Q3 2019 Earnings Call
Greetings and welcome to the Earth Stone energy third quarter 2019 earnings Conference call.
This time, all participants are in listen only mode.
Question and answer session will follow the formal prison presentation.
If anyone should require operator systems during the conference. Please press star zero on your telephone keypad.
As a reminder, this conference is being recorded I.
I would now like turn the conference over to our host Mark Lufkin Executive Vice President and Chief Financial Officer. Thank you you may begin.
Thank you and welcome to our third quarter Conference calls for get started I would like to remind you that today's call will contain forward looking statements. The meaning of section 27, eight the Securities Act of marching 33, as amended and section 21 eat the Securities Exchange Act 1934 estimate it although management believes these statements are based on original expectations.
They can give no assurance.
They will prove to be correct. These statements are subject to certain risks uncertainties assumptions as described in there or anything else released yesterday in our quarterly report on Form 10-Q , you put the third quarter of 2019.
These documents can be found any investors section number by www Dot Earthstone energy Dot com should one or more of these rest materialize or should underlying assumptions prove incorrect actual results may vary materially.
This conference call often goes references to certain non-GAAP financial measures reconciliation reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP or container earnings announcement released yesterday also please note information recorded on this call speaks only as its they ever summer 2019, that's any time sensitive information.
In may no longer be accurate up the time of any required a replay of todays call will be available via webcast like onto the investors section of our son'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 Frankel dusky followed by an overview of our current at upcoming operations by Robert Anderson.
My remarks for me regarding financial matters and performance in concluding remarks from frankly, Penske I'll now turn call over to Frank.
Okay. Thank you Mark and thank you everybody for joining this call as our Robert a marker going to explain in some detail we had a very solid third quarter were very well.
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 constant rate.
Improve our metrics our cost metrics our operations I believe that we're showing a the market data small company what good management now standing up ratios can be a pressure and and actually quite competitive with larger companies that have greater scale.
We continue to focus both on operating cost an operating efficiencies in our efforts to drive stronger while returns and ultimately shareholder value.
The environment for acquisition or merger as remains very challenging, but we continue to chase transactions in the Permian.
And possibly the Eagleford thatll be accretive in the absence of a significant transaction, we continue to improve our inventory of locations through small where acreage acquisitions.
And trades that result in longer laterals and increased economics.
The wells, we expected drilling complete with 2020, well all be longer laterals.
Fiery based on current commodity prices and our current expectations for one rig operated programming 2020.
We forecast or 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 our Robert.
Thanks, Frank and good morning, everyone.
As we stated all year long our 29 capital 2019 capital program is heavily weighted to the second half we were very active in the third quarter running two rigs and a completion crew in the Midland basin, while running one rig and a completion crew in the Eagle Ford as a result, we spent 11 wells and completed eight in the Midland Basin in Eagle.
Third we drilled four wells and completed three and started completions activity on for additional wells.
When basing completions included five mid stage wells in Midland County, which were completed during the third quarter and brought online in late September as well as three TSR H. wells in Reagan County that we completed in the third quarter and subsequently brought online in October .
The seven Eagle Ford Wells at our Pan Ranch project, we're in the process of being completed over quarter end and we're also brought on in late October .
We're pleased to achieve third quarter production of 12181 be OE per day with no significant contribution from the new operated wells brought online at the ended the quarter.
Key factors driving this performance are the larger than expected production impact from non operated 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 five mid stage wells.
Which came online in late September these approximately 10000 foot lateral wells targeting the wolfcamp, a and b intervals.
Average peak 30 day rates of 1290 barrels of oil equivalent per day with about 88% oil cut.
The three wells in our TSR H. unit with a which were approximately 12000 foot lateral targeting the wolfcamp b upper and be 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 three gross non operated wells in which we have meaningful working interest of 35% to 40% were brought online in Howard County. These wells are all approximately 10000 foot laterals with one well targeting the wolfcamp, a and two wells targeting the Wolfcamp D.
