Q3 2020 Earthstone Energy Inc Earnings Call
Good morning, and welcome to Earthstone Energy's Conference call. At this time, all participants are in listen only mode. A brief question and answer session will follow the formal presentation.
If anyone should require operator assistance during the conference.
Press Star Zero on your telephone keypad as a reminder, this conference call is being recorded joining us today first thought well Robert Anderson, President and Chief Executive Officer, Mark Lumpkin, Executive Vice President and Chief Financial Officer and.
Scott the lender Vice President of finance.
The winter you may begin.
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 27, a of the Securities Act of 933 as amended and section 21 E of the Securities Exchange Act of 1934.
No not at all.
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 Dot Earthstone energy Dot 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 five 2020 that 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 averse Don'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 [noise].
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.
There's 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 time levered at year end.
Third quarter volumes came in at almost 17000 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 and 51.
Cents per BOE, which is $2 per BOE, we below the first quarter and slightly below the second quarter. This represents an all time low first step.
We have made similar strides on corporate costs with cash DNA 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 Ela, we plus cash DNA of below $10 per BOE, we 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 as partially offset by our being below our previous guidance previous guidance range.
We also plan to complete the five well Hammond 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 the cost for completions are down 25% to 30%.
As a result, we 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 similar percentage as the completion costs.
As we have mentioned before completing these 11 wells on this timeline 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 server 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 or early in 2021.
With that I will turn the call over to Mark to review the financials.
Thank you Robert.
Let me start with some comments on our balance sheet. We're pleased that for the second consecutive quarter, we have generated substantial free cash flow, which came in at $33.8 million in the quarter that brings 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 pay down with our free cash flow and were able to reduce our outstanding debt balance during the third quarter by $38.6 million or 23% to $130 million. While we have resumed completion activity an estimate around $20 million of capital expenditures in the fourth quarter, we still expect to generate free cash flow and pay.
On our revolver further even with less debt paid on 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 a $110 million of unused borrowing capacity on our 240 million, our borrowing base and 5.3 million of cash on hand, we had approximately $150 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 pay down in the fourth quarter and into next year.
Now looking at our income statement, starting with the topline revenue for the third quarter of 2020 or $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 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 a $1.31 per mcf and Ngls at.
Average $13.60 per barrel.
From a production standpoint, our third quarter sales volume averaged 16959 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 NGL 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 costs, which includes lease operating expense production in severance tax cash DNA 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 expenses came in at $4.51 per BOE, a day, which is a 31% decrease compared to the first quarter and just slightly below the second quarter costs.
As Robert noted given our success in managing our cost 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 and expenses to $2.18 for B B, 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 18 cents 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 six cents 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 our gain on our commodity hedges for the quarter, we remain really well hedged for the balance of the year with an average of six.
2000 barrels a day of oil swaps at an oil price of a little over $60, a barrel and that steps down to 4000 barrels a day for full year 2021 at a price of a little over $50 per barrel and both those periods. We do have basis hedges on approximately same volumes.
On the natural gas side, we have 7000 Mmbtu per day of swaps at Henry hub price of $2 to 85 cents per MB to you for the remainder of the year and that step up steps up to 12000 Mmbtu per day at a price of $2 and 76% $2.76 per and then B to you.
For full year 2021, and again, there we have similar volumes hedged on what basis as.
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 14000 to 14500 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 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 update our capital expenditure and lease operating expense guidance.
But I don't think I'll reiterate those details as Robert has already cover them with that and turn it back to Robert.
Thanks Mark.
While the industry has recovered from the lows we experienced in the second quarter Theres still 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.
We continue to actively pursue profitable acquisitions, while maintaining our historically disciplined operating technical and financial approach to these evaluations. We are definitely seeing continued flow of opportunities most of which are in some stage of distress, but we are optimistic that we will be able to add scale in this environment and drive shareholder value.
Q.
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. Thank you we will be conducting a question and answer session. If you'd like to be placed in the question can you. Please press star one on your telephone keypad, a confirmation tone would indicate your line is in the question queue. You May press star two if you'd like to request from the Q corporate.
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To be placed in the question Q1.
One moment, please while the poll for questions.
Our first question today is coming from Neal Dingmann from Suntrust. Your line is now live.
Morning, All had nice nice update guys.
Robert Mike My question is.
I don't had detailed.
Two detailed plan at 21 plans out you do EPS and guidance out could you maybe try to give a little bit how you think about goalpost next year and I guess, what I'm getting at is you.
You've kind of outlined if you just do the debt.
Sort of the.
Job next year. If you just finished though is how you guys are thinking about production and capex, but I'm just thinking.
I guess to me that would be the one in the goalpost I'm just wondering with the other would that consider adding up a one or would you consider it 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, though.
Yes, that's a good question Neil and obviously, we don't have all the details figured out yet but.
You've got you've got it right we will complete the other wells in the first quarter that keeps us flat on 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 probably start within the first half of the year is one scenario and we could drill 910 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.
Okay, and then you'd market so just on.
The decline helped by obvious.
Obviously, given what the gas 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 may be what it is and into are there what would you would you consider other things you could do a re frac or whatever.
