Earthstone Energy Inc

F:BSC2

Earnings Call Transcript 2020-Q3

[Operator]

Good morning and welcome to Earthstone Energy's Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the former presentation. [Operator Instructions] As a reminder, this conference call is being recorded.

Joining us today from Earthstone are Robert Anderson, President and Chief Executive Officer; Mark Lumpkin, Executive Vice President and Chief Financial Officer; and Scott Thelander, Vice President of Finance.

Mr. Thelander, you may begin.

[Scott Thelander, VP, Finance]

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 and Section 21E of the Securities and 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 and in our annual report on Form 10-K for 2019 and subsequent quarterly filings. 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 to be incorrect, actual assumptions 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 5, 2020. 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 on our earnings announcement released yesterday. Today's call will, today's call will begin with comments from Robert Anderson, our CEO, followed by remarks from our CFO, Mark Lumpkin, regarding financial measures and performance and then some closing comments from Robert.

I'll now turn the call over to Robert.

[Robert Anderson, President and CEO]

Thank you, Scott, and good morning, everyone. Thanks for joining our third quarter conference call. As you can see from our earnings announcement released yesterday, we had another strong quarter with outstanding operational and financial performance driven by solid production, continued cost reduction and our favorable hedge position. We have generated significant free cash flow for the nine months of this year, including almost $34 million this quarter alone. This has been used to reduce our debt outstanding along with our working capital deficit. Mark will give you the details shortly, but we are well on our way to being less than one times levered at year-end.

Third quarter volumes came in at almost 17,000 BOE per day, which nearly matches our company record high achieved in the fourth quarter of 2019. And it's up 8% from the first quarter and significantly up from the second quarter when we had almost 60% of our production shut in for about a month. Our oil volumes have been tracking our forecast or even slightly above while our gas and NGL volumes were much higher because of lower gas stream decline rates compared to our internal forecast. Given that we are tracking to beat the high end of our full year guidance, we have increased our production guidance for the year, as outlined in our press release.

We continue to focus on the cost side of our business with all of our employees contributing to both operational and corporate expense reductions. With sustainable cost reductions in place, we have also provided an update to our lease operating expense guidance, which we have lowered. For the quarter, lease operating expense came in at $4.51 per BOE, which is $2 per BOE below the first quarter and slightly below the second quarter. This represents an all-time low for Earthstone.

We have made similar strides on corporate costs with cash G&A also coming in at an all-time low in the third quarter at $2.18 per BOE. Some of you will recall that in 2019, we hit our long-stated goal of achieving LOE plus cash G&A of below $10 per BOE, which we did for the first time at $9.72 for the full year of 2019. And we have now driven that number lower each successive quarter this year, hitting $6.69 per BOE in the third quarter.

We also announced that we have begun completions on our six well Ratliff pad in Upton County, in which we hold 100% working interest and target having them online around year-end. Associated with this resumption of completion activity, we have updated our capital guidance for the year to a range of $65 million to $70 million. The increase reflects approximately $18 million to $20 million of incremental expenditures for these completions, but is partially offset by our being below our previous guidance range.

We also plan to complete the five well Hamman pad in Upton County in the first quarter of 2021, in which we hold a 75% working interest. Our decision to proceed with completion activity is reflective of a much improved commodity price environment compared to the spring when we made the decision to halt all drilling and completion activity. Compared to earlier in the year, we estimate that cost for completions are down 25% to 30%.

As a result, we expect rates of return on the incremental completion CapEx to be well over 100% on these completions. When adding in the actual historical drilling costs, we expect these 11 wells to generate returns of around 35% to 40% at current strip prices. As an aside, the drilling costs currently we view as being down a similar percentage as the completion costs.

As we have mentioned before, completing these 11 wells on this time line is expected to keep production relatively flat in 2021 as compared to 2020. As we get closer to the end of the year, we are beginning our operational planning process for 2021. Considering our strong financial position, the quality of our inventory and the continued positive shift in economics of drilling and completing wells, we are considering resuming our drilling program next year.