The Wolfcamp, a well achieved a peak IP 30 of approximately 2381 BRL <unk> per day with 88% oil. This well has been online now for approximately 90 days and has averaged 2159 Boe per day with 87% oil over this time.
Right, which is a fantastic well.
The two Wolfcamp D wells the first for US have achieved peak 30 day rates, averaging 969 Boe per day with 86% oil. So we are pleased with these were well results also.
As a result at the continued success we've 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're pleased with the impact of adjustments. We have made this year already with regards to our well spacing in certain areas and we're making progress it understood.
Handing how to optimally develop our acreage position.
This is particularly evident in the results of our recent TSR H initial initial production, which we did space a bit whiteread approximately 1100 feet between wells in the same landing zones compared to previously drilled drilled wells on this block, which would which were at approximately 925 feet.
Our initial results it TSR age and granted this is only about 20 days of production look 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 until undeveloped locations at wider spacing in order to be conservative conservative in our development planning.
A little bit on operations as expected at the end of the third quarter. We released one of our two 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 it's supporting our push to drive efficiency gains.
We continue to target 15 days per 10000 foot lateral and have averaged 16 days per well normalize to a 10000 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.
Now to schedule and expect to have these remaining six wells online by the ended the year.
Over the past few months, our completion team did a great job fracking. These 14 wells. We went from averaging eight has stages per day at the beginning to 12 and a half stages per day at the end, while dropping our cost per stage by 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 act 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 10000 feet.
Implement to our land team, we've accomplished a trade in September which will.
Positively impact our 2020 drilling program and keep our lateral lengths towards this less distance.
The non operated side, we have to gross 0.7 net wells in Midland County that were brought online in October . We're 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 for the first quarter.
2020.
In the Eagle Ford, we ran one rigs throughout the third quarter during which we finished the drilling a four wells on our on our seven well Pan Ranch project and Spudded, an additional three wells on our Davis These east project.
And we brought all seven of the pen Ranch wells online in October .
We have just recently started completion activity on the three 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 11250 to 12250.
Be OE per day with average production year to date, a little over 12000 Boe per day and with increased production in fourth quarter from all this new activity, we expect to be at the top end of the 14000 15000 Boe per day exit rate that we have provided in August .
Further with our commodity mix year to date of 62% oil, 17% gas and 21% NGL, 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. Thank you Robert.
Let me start with our financial metrics for the order of 2009 team 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 15% 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 up $54.89 per barrel natural gas realizations improved from 4% of an IMAX to 32% of buybacks quarter over quarter, resulting in a realized price of 72 cents per mcf.
Natural gas liquids prices remain pressured as we relative price up $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, what realized gains in the third quarter of $3.7 million, bringing our realized commodity hedge gains for the year to approximately $13.7 million are headed position remained 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 at it and 2020. We know we now have 7000 barrels of oil per day hedge on both W.G.I. and mid cush basis at an average net price of approximately $60 per barrel. We also now have a moderate level hedges for 22.
Anyone 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 the wall how basis for the full details of our current has 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 41 cents per adjusted diluted share and recorded adjusted net income of $11.6 million or 18 cents 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 41 cents 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 reduce both our lease operating expense and cash DNA costs compared to the second quarter on both an absolute dollar basis and on a per barrel oil equivalent basis.
Total Ela, we have $7.3 million was down from $8.6 million in the second quarter, leading to an average of six stars and 48 cents elderly per barrel oil equivalent and the third quarter, which was down from seven to ours and 44 cents and the second quarter and six stars and 61 cents and the first quarter. This was more in line with our with our although he called.
Expectations versus the second quarter, which as we discussed previously was elevated for a variety of Noncontrollable reasons. Our total cash rent expense of $4.1 billion was down from $4.8 billion in the second quarter, leading to an average of $3.59 a cash DNA per barrel of oil equivalent in the third quarter down from 413 and.
The second quarter and fiber one in the first quarter.
