in mind as you adjust your models. But we do expect to continue managing G&A tightly and LOE, and we continue to target sub-$10 per barrel combined cash cost of G&A and LOE. And we nearly hit that in the third quarter with cash cost of $10.07 per BOE.

Continuing a little bit more on the cost side, let me now turn to capital expenditures. As expected, the third quarter was our highest quarter for capital expenditures year-to-date, with approximately $79 million accrued for the quarter, bringing us to approximately $152 million of capital expenditures accrued for the year through the third quarter. This compares to our full year guidance of $205 million, which implies approximately $53 million of capital expenditures in the fourth quarter. We are still targeting $205 million for the year and don't have any updated guidance for you all.

A couple of things that could move that number a bit higher for the year. First, we are running a little bit ahead of things operationally on the drilling side, with our newer high-spec rig being very efficient. And we'll likely be in a position to drill some additional wells in the fourth quarter versus what is embedded in our guidance. Second, the current guidance assumes completion activity in our nonoperated 15-well Toe Nail project, commences in 2020, but it's not out of the question that completion activity could start late in the fourth quarter and, of course, out of our control as a nonop partner, but if that were to occur, it would require additional CapEx in the fourth quarter. An offset to this potential upward movement in the CapEx is that we are seeing lower capital costs in our drilling and completions than we had previously forecast.

Lastly, let's move over to the balance sheet and liquidity. At September 30, 2019, we had outstanding borrowings under our credit facility of $125 million, with a borrowing base of $325 million and a cash balance of close to $10 million, therefore, we ended the quarter with $200 million of undrawn capacity, plus the $10 million of cash for total liquidity of approximately $210 million.

So our liquidity continues to remain strong. I'm cognizant that our $125 million balance on the credit facility is a bit lower than most of you had anticipated, and this is largely as a result of our working capital deficit increasing a good bit quarter-over-quarter, really based on the timing of our drilling and completion activities and the high level of activity we had in process over quarter end. We would expect this working capital deficit to be worked down a little bit, and [ necessary ] draw-ins to increase a bit over the coming months and by year-end.

With that, I will turn over to Frank for closing remarks.

[Frank Lodzinski, executive]

Okay. Thanks, Mark. Look, as we described this morning, we continue to demonstrate our operational strength and capabilities with lower cost on our drilling and completion activity and being ahead of schedule. We're positioned for meaningful production growth in the fourth quarter and heading into 2020. We intend to continue to demonstrate our ability to increase wellhead economics and generate peer-leading returns.

In addition to focusing on those things that we can control on a day-to-day basis and executing our operating strategies, we continue to actively pursue accretive M&A activities that would drive shareholder value higher. Our strong balance sheet and liquidity provide us the ability for us to expand our footprint. We just need the logjam out there to break, but we're not going to overpay or sacrifice our strong balance sheet. Without a doubt, we believe that across the board, we have the right team with the right skills to evaluate and execute a major acquisition or merger. We've done that before. Plus, we have an outstanding team with proven ability to operate assets efficiently, effectively and to drive attractive returns, whether they'd be on existing assets or newly acquired ones. Also, we've done that before. In the meantime, we'll continue to enhance, develop and exploit our existing assets.

Before I open the line to questions, I'm going to go off script just a bit and address an issue that one of you all -- or a matter that one of you all have brought up yesterday, and that is consistency in spending activity, completions and financial measures, such as EBITDAX and earnings.

As we've advised, our profitable growth this year provides an opportunity for us to revert to a constant 1-rig program in 2020, and we currently project reaching free cash generation over capital expenditures in the latter part of the year. However, we continue to increase efficiency and reduce costs, and as we do that, it's highly important to have multiple wells to complete at one time. Again, to get the maximum efficiency and the best cost advantages. That impact -- that could impact reported production from quarter-to-quarter throughout the year. Nevertheless, we intend to structure our activities to be as consistent as possible, but to maximize our efficiency and returns, and we'll work hard to keep the market appropriately advised.