A number of factors will go into this decision as we move through the remainder of this year and early next year, including the volatility in commodity prices, service costs and the quality of available service providers. At this point, we are going to remain flexible and not make any financial commitments until late this year, early in 2021.

With that, I'll turn the call over to Mark to review the financials.

[Mark Lumpkin, EVP and CFO]

Thank you, Robert. Let me start with some comments on our balance sheet. We're pleased that for the second consecutive quarter, we've generated substantial free cash flow, which came in at $33.8 million in the quarter. That brings us to just under 20, just under $70 million of free cash flow in the second and third quarters combined.

As you all know, we've been focused on debt paydown with our free cash flow, and we were able to reduce our activity and estimate around $20 million of capital expenditures during the fourth quarter, we still expect to generate free cash flow and pay down our revolver further. Even with less debt paydown in the fourth quarter, as we incur completions capital expenditures, we do expect to achieve our target leverage ratio of one times or better net debt to adjusted EBITDAX at year-end 2020. With $110 million of unused borrowing capacity on our $240 million borrowing base and $5.3 million of cash on hand, we had approximately $115 million of liquidity at quarter end compared to $108 million at the end of the second quarter. And we expect that liquidity number to grow with further debt paydown in the fourth quarter and into next year.

Now looking at our income statement, starting with the top-line. Revenues for the third quarter of 2020 were $41 million compared to $21.7 million in the second quarter. This represents an almost 90% sequential increase, which was driven by improved commodity prices and higher production compared to the second quarter, which, as you recall, during which we shut in about 60% of our production in May. From a revenue composition standpoint, oil revenues comprised about 81% of total revenues, NGLs comprised about 13% and natural gas comprised about 6%. Our average price in the third quarter for all three commodities was $26.31 per barrel of oil equivalent, which was up 50% from our average price during the second quarter. By commodity, our average realized price for crude oil in the third quarter was $39.50 per barrel. Natural gas averaged $1.31 per Mcf and NGLs averaged $13.60 per barrel.

From a production standpoint, our third quarter sales volume averaged 16,959 barrels of oil equivalent per day, which was comprised of 54% oil, 21% natural gas and 25% natural gas liquids. As Robert mentioned, our natural gas and NGLs production has not declined as rapidly as we previously expected. So we're seeing higher gas and NGL production than we expected, which is great to see. At the same time, oil is tracking nicely.

But this does result in a decrease in the oil percentage and should do so until we bring on new wells around the end of the year. On the expense side, on a per unit, our all-in cash cost, which includes lease operating expense, production and severance tax, cash G&A and interest expense, decreased to $9.18 per barrel of oil equivalent. This represents a 29% decrease from the first quarter and a 9% decrease from the second quarter. Our lease operating expense came in at $4.51 per BOE, which is a 31% decrease compared to the first quarter and just slightly below the second quarter cost.

As Robert noted, given our success in managing LOE costs and strong production levels, we have lowered our cost guidance for the full year for 2020, which is now at $5.25 to $5.50 per BOE. On the general administrative side, we reduced the third quarter per unit cash G&A expense to $2.18 per BOE, which is a 30% decrease from the first quarter and a 35% decrease from the second quarter. From an income standpoint, we reported a GAAP net loss in the third quarter of $11.9 million or $0.18 per share, which included a pre-tax unrealized loss of $14.5 million on our derivative contracts.

Our adjusted net income was $3.7 million or $0.06 per diluted share in the third quarter. Despite no new wells online since late March, we reported adjusted EBITDAX of $36.4 million in the quarter, which was a slight decrease from both the $38.2 million generated in the first quarter and the $39.8 million generated in the second quarter. On the commodity hedging side, we realized an $8.5 million gain on our commodity hedges for the quarter.