Let me give a little further color on the cost side on the cash DNA, what the unit cost to the year to date afford ours and 22 cents per barrel of oil equivalent were running below our full year guidance range for 52 $5 per Boe.
I would note that the third quarter tends to be our lowest cash to get a quarter and fourth quarter tends to be our highest cashing in a quarter. Historically, so just keep in mind as your gesture models, but we do expect to continue managing DNA tightly and L. A week and we continue to target sub $10 per barrel combined cash cost of DNA and Callaway.
And when you really hit that in the third quarter, what cash costs of tend to ours and seven cents per be or we.
Continuing a little bit more on the call side, let me now trying to capital expenditures as expected the third quarter was our highest quarter for capital expenditures year to date with approximately $79 million recruit the quarter, bringing us to approximately 152 million of capital expenditures accretive for the year to 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're 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 things operationally on the drilling side with our newer high spec rigs being very efficient and will 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 non operated 15, well turn out project.
Commences in 2020, but it's not all the question that completion activity could start late in the fourth quarter and of course out of our control as an <unk> partner, but if that were to occur it would.
It would it require additional capex and the fourth quarter.
And also to this potential upward movement in the Capex is that we are seeing lower capital costs on our drilling completions than we had previously forecast.
Lastly, let's move to balance sheet and liquidity at September Thirtyth 2019, we had outstanding borrowings under our credit facility of $125 million, what the borrowing base of $325 million and a cash balance of close to $10 million. Therefore, we ended the quarter, what 200 million of Undrawn capacity, plus the 10 million of cash for total.
Equity of approximately $210 million Starlink. What are your continues to remain strong I'm cognizant that are 125 million our balance on the credit facility as a bit lower than most of you had anticipated and this is largely as a result of our working capital deficit increase in a good bit quarter over quarter really based on the timing of our drilling and completion activities.
Couple of activity, we had in process over quarter in we would expect us working capital deficit to be worked down a bit adequately fully drawings chicken to increase a bit over the coming months and by year end with that I will turn it over to Frank for closing remarks.
Okay. Thanks Mark.
Book as 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 where position for meaningful production growth on the fourth quarter and heading into 2000 Corning.
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 in 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 opposite the ability for us to expand our footprint.
We just need the log jam 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 rights scales 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 official rate.
Actively and to drive attractive returns, whether they be on existing assets or newly acquired warrants.
So we've done that core.
In the meantime will continue to enhance develop unexplored our existing assets.
Before I open the line of questions I'm going to go off script, just a bit and addressing the issue that want to you all or matter that one of you. All are brought up yesterday and that is consistency in spending activity completions and financial measures such as EBITDA.
That's an earnings.
As we have advised our profitable growth. This year provides an opportunity for us to revert to a constant one 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 in the best cost advantages.
That impact you know 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 will now take your questions.
Thank you.
At this time, we will be conducting a question and answer session.
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Our first question comes from Neal Dingmann with Suntrust. Please state your question.
Morning, All appreciate the time I think my first question probably Robert for you.
Maybe could you speak more about marks just recent comments that you are running ahead with the drilling currently enable you to drill more before yesterday and I guess, what I'm kind of particularly looking at is maybe could you talked about how many additional wells this might or might imply in.
What this might imply for early the impact on early 2020 operations.
Neil It probably I'll go in 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 in Frac, just because of operational efficiency and driving cost.
Down and we've done that all this year and that's why we ended up with a pretty back end weighted.
Group of wells coming online.
You know, it's likely we'll have a couple of wells down before year end and will be a couple wells. Therefore ahead.
Of the plan.
But you know 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 frac started in the.
In December and we won't know that till we get through the end of the drilling phase, which will happen here in the next month or so.
Got it got it and then my second one just follow probably for Frank Frank couldn't help notice that.
One of your large orders within cap at filed 13 de knocking on wood with you all but with some of their or their portfolio companies and I'm. Just wondering is there any implication there or if you could just talk about.
Thoughts around that.
Sure.