Maybe even help that stayed even more stable result, even necessary.
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 havent had any completions since about March timeframe or maybe it was April.
Drove.
Our oil percentage in it as a total compared to our total production.
Downright with bringing on new wells always have higher oil component. So.
I think we could look at some refracs, probably more applicable in the Eagle Ford than it is in the.
The Midland Basin, but.
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 a significant amount of cash flow.
Great Love Love the planned thanks, guys.
Hey, Neil Miss Mark maybe I'll, just add a couple of things.
Like starting with no rig it did 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 600% working interest completions and it's about 20 million for the first quarter is 3.7 net but they're also shorter lateral lateral so it sort of 10 million I mean that sort of like the the starting point of if you don't do anything and we just produced things out except for the Ducks.
And we basically got $10 million of Capex for next year, NIM, you're paying down debt at a pretty good clip.
Like if you think about where costs are now Robert mentioned.
The DNC costs are down probably 25% to 30%.
Versus what they were at beginning of the year.
I think probably at beginning of the year, we would've said, well hey, running a rig for full time of a full year and completing which would assume you've got some ducs and the inventories you're completing all yours as well was somewhere around 140 to 150 million range. If you are doing that for full year. Now we think it's probably you know 110 million a year.
But if we're picking up a rig in the spring.
Let's just say, okay, let's say, it's in the middle of April you favour in April while you're probably drilling for.
Four to six months before you start any completions.
So 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 Thats sort of a way you could think of one rig in 2022 with the full year completions.
But looking at.
Yes, picking a rig up sometime in the spring and start completion sometime in the fall I'm sure you're probably talking about something thats more in the sort of yes $60 million to $80 million of incremental capex for the year, depending on the timing in the completions et cetera.
So even in that case, you kind of take that you add the 10 billion for the DUC completions, yeah, there's there's still a pretty decent bit of free cash flow.
On top of what that spend it would look like and in that case.
You hold production flat you know how much of an impact you get from new wells late in 2021 sort of be TVD.
Probably a little bit, but but not a massive step change and that of course, if you hold that pace you get into 2022, and you've got a a bit more growth, but still free cash flow positive.
Thank you. Our next question is coming from John Mackintosh from Johnson Rice and company. Your line is alive.
Good morning, Robert.
Hey, Doug.
Thats on another another really strong quarter.
My question I guess is more you touched a little bit on the M&A side and we've seen some.
Some interesting deals kind of in the small cap space in the past.
Few weeks now yarn anywhere near that the situation in some of those those guys were but how do you think about M&A.
M&A or a endearing smaller packages are maybe smaller peer groups I mean.
Would equity view the currency of choice and just kind of what are you seeing from an opportunity set there.
Yes, good question done that equity would be the.
Seems like there is 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.
10 million dollar 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 enroll into next year just with the.
The state of many.
Of our peers out there and the distressed 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.
Okay, great. Thanks, and then just 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 a from an operating cost standpoint can you just talk about some of the some of the efforts you made there and how sticky do you think some of these cost reductions could be even with lower.
A unit there how do you think about trading on a unit basis. If production is does kind of stay flat next year.
Yes, Thats a good question, if if if production stays flat and prices stay about the same then ela, we audit continued to trick.
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 are 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 in that part of it is the lifecycle 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 Ella.
Lee 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 that is sticky related to what we've done and then some of it is going to bounce up if oil prices come up.
All right. Thank you.
Thank you. Our next question is coming from Jeff Grampp from growth in capital markets. Your line is now a lot.
Hey, guys.
Hi, Jeff.
Morning.
Afternoon.
Maybe to build on kind of the the the last point you were hitting on.
The cost take units, but maybe on the capital side can you touch on the sustainability of what seems like some some rock bottom service pricing for you guys. As we look into 21 and I guess, how comfortable you guys underwriting these types of well costs when youre assessing.
Return profile, bringing a rig back to work.
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 curve as you know and look at sensitivities and everything like that and we.
We've been pretty good over the last couple of years of staying very close on average to our feed capital costs.
And some of that is some success in timing of when they are put together.
Versus when we actually do the work and a reduction in certain pieces like the frac side of prices coming down.
But you know, it's just something we'll have to evaluate as we get closer to that decision as of.
Putting putting a rig to work.
Right now I feel pretty good that where we are we are pretty rock bottom and I suspect as we get into 2001 and there is 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 it.
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 into the decision making process, Jeff its mark here sort of dumb finance Guy Big picture math like you think to the beginning of the year you, let's say, we're looking at $50 stripped out I think in general is probably closer to 55, but say we're looking at our strip yeah, we felt pretty good about the.
Most of our drilling program on a $50 strip.
If you think about today.
I mean, we think that 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 sort of 37 50.
You know at 37, 50, or 40 Bucks, It was which about where the strip is now we feel pretty good about the economics now and not that different than we did at the beginning the year thinking about $50 share price.
So.
If the ship 40 Bucks now it goes up five Bucks and Thats, 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 yes, theres a little bit of pricing pressure on the service side because oil prices are up five bucks a week.
I think thats pretty manageable from a you are maintaining similar better economics sure.