We remain really well hedged for the balance of the year with an average of 6,000 barrels a day of oil swapped at an oil price of a little over $60 a barrel. And that steps down to 4,000 barrels a day for full year 2021 at a price of a little over $50 per barrel. And in both those periods, we do have basis hedges on approximately the same volumes. On the natural gas side, we have 7,000 MMBtu per day of swaps at Henry Hub priced $2.85 per MMBtu for the remainder of the year, and that steps up to 12,000 MMBtu per day at a price of $2.76%, $2.76 per MMBtu for full year 2021. And again, there, we have similar volumes hedged on WAHA basis.

As Robert mentioned, with our production year-to-date tracking above our guidance pretty handily, we've increased our full year 2020 guidance on production to a new range of 14,000 to 14,500 BOE per day. We've also changed the commodity mix with oil now being 58% to 59% of production for the full year. We do expect to see a natural decline in the fourth quarter given our DUC completions won't contribute much, if any, to fourth quarter production. And in addition to that, we've got about 800 BOE per day mostly oil production shut in near the pad we are fracking that will adversely affect the fourth quarter volumes. We've also updated our capital expenditure and lease operating expense guidance, but I don't think I'll reiterate those details as Robert has already covered them.

With that, I'll turn it back to Robert.

[Robert Anderson, President and CEO]

Thanks, Mark. While the industry has recovered from the lows we experienced in the second quarter, there's still a lot of uncertainty, both broadly speaking and specifically as it relates to commodity prices. We are fortunate to be in a position of having a strong balance sheet, a low-cost corporate and operating structure that has allowed us to continue strong free cash flow generation that we are using for paying down debt and deleveraging in this commodity price environment. We will continue to consider options for our cash flow generated in 2021 with the most likely scenario being a combination of debt reduction and a capital program delivering compelling economics.

We continue to actively pursue profitable acquisitions while maintaining our historically disciplined operating, technical and financial approach to these evaluations. We're definitely seeing continued flow of opportunities, most of which are in some stage of distress, but we are optimistic that we'll be able to add scale in this environment and drive shareholder value. Before turning it over to questions, I know you guys have all had a long day. But lastly, I want to thank our employees who have really done a fantastic job in a challenging environment over the past two quarters to get us where we are today.

With that, operator, Kevin, let's turn it open to questions.

[Operator]

[Operator Instructions] Our first question today is coming from Neal Dingmann from SunTrust. Your line is now live.

[Neal Dingmann, SunTrust]

Nice update, guys. Robert, my question is, I know you don't have detail, let's say, too detailed '21 plans out. You do have some guidance out. Could you maybe try to give a little bit of how you think about goalpost next year? And I guess what I'm getting at is, you've kind of outlined, if you just do the DUC sort of job next year, if you just finished those, how you guys are thinking about production and CapEx. But I'm just thinking, I guess, to me that would be the one end of the goalpost. I'm just wondering, would the other, would that consider adding up a one, or would you consider a two rig program? Or maybe how you're thinking about next year because, again, obviously, with your incredibly low spend, I think you have some advantages maybe that some others don't.

[Robert Anderson, President and CEO]

Yes. That's a good question, Neal. And obviously, we don't have all the details figured out yet. But you've got it right. We'll complete the other wells in the first quarter. That keeps us flat in terms of production year-over-year or relatively close to it. And that's a pretty good baseline. And then we are considering what we would do with adding a rig and timing of that. I don't see us going to two rigs. And I don't see us starting in January with a rig.

So it'd probably start within the first half of the year is one scenario. And we could drill 9, 10, 15 wells, depending on the timing. We wouldn't get all those completed. And that, one of the keys to that is to continue to live within cash flow. So we're not going to outspend in 2021, irrespective of when we pick up a rig.

[Neal Dingmann, SunTrust]

Okay. And then you and Mark, so just on the decline helped by, obviously, given what the gas, what gas was going on with the gas part of the well. Could you talk about how you see sort of maybe your baseline decline? It seems like, I don't know, one, maybe what it is? And two, are there, would you consider other things you can do, a refrac or whatever, to maybe even help that stay even more stable? Or is that even necessary?