Thanks for listening, and we'll now take your questions.

[Operator]

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

[Neal Dingmann, analyst]

I think my first question is probably, Robert, for you maybe. Could you speak more about Mark's just recent comments that you're running ahead with the drilling currently enabled you to drill more before year-end? I guess, what I'm kind of particularly looking at is, maybe could you talk about how many additional wells this might imply? And what this might imply for early -- the impact on early 2020 operations?

[Robert Anderson, executive]

Neal, it probably -- I'll bill it kind of in reverse order. It won't probably have much impact on 2020 in terms of at least bringing wells online because, as Frank just stated, we like to have a group of wells in the queue to go out there and frac just because of operational efficiency and driving costs down. And we've done that all this year, and that's why we ended up with a pretty back end-weighted with the wells coming online. It's likely we'll have a couple of wells down before year-end, and we'll be a couple of wells therefore ahead of the plan. But materially, I don't think it's going to change the ultimate CapEx, because what's going to drive that more so is what happens to this non-op pad if they actually get some fracs started in the -- in December. And we won't know that until we get through the end of the drilling phase, which will happen here in the next month or so.

[Neal Dingmann, analyst]

Got it. Got it. And then my second one, just a follow-up, probably for Frank. Frank, I couldn't help but notice that with one of your large owners, with EnCap, had filed a 13D, not only with you all, but with some of their other portfolio companies. And I'm just wondering, is there any implication there? Or if you could just talk about your thoughts around that?

[Frank Lodzinski, executive]

Sure. So look, I think, EnCap -- you're talking about EnCap, and of course, they've filed the 13D for all the public companies where they have an equity position. And we're, of course, one of them and a sizable one with our equity involvement. Look, the filing is just to provide the market with full disclosure that our largest shareholder, along with the Board and management, are focused on maximizing shareholder value. So it's really just legalities, and we're always talking to them and our Board about where we see opportunities to increase shareholder value. So it's nothing more than that.

[Operator]

Our next question comes from Brad Heffern with RBC Capital.

[Brad Heffern, analyst]

I think maybe for Robert. During your M&A commentary, you talked about you continuing to look at Permian acquisitions, and then you also said potentially Eagle Ford as well. I'm just curious how you think about the balance between the economics of doing an Eagle Ford acquisition versus sort of the investor preference for Permian?

[Robert Anderson, executive]

Good rock probably has good economics in both places, and it's somewhat opportunistic. It's not like we're having -- we have a capital allocation between the 2 areas. We're spending a little bit of time in the Eagle Ford looking at opportunities, and we're spending more time in the Midland Basin looking for opportunities. But we're going to let the opportunity drive sort of the answer there. And if we can find the right rock, the right PDP and running room, combination and asset, then, whether it's in one base or the other, we're a little bit agnostic.

[Brad Heffern, analyst]

Okay. Got it. And then you mentioned you guys have laid down the Permian frac crew. When is that coming back? And sort of what is the turning line cadence look in the first half of '20?

[Robert Anderson, executive]

Yes. We're still putting that all together. We've got a schedule, but I think we've got some room to tweak that a little bit. So at this point, we -- the preliminary schedule is we could have some fracs done in January, February time frame, and then take another break and then do some more later in the end of the first half of the year. But right now, it's still kind of up in the air. We've got the frac company and us working together on the schedule. It's not like we don't have access to them. It's just trying to fine tune it now.

[Mark Lumpkin, executive]

And Brad, I would just add. In terms of that, I mean, what Rob is referring to is when we realistically could get some of the fracking done As you know, there's typically a bit of a delay between when you frac internal line. If you're thinking about how to model that, I would add 30 to 45 days.

[Brad Heffern, analyst]

Okay. Got it. And then just one clarification. So on the TSRH pad, you talked about the wider spacing. I think you said 1,100 feet end zone. So just to verify, like from a bird's eye view, that would be 660? And just in the upper and in the lower there, 1,100 feet apart. Is that correct?