So so look I think encap, you're talking about end cap and of course, they filed the 13, Dave for all the public companies, where they have an equity position where of course want to bomb and a sizeable Lauren.
With our equity involved and look to the far away is just to provide the market with full disclosure.
So that our largest shareholder along with the board and management.
Our focused on maximizing shareholder value. So it's really just legalities and we're always talking to them and our board about.
About where we see opportunities.
To increase shareholder value, so it's nothing more than that.
Very good appreciate the clarification on both.
Our next question comes from Brad Heffern with RBC capital. Please state your question.
Hey, good morning, everyone.
I think maybe for Robert during your M&A commentary you talked about you continue to look at Permian acquisitions, and then you also said potentially eagleford as well I'm just curious how you think about.
The balance between you know the economics of doing an Eagle Ford acquisition versus sort of the investor preference for Permian.
HM.
You know 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 two areas, we're spending a little bit at time in the Eagle Ford looking at opportunities in and we're spending.
More time.
In the Midland Basin looking for opportunities but.
So we're going to let the opportunity drive.
Sort of that answer there and if we can find the right rock the right PDP and runway running room combination.
And asset then whether it's in one base or the other we're a little bit agnostic.
Okay got it.
And then you mentioned you guys have laid down the Permian Frac crew when is that coming back in sort of what does that turn in line cadence like in the first half of 20.
Yeah, 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 you know we the preliminary schedule as we could have some fracs done in January February timeframe.
And then take another break and then do some more later in the ended 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 and Brad I would just add.
In terms of that I mean, what rob's, referring to is one we realistically could get some of the fracking done yes, there's typically a bit of a delay between when you Frac and Turner lot of you're thinking about how to model but.
I would add 30 to 45 days.
Okay got it.
And then just one clarification so on the TSR each pad.
You talked about the wider spacing I think you said 1100 feet end zone, just to verify like from a bird's eye view that would be six XT and just in the upper and then the lower their 11 under feet apart is that correct.
Yeah, there they are actually 550 feet between wells.
Is the way to think about it Brad Yeah, sorry, I just can't do Matt. Thanks, Yes, no I knew what you were talking about yes, 550 between wells 1100 in the same bench old wells were done at 925 between.
Benches, and so whatever that is.
For 37, and a half no it's not it's for 67 and a half.
Between wells in total.
Keep in mind that the TSR age pad that we just drill 1100 feet apart or on the is on the far western side of our acreage position versus the older wells are on the far eastern side or position and so.
We put this test down to really give ourselves a good view of spacing.
Okay. Appreciate the color. Thanks.
Our next question comes from Jeff Grampp with Northland Capital markets. Please state your question.
I guess.
If I'm looking at slide 12 year and tracking your your DC any costs relative to the target. They all are going for just kind of wonder end.
What kind of bridges that that lasted let's call. It 40 Bucks.
But what kind of do you guys need to see or accomplish operationally to to get to that target and is that.
But you won't have than your medium term and just kind of set expectations for how to think about 2020 costs.
Yeah. 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.
Three pads with two wells each and then a single.
This year or they were all completed this year or will be and that is less efficient than three four or five wells per pad and our 2020 plan.
As either three.
And then five and six well pads that will get us most of the years completion activity.
For 2020, maybe two more on top of that so that is one of the keys.
Probably the next one is lateral lengths as we can continue to keep the momentum up of drilling longer laterals that also drives down. So those two in combination really drive down the cost the wells that we've drilled.
In Reagan County over the last 10 wells are so we had a pad where we're probably going to be under our target and a couple of pads right at targeting a neat and those were two or three well pads. So we're continuing to drive down the cost by that efficiency.
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 I'm just trying to get a better handle on how we should think about kind of low we trending the next few quarters, given kind of the impending production ramp that we should be sand.
Sure maybe I'll pick up on that one Robert can add if we'd like to.
So I'm pleased with what the fourth quarter coming up and we've got a bit of a step change in production levels, we'd expect the.