[Robert Anderson, President and CEO]

Well, like I said, we can definitely keep production relatively flat by just completing our, these 11 wells, six this quarter, five in the first quarter. And that, the fact that we haven't had any completions since about March time frame, or maybe it was April, drove our oil percentage as a total, compared to our total production down, right? Bringing on new wells always have higher oil components.

So I think we could look at some refracs, probably more applicable in the Eagle Ford than it is in the Midland Basin. But right now, I feel pretty good about our baseline plan of just completing these other five wells and maintaining production and having a significant number, significant amount of cash flow.

[Neal Dingmann, SunTrust]

Okay, great. Love the plan. Thanks, guys.

[Mark Lumpkin, EVP and CFO]

Hey, Neal, it's Mark here. Maybe I'll just add a couple of things. Like starting with no rig added for 2021, the CapEx is really small because it's basically just those five completions. For the fourth quarter, if we're sort of saying, hey, we've got 6, 100% working interest completions, and it's about $20 million, for the first quarter is $3.7 million net. But they're also short laterals, so sort of $10 million.

I mean that's sort of like the starting point of, if you don't do anything and we just produce things out except for the DUCs, I mean you've basically got $10 million of CapEx for next year, and you're paying down debt at a pretty good clip. Like if you think about where costs are now, Robert mentioned the D&C costs are down probably 25% to 30% versus what they were at the beginning of the year.

Yes, I think probably at the beginning of the year, we would have said, well, hey, running a rig for a full time, a full year and completing, which would assume you've got some DUCs in the inventory and you're completing all years as well was somewhere around the $140 million to $150 million range. If you were doing that for a full year now, we think it's probably $110 million a year. But if we're picking up a rig in the spring, let's just say -- let’s say, it’s in the middle of April. You figured that in April, while you're probably drilling for four to six months before you start any completions, you're not going to get anywhere near that sort of full year drilling and completion CapEx of $110 million.

Now if we do that, I mean, that's sort of a way you could think of one rig in 2022 with the full year completions. But looking at taking a rig up some time in the spring and starting completion sometime in the fall, I mean you're probably talking about something that's more in the sort of, yes, $60 million to $80 million of incremental CapEx for the year, depending on the timing and the completions, etc. So even in that case, you kind of take that, you add the $10 million for the DUC completions, there's still a pretty decent bit of free cash flow on top of what that spend would look like.

And in that case, I mean you hold production flat, how much of an impact you get from new wells late in 2021 sort of be -- TBD, probably a little bit, but not a massive step change. And then, of course, if you hold that pace, you get into 2022, and you've got a bit more growth, but still free cash flow positive.

[Operator]

Thank you. Our next question is coming from John Dun McIntosh from Johnson Rice & Company. Your line is now live.

[John Dun McIntosh, Johnson Rice & Company]

Good morning, Robert.

[Robert Anderson, President and CEO]

Hey, Dun.

[John Dun McIntosh, Johnson Rice & Company]

Congrats on another really strong quarter. My question I guess is -- you touched a little bit on the M&A side, and we've seen some interesting deals kind of in the small-cap space in the past few weeks. You all aren't anywhere near in the situation that some of those guys were. But how do you think about M&A or A&D, I mean smaller packages or maybe smaller PE groups? I mean would equity be the currency of choice? And just kind of what are you seeing from an opportunity set there?

[Robert Anderson, President and CEO]

Yes. Good question, Dun. Equity would be the -- seems like there's a lot of feedback, so I'll let somebody go on mute. Equity would be the choice based on a sizable transaction. I don't know what sizable really means. But if it's small enough, we've got liquidity in our revolver and the ability to use that for transactions. And a $10 million deal, we're not going to use equity.

So I think there are a number of opportunities that will present themselves as we get closer to the end of the year and roll into next year just with the state of many of our peers out there and the distress that's in the system and where revolvers are going to come out in the fall. So we think there's a good pipeline of opportunities, and we actually have stayed very busy evaluating a number of different opportunities.