Sure Hey, Dumb Guy math is the only math right now so that works for me.
And.
Robert can you remind me.
I recall kind of heading into 2020, you guys were able to kind of reconfigure.
Drilling commitments or lease obligations that you had and 21.
Is that something you guys would that kind of.
Hey, where you would put a rig in terms of meeting those commitments or would you look to renegotiate with the lease holders to maybe.
Then those further can you just remind us kind of the status of how that might influence the decision making process and 21.
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 is being accretive to our whole plan at some point.
It doesn't happen in 21 or 22, but.
Three years from now we want to be out there drilling and $60 price environment, then we'll want to hold onto as much acreage that makes sense. So.
So we've got some options and we're actually already working on.
Considering some.
Options in a couple of places.
Okay makes sense, thanks for the time guys.
Thanks, Jeff.
Thank you. Our next question is coming from Brad Heffern from RBC capital markets. Your line is now live.
Hey, good morning, everyone our after.
Afternoon.
Just touching on sort of the M&A theme I mean, there's been.
But to put it lightly a lot of deals done in the space and seems like pretty much everybody is trying to pursue scale. So curious if you can just give your thoughts on it.
Here are some competing at the scale of it now.
And then how you think about adding scale through sort of acquiring other things, which is sort of already talked about but how do you also think about it from the standpoint of just selling riverstone is on the larger.
Oh good question.
You know, we're we're building a company here that is long term investable and run it like we are going to own it forever, but if somebody comes along and says.
We like your business, because you're generating free cash flow you got low debt I got very low DNA.
You know we're open for business.
It's it's they're not mutually exclusive we think we can build a very sustainable.
Profitable company through scale.
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 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 and trying to get a deal done so.
You know, we're we're open to considering either but I'd say that at this point, we're a consolidate Tor and spent a lot of time working on that there's also a lot of opportunities outside the public market I mean, there is a big private.
Group of operators.
In every basin and we look at several different opportunities related to the private space as well.
Okay. Thanks for that Robert.
And then maybe for Mark just I know you guys said that the you know the gas costs 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.
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%.
But it would have been.
So you're not really looking at a true sequential comparison versus comparison.
Yes that was also right when we broadened the Wttg wells, which did really have some nice initial volumes and they're still looking nice I mean honestly.
Yes oil came in pretty close to maybe a little better than what we forecast the fourth quarter.
The gas came in a bunch higher than we forecast and it's sort of our internal discussion as well with our our senior engineer as 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 the Ngls.
Just looks flat and were 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 bopping completion and 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.
Thats, probably 80% oil so it's kind of price 650 barrels a day of oil.
Yes, that's embedded in our guidance.
If anything I think we feel really good about what our guidance implies from an oil production standpoint, I is it possible that the the gas is a little bit higher than that yet maybe so financially I mean sure. The gas it's nice to have and prices are better differentials are better but it just doesn't move the needle I mean natural gas only six.
Percent of our revenues in the third quarter is that going to be much more than that though the ngls help a little more.
Hey, Brad this is definitely a function of the types of reservoirs that we're drilling and as you know if you're not bringing on new wells. Your gas volumes are going to continue to rise to a certain point then they level out.
It's not anything unusual.
Yeah, Okay I appreciate it guys.
Thank you. Our next question is coming from John White from Roth Capital. Your line is our.
Good morning, guys and congratulations it was a blow out quarter.
Thanks, John.
Say on the lease operating expense is that lower due in part to using employees versus contractors.
Theres Theres no doubt that our employees work really hard and help us maintain.
Our 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.
Of routine things that we would otherwise have a contractor come help us do from a cost standpoint, I'd say, it's a lot of money so yes.
Sure.
Okay, Thanks and.
On the acquisition market from a little different angles.
Has deal flow improved.
His deal flow higher or was deal flow higher in the third quarter versus second quarter.
We didnt do a deal in the third quarter we.
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 so.
Folks considering.
Their options and looking at.
Potentially what market valuations are so I'd say the deal flow is picking up marginally.
Thanks again.
And not question, but I appreciated your comment about how selected you're being on your on choosing your frac crews at very good to hear thank.
Thanks again thanks.
Thanks, John.
As a reminder, that star one three placed in the question queue. Our next question is coming from Andrew Bond from Alliance Global Partners. Your line is now live.
Good morning, all thanks for taking my questions and congrats on another great quarter.
Thank you Andrew.
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 just trying to get a sense of whether you still look to turn the remaining five ducs in first quarter, if prices kind of stay here in the high 30 barrel range or even dip to the to the mid thirtys.
Thank you.
Yes, definitely 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.
I have to line up a lot of vendors. So we started talking about this.
Oh, probably August September timeframe with no date selected and then as we got later in September we picked the date.
With our vendor team.
The next five we've got some flexibility if prices continue to dwindle down and get into the mid Thirtys, we have no obligation or timing that we have to go complete them. So we'll sit back and watch.
Are 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.
[music].
That's great thanks, very much Roger.
Thank you we have reached end of our question answer session, let's turn the floor back were rubber for any further or closing comments.
Thank you everybody appreciate everyone's attendance today and the questions and were open if you have some further questions. Thanks.
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.