[Robert Anderson, executive]

Yes. There are actually 550 feet between wells, is the way to think about it, Brad.

[Brad Heffern, analyst]

Yes. Sorry, I just can't do math.

[Robert Anderson, executive]

Yes. No. I knew what you were talking about. Yes, 550 between wells, 1,100 in the same bench. Old wells were done at 925 between benches, and so whatever that is, 437.5? No, it's not. It's 467.5 between wells in total. So keep in mind that the TSRH pad that we just drilled 1,100 feet apart is on the far western side of our acreage position, versus the older wells are on the far eastern side of position. And so we put this test down to really give ourselves a good view of spacing.

[Operator]

Our next question comes from Jeff Grampp with Northland Capital Markets.

[Jeffrey Grampp, analyst]

If I'm looking at Slide 12 here and tracking your DC&E costs relative to the target they all are going for, just kind of wondering, what kind of bridges that last about $40 a foot? What kind of do you guys need to see or accomplish operationally to get to that target? And is that achievable in kind of the near-medium term? And just kind of set expectations for how to think about 2020 costs.

[Robert Anderson, executive]

Yes, that's a good question, Jeff. So what really drives capital efficiency on the drilling side, or is very helpful, is the number of wells per pad. And we drilled 3 pads with 2 wells each, and then a single this year -- or they were all completed this year, or will be. And that is less efficient than 3, 4, 5 wells per pad. And our 2020 plan has either 3 and then 5 and 6 well pads that will get us most of the year's completion activity for 2020, and maybe 2 more on top of that. So that is one of the keys.

Probably the next one is lateral length as we continue to keep the momentum up of drilling longer laterals. That also drives down. So those 2 in combination really drive down the cost. The wells that we've drilled in Reagan County over the last 10 wells or so, we had a pad where we're probably going to be under our target and a couple of pads right at target, and those were 2 or 3 well pads. So we're continuing to drive down the cost by that efficiency.

[Jeffrey Grampp, analyst]

Got it. Great to hear. And maybe switching over to the operating cost side. And Mark, you touched a little bit on this in the prepared remarks. But just trying to get a better handle on how we should think about kind of LOE trend in the next few quarters, given kind of the impending production ramp that we should be seeing.

[Mark Lumpkin, executive]

Sure. Maybe I'll pick up on that one. Robert can add, if he'd like to. So obviously, with the fourth quarter coming up, and we've got a bit of a step change from production levels. We'd expect the -- while the total LOE number on absolute basis should go up a bit with incremental wells online, we'd expect the kind of per BOE cost metric to improve. And we still feel like we're kind of in that range that we gave on guidance. So nothing really drastically different than that. I think that's probably not a terrible starting point for next year. So with additional volume, it's probably a bit lower than the range of guidance we have for this year. But we're also, right now, not modeling that it's going to hit $5 or $5.50 next year either.

[Frank Lodzinski, executive]

Jeff, this is Frank. This is Frank. I walk in here every day and tell them, we got to get down closer to $5. So we'll keep working on that.

[Jeffrey Grampp, analyst]

Sounds good.

[Operator]

Our next question comes from Jason Wangler with Imperial Capital.

[Jason Wangler, analyst]

Maybe just following up on that, with the LOE side. Can you maybe talk about -- obviously, higher production should help that. But are there any certain things that you guys are kind of focused on to drive that lower?

[Robert Anderson, executive]

Yes, Jason, this is Robert. One of the things that we're really focused on is our chemical program. We took over these assets in 2017. We had a good run with a bunch of new wells for a period of time. And then as you would expect, like we all do when we get older, things start breaking down. And one of the things we can be proactive about is our chemical program, treating for scale and corrosion. So we've got a group or a team in our field office working through that, trying to figure out the best program. Winter time is a little bit more expensive from a chemical standpoint, even though we're in the Midland Basin, for the most part. Yes, winter does create some problems there. But we'll handle that again with chemical and just having guys in the field work every day to try and keep the cost down. So that's the biggest thing for us right now is looking forward on our chemical program.