[John Dun McIntosh, Johnson Rice & Company]

Okay. Great. Thanks. And then just for a follow-up, yourselves and most of the industry has been pretty surprising with what they've been able to do on the cost reduction from an operating cost standpoint. Can you just talk about some of the efforts you made there and how sticky you think some of these cost reductions could be even with lower -- on a unit -- how do you think about it trending on a unit basis if production is -- does kind of stay flat next year?

[Robert Anderson, President and CEO]

Yes. That's a good question. If production stays flat and prices stay about the same, then LOE ought to continue to trickle down a little bit. But if we get an improvement in oil prices, we're going to see a little bit of pressure from the service companies, and our lease operating expenses are liable to trickle up a little bit because some of those costs are directly related to where oil prices are. We've been able to do a number of things, though, operationally that we believe are sustainable and, as you say, sticky. And part of it is the life cycle of these wells that we have in the Midland Basin where we're on gas lift originally, or initially, and then over time, we can reduce that into a gas-assisted plunger lift or plunger lift, in both cases, reducing the cost. And long term, the impact of that is quite substantial on LOE and doesn't have any effect, at least in the near term, we haven't seen any effect on the work we've done on production. So we believe that there are some other low-hanging fruit out there in order to save costs, and some of it is sticky related to what we've done, and then some of it is going to bounce up if oil prices come up.

[Operator]

Thank you. Our next question is coming from Jeff Grampp from Northland Capital Markets. Your line is now live.

[Jeff Grampp, Northland Capital Markets]

Good morning, good afternoon. Maybe to build on kind of the last point you were hitting on with the cost stickiness, but maybe on the capital side, can you touch on you know the sustainability of what seems like some rock bottom service pricing from you guys as we look into '21? And I guess how comfortable are you guys underwriting these types of well costs when you're assessing kind of the return profile of bringing the rig back to work?

[Robert Anderson, President and CEO]

Yes. A great question because it is a little bit of a risk. And we, obviously, when we look at economics, we plow in a couple of different scenarios, and we have a base and then we add to that in terms of CapEx, and we'd reduce type curves and look at sensitivities and everything like that. And we've been pretty good over the last couple of years of staying very close on average to our AFE capital costs. And some of that is some success in timing of when they're put together versus when we actually do the work and a reduction in certain pieces like the frac side of prices coming down. But it's just something we'll have to evaluate as we get closer to that decision of putting a rig to work.

Right now, I feel pretty good that where we are, we're pretty rock bottom. And I suspect as we get into '21 and there's a little bit more demand for services, that we'll see some inflation related to wages and maybe even on the frac side. So one of the reasons we decided to kick off this frac program a little earlier than maybe what some of you might have imagined was because we got the team we wanted at a really good price. It was the same group that we've been using last spring. And with that being an important factor in our execution, we decided to pull the trigger and start completing wells. So all that goes into the decision-making process.

[Mark Lumpkin, EVP and CFO]

Jeff, it's Mark here, sort of dumb finance guy, big picture math. Like you think to the beginning of the year, let's say we were looking at $50 strip and that I think in January, it was probably closer to $55. But say, we're looking at a $50 strip, we felt pretty good about the economics of our drilling program on a $50 strip. If you think about today, I mean we think that drilling completion costs are down by at least 25%. So if you sort of just take 25% off of the $50 oil price, that's $37.50. You know, at $37.50 or $40, which is about where the strip is now, we feel pretty good about the economics now and not that different than we did at the beginning of the year, thinking about a $50 strip price. So if the strip is $40 now and it goes up $5, that's a, what, a 12% increase in the strip. If service costs come up 12%, it's sort of a wash there. So we feel really good about what it looks like right now. And certainly, if there's a little bit of pricing pressure on the service side because oil prices are up $5, we think that's pretty manageable from a maintaining similar better economics.

[Jeff Grampp, Northland Capital Markets]

Sure. And dumb guy math is the only math I know. So it works for me. And Robert, can you remind me, if I recall, kind of heading into 2020, you guys were able to kind of reconfigure some drilling commitments or lease obligations that you had; into '21. Is that something you guys, would that kind of dictate where you would put a rig in terms of meeting those commitments? Or would you look to renegotiate with the leaseholders to maybe extend those further? Or can you just remind us kind of the status of how that might influence the decision-making process in '21?

[Robert Anderson, President and CEO]

Sure. We would definitely look to cherry pick our inventory to drill the best economics. And if that is in areas where we've got obligations, that solves the problem. If it's not, then we'll try and find ways to work with owners, landowners in order to extend terms, pay a small fee, what have you, in order to protect that acreage.

As long as we view that acreage as being accretive to our whole plan at some point, maybe it doesn't happen in '21 or '22, but three years from now, we want out there drilling in a $60 price environment, then we'll want to hold on to as much acreage that makes sense. So we've got some options, and we're actually already working on considering some options in a couple of places.

[Operator]

Our next question is coming from Brad Heffern from RBC Capital Markets.

[Brad Heffern, RBC Capital Markets]

Just touching on sort of M&A theme. I mean there's been, to put it lightly, a lot of deals done in the space, and it seems like pretty much everybody is trying to pursue scale. So curious if you can just give your thoughts on if you see Earthstone competing at a scale, is it now? And then how you think about adding scale through sort of acquiring other things which you've sort of already talked about, but how do you also think about it from the standpoint of just selling Earthstone to someone larger?

[Robert Anderson, President and CEO]

Good question. You know, we are building a company here that is long-term investable and run it like we're going to own it forever. But if somebody comes along and says, we like your business because you're generating free cash flow, you've got low debt, you got very low G&A, you know, we're open for business. It's, they're not mutually exclusive. We think we can build a very sustainable, profitable company through scale and consolidation.

And we work on that every day and spent probably more time working on it this year on a number of different opportunities. It's difficult in this environment when companies are under a lot of stress and distress related to their balance sheet. And we're trying to find ways to work through that system or process with them, and it just takes a while in trying to get a deal done. So, you know, we're open to considering either. But I'd say that at this point, we're a consolidator and spend a lot of time working on that. There's also a lot of opportunities outside the public market. I mean there's a big private group of operators in every basin, and we look at several different opportunities related to the private space as well.

[Brad Heffern, RBC Capital Markets]

Okay. Thanks a lot, Robert. And then maybe for Mark, just -- I know you guys said that the gas cuts are going up just because of the wells maturing. But I was a little surprised to see the gas volumes just up in the aggregate and basically the highest quarter you guys have ever had in the third quarter. So I was wondering, was there any sort of like accounting true-up or anything like that that's responsible for that?

[Mark Lumpkin, EVP and CFO]

I don't really think so. Nothing that jumps out to me on that. I mean I will say just generally speaking, if you look at the second quarter, we obviously had production shut in for a good chunk of the quarter, I mean roughly sort of 20% of what it would have been. So you're not really looking at a true sequential comparison versus comparison. That was also right when we brought in the WTG wells, which did really have some nice initial volumes, and they're still looking nice. I mean, honestly, oil came in pretty close to maybe a little better than what we forecast before the quarter. The gas came in a bunch higher than we forecasted.

And sort of our internal discussion is, well, with our senior engineer is, hey, like explain this to me. And it's a little bit of the, well, hey, look, like on some of these wells, the curve on the gas stream, which includes NGLs, it just looks flat. And we're engineers. We can't draw flat curves. I think that, that will sort of wash out. I would no doubt expect that this quarter, we'll have even a higher gas -- a higher percentage of gas than the second -- than the third quarter did just from the standpoint of we shouldn't get any real bump in production from completions at all, if anything.