[Frank Lodzinski, executive]

Which, of course, over time, gives you essentially longer run times. And you don't have to pull your tubing as often and so on and so on. So once you get that all working -- I'm just making this up for illustrative purposes, but instead of having to pull a well every 18 months or something and replace a few joints, you try to swap that out to 2 years or 3 years, and it all adds in there.

Second thing is that we're really built for 20,000 BOE a day in the office and in the field, and your office costs and your field costs are not linear variables or step variables. You got to make sure you have the people, the infrastructure, the systems and so on. So I think we're going to see -- or at least, I'm hoping that we do as in prior companies, and that's why I'm harping on trying to get the thing down closer to $5 or even below over the course of next year. Just keep on working on it every day like we've done in prior entities.

[Jason Wangler, analyst]

I appreciate the color. And then, Frank, as you talk about M&A, and you kind of mentioned that Eagle Ford as well as Permian, as you've been looking out there -- I don't know how specific you can obviously be, but is there a significant difference outside of price, obviously, but even the availability of deals out there? Just maybe how you kind of compare and contrast the 2 landscapes as you kind of stay out looking forward?

[Frank Lodzinski, executive]

Well, I mentioned the logjam. I think the -- I think that there's still quite a bit of buyer and seller difference when you're talking to private companies out there. Clearly, we don't want to over-lever, and clearly, we don't want to use too much of our equity, but we will use some of our equity for the right deals. So it's very, very difficult when you're talking to private companies or portfolio companies of PE firms. I'm not so sure that, in that context, it's any different. If you have a Permian Basin company or an Eagle Ford company, if it makes sense, other than the Permian guys are a little bit prouder because of more stacked potential.

And the real key, and you folks on your capacity and the other analysts on here, are probably even better to consider, but the other key is, you stand a chance of putting together a public-to-public thing. But you have the same old issues in public-to-public: mutual valuations, management, social equations and so on. You can probably count on 2 hands the amount of public -- maybe even one hand, the amount of public companies that are out there. And that's the landscape right now. So it's difficult, but we are -- Jason, we're out there all the time talking to people. And to bring up Neal's previous question about shareholder return, we've done mergers in the past, where we are the surviving company. And we've done mergers in the past where we're not the surviving company. So we're going to continue to consider all of that from the perspective of building shareholder value, and we are shareholders. So that's meaningful to us. So I don't know.

[Operator]

Our next question comes from John White with Roth Capital.

[John White, analyst]

Congratulations on the really [indiscernible] quarter. On your big Wolfcamp A well in Howard County, was there -- or any other wells that were drilled during the quarter, whether operated or nonoperated, are there any significant changes in the drilling and completion practices that you'd like to highlight?

[Robert Anderson, executive]

Thanks, John. This is Robert. We are constantly, on our side, from an operated standpoint, looking at making minor tweaks to our frac recipe, whatever that might be. And there's some stuff that we do that is maybe a little different than other companies, but not necessarily, I'll call it, proprietary. It's just maybe some of it is the efficiency that we've gained by trying some different things. But I won't say that any of that had a direct impact on -- it's not like we fracked a well with 5,000 pounds of sand and 100 barrels per foot of water or something like that. It was the same recipe generally used between us and the same recipe that our nonoperator had been using on our Wolfcamp A well. So we just knew we had good rock there and we got good results.

[John White, analyst]

Well, your tweaking pays off. So keep at it.

[Robert Anderson, executive]

You bet.

[Operator]

[Operator Instructions] Our next question comes from Noel Parks with Coker & Palmer.

[Noel Parks, analyst]

I'm going to ask a question in the same neighborhood as some of the other past ones. But just as a reality check, when you talk about the advantages of scale -- and Frank just gave the example of being built really to do 20,000 barrels a day and the overhead that goes with that in terms of people and facilities, offices and so forth, what piece of the cost or efficiency puzzle would most improve with scale from here? Certainly, covering the overhead is one, but I just think about how far down we've come in service costs, and of course, speed is still -- benefits of speed are things you're -- I guess, you can learn and achieving as you're just running a single rig. So kind of what's the opportunity to be harvested if you did get a good deal bigger from here?

[Frank Lodzinski, executive]

Well, look, we look at that all the time. And as you know, from prior companies, what we do here in terms of driving down drilling and completion cost and operating cost and G&A cost per BOE is something that we've always worked on in prior public companies and in this one and so on. No, I don't think it's any one thing. I think the trick with this management team here and what we've done over the years of working together is continue to look at all facets across the board, being the drilling and completion activities. Robert and I were just out in the Midland Basin, and I mean, this may sound corny, but you go out there and you meet with all your field people. And you pat them on the back for doing a good job, and you say that improvements come from the bottom-up and the top-down and sideways. And then you install some new software, so we can focus more clearly and they understand where we can drive down the absolute LOE cost. So it's really across the board in all of them.

Now I will say that once you have the infrastructure built in the field, you can go to -- do we have to add very much infrastructure if our exit rate's going to be 15,000 BOE a day and we achieve 18,000 or 20,000? No. We don't have to add a lot of people, infrastructure, fixed costs in the field, et cetera. But then that next group from 20,000 to 25,000, I'm just making this stuff illustrative -- for conceptual illustrative purposes, that's run at 20,000, you're going to incur some more fixed costs, so you got to ramp up that variable cost.

The biggest thing that I'm so proud of our folks, and a lot of these folks are the same people that have been with me for 15 or 20 years or more, is we're just not -- our officers, our senior people are out there on location, fracking those wells and watching the rigs and so on and so on. And I just kind of tend to think you lose a little bit, even with the Internet in the communications, between the field and the office, 600 miles away or 700 miles away. So there's no one thing. It's looking at it all. So long-winded way of saying it's everything.

[Noel Parks, analyst]

Right. Well, just as an example, it seems like the days when sand availability and sand costs were a big preoccupation. Seem like they're so far in the rearview mirror, but it wasn't all that long ago. Is there anything on the material side? Or I don't know, maybe on the water handling side? Is any improvement still to be made there, would you say?

[Robert Anderson, executive]

Well, Noel, this is Robert. With scale, you definitely have some pricing power, right? And that would be beneficial to some degree, whether -- and it would cover all facets of your business. Because running multiple rigs, you could have more pipe, therefore, you get a bigger discount. Whatever it might be. The other thing is that we wouldn't focus -- and you guys probably wouldn't focus on individual well-to-well activity to be more focused on -- okay, we brought on 10 wells in the quarter, and it would have less impact if we had downtime related to a frac hit somewhere else if we add more and more scale, which is what we're trying to do. And that kind of goes along with what Frank talked about early is consistency. And it would make your life a little easier, and probably ours, being more consistent from quarter-to-quarter if we had more scale. We can be very efficient. As small as we are, we can be very efficient. I think we've proven that, and we've talked about it over and over again. But with scale, it would even be better from that consistency and growth standpoint.

[Noel Parks, analyst]

Okay. And just that, please, remind us. One last thing. Talking about private companies in the environment. Anything on the sort of on the order of farm-in type opportunities where if folks can't get to a valuation that they like to let go of assets, maybe taking in and letting them sort of reduce their operating teams, but with kind of the current ownership, is that feasible?

[Robert Anderson, executive]

It is. And we are working on several different things, and there's private and probably some public opportunities where, whomever it is, the operator is not going to get to all their acreage. And you're right, they probably don't want to sell it. So is there a way we could do some structured [ farm-in ] to earn our way into it? And we are looking at that particular structure as well on things we have on the board.

[Operator]

Ladies and gentlemen, there are no further questions at this time. I'll turn the floor back to management for some closing remarks.

[Frank Lodzinski, executive]

Well, all we have to do is say thank you, and we hope to be here in a few months, telling you about the fourth quarter, equally good or better. Thank you.

[Operator]

Thank you. This concludes today's conference. All parties may disconnect. Have a great day.