And they were also -- we'll probably have about 800 BOE a day of production shut-in really for the whole quarter or close to it that offset the fracs we're doing now. That's probably 80% oil, so it's kind of priced 650 barrels a day of oil. That's embedded in our guidance. Yes, if anything, I think we feel really good about what our guidance implies from an oil production standpoint. Is it possible that the gas is a little bit higher than that? Yet, maybe -- financially, I mean, sure, the gas it's nice to have and prices are better and differentials are better, but it just doesn't move the needle. I mean natural gas is only 6% of our revenues in the third quarter. It's not going to be much more than that, though the NGLs help a little more.

[Robert Anderson, President and CEO]

Hi, Brad, this is definitely a function of the types of reservoirs that we're drilling. And as you're -- if you're not bringing on new wells, your gas volumes are going to continue to rise to a certain point and then they level out. So it's not anything unusual.

[Brad Heffern, RBC Capital Markets]

Okay. Yes, okay. Appreciate it, guys.

[Operator]

Thank you. Our next question is coming from John White from ROTH Capital. Your line is now live.

[John White, ROTH Capital]

Good morning, guys. And congratulations. It was a blow-out quarter.

[Robert Anderson, President and CEO]

Thanks, John.

[John White, ROTH Capital]

Hey. On the lease operating expense, is that lower due in part to using employees versus contractors?

[Robert Anderson, President and CEO]

There's no doubt that our employees work really hard and help us maintain a low-cost structure. And in times like this, when we're not as active in the field with new wells coming on, they have a little bit more time on their hands, and we can reduce contract support, and they can do a lot of routine things that we would otherwise have a contractor come help us do. From a cost standpoint, that saves a lot of money. So yes.

[John White, ROTH Capital]

Okay. Thanks. And on the acquisition market from a little different angle, has deal flow improved? Is deal flow higher? Or was deal flow higher in the third quarter versus second quarter?

[Robert Anderson, President and CEO]

We didn't do a deal in the third quarter. We have been busy all year along and we don't necessarily count how many deals or anything like that. I would tell you that when prices are volatile, no matter what we're working on, it gets really hard to do a deal. But I think there is more activity and more folks considering their options and looking at potentially what market valuations are. So I'd say the deal flow is picking up marginally.

[John White, ROTH Capital]

Thanks again. And not a question, but I appreciated your comment about how selective you're being on choosing your frac crews. That's very good to hear. Thanks again.

[Robert Anderson, President and CEO]

Thanks, John.

[Operator]

[Operator Instructions] Our next question is coming from Andrew Bond from Alliance Global Partners. Your line is now live.

[Andrew Bond, Alliance Global Partners]

I just wanted to get a little bit more color on the decision to complete the Upton pad. Was that decision made when prices were slightly higher than where we sit today? I'm just trying to get a sense of whether you still look to turn the remaining five DUCs in the first quarter if prices kind of stay here in the high 30-barrel range or even dip to the mid 30s. Thank you.

[Robert Anderson, President and CEO]

Yes. Definitely, as you know, completing wells is a process, and you've got a lot of logistics and you have to get started early, right? We have to line up a lot of vendors. So we started talking about this probably August, September time frame with no date selected. And then as we got later in September, we picked a date with our vendor team. The next five, we've got some flexibility. If prices continue to dwindle down and get into the mid-30s, we have no obligation or timing that we have to go complete them. So we'll sit back and watch.

Our, we are taking a slight break from the fracking. Once we complete these six wells, that frac company I think is going to go do some work for one or two other operators, and then we would plan to get them back after the first of the year. So we've got some flexibility, and we're not locked into anything.

[Operator]

Thank you. We've reached the end of our question-and-answer session. I'd like to turn the floor back over to Robert for any further or closing comments.

[Robert Anderson, President and CEO]

Thank you, everybody. I appreciate everyone's attendance today and the questions, and we're open if you have some further questions. Thanks.

[Operator]

Thank you. That does conclude today's teleconference. You may disconnect your line at this time and have a wonderful day. We thank you for your participation today.