While the total a number on absolutely should basis should go up a bit incremental wells online, we'd expect to kind of per BOE. We.
Cost of metric to improve.
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.
Thats.
Probably not a terrible starting point for next year, so with additional volumes, probably a bit lower than the range of guys. We have for this year.
But we're also right now not modeling that it's going to hit five bucks or 550 next year either.
Hey, Jeff this is spray.
This is Frank I walked in here every day and tell them, we got to get down closer to five so we'll keep working on that.
Sounds good I appreciate the time guys.
Thanks.
Our next question comes from Jason Wangler with Imperial capital. Please state your question.
Good morning, maybe just following up on that.
Can you maybe talk about obviously higher production should help that but are there any things that you guys are kind of focused on to drive that lower.
Yeah, Jason this is Robert.
One of 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 unlike we all do when we get older things start breaking down in one of the things we can be proactive about is our chemical program treating for scale and corrosion. So we've got a.
A group or team and our field office working through that trying to figure out the best program.
Winter times, 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 haven't guys in the field work every day to try and keep the costs down. So that's the biggest thing for US right. Now is looking forward on our chemical program.
Which which of course, which of course overtime.
Gives you.
Gives you essentially longer run times and.
And you don't have to polio tubing is often and so on and so on so once you get that all working.
I would you I'm just making this up for illustrative purposes, but you know instead of having to pull a well every 18 months or something to replace a few joints. You know you try to swap that out to two years or.
Or three years around all adds in the second thing.
Is that we're really built for 20000 before we had day in the in the our person 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 of the systems and so on.
So 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 and next year.
Just keep on working on it everyday like we've done in prior entities.
I appreciate the color and then.
Frank.
As you talk about M&A and you kind of mentioned the 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 is there a significant difference.
Outside of price, obviously, but even availability of deals out there just maybe how you kind of compare and contrast that to landscape as you kind of stay out looking forward.
Well you know.
I mentioned the log jam I think.
I think the.
I think that there's still quite a bit a buyer and seller.
Difference.
When you're talking a 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.
And it's very very difficult when you're talking to private.
Companies or portfolio companies of PE firms.
I'm not so sure that that's in that context in 70 different if you have.
Ill.
Our Permian Basin company or a or in Eagle Ford company. If it makes sense other than the guys are are a little bit prouder because of more.
More stacked.
Potential.
The the real key.
And you focus on your capacity and the other analysts on here or probably even better too to consider but the other key as you stand a chance or putting together.
Our public to public thing, but you have the same old issues in in public to public mutual valuations.
You know management, social equations, and so on you can probably count.
In two hands.
The amount of public maybe even one hand, the amount of public companies that are out there.
And.
And that's the landscape right now so it's a it's difficult, but we are Jason we're out there all the time talking to people and to bring up Neils question about shareholder return.
Okay.
You know 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.
One of the perspective of building shareholder value and we are shareholder so that's meaningful to us so.
I don't know helpful. Thank you.
Thank you. Our next question comes from then on White with Roth Capital. Please state your question.
Hey, Thank you congratulations on the really quarter.
On your big Wolfcamp, a well in Howard County was there.
Or any any other wells that were drilled during the quarter, whether operated and nonoperated there any significant.
Changes in the drilling and completion practices that you'd like to highlight.
Thanks, John This is Robert we are constantly on our side from an operating 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 likely frac, the well with 5000 pounds of sand in 100 barrels per foot, a water or something like that it was the same recipe.
Generally use between us and and the same recipe that are non operator been using.
On our Wolfcamp a well so.
We just knew we had good rock there and we got good results.
Well, you're tweaking pays off so keep at it and thanks for taking the questions.
You bet.
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Our next question comes from Noel Parks with Coker and Palmer. Please state your question.
Hey, good morning.
Good morning no.
No I'm I'm going to ask a question the same neighborhood as some of the other past ones, but just as a reality check.
When you talk about the advantages of of scale and.
Thank you just gave the example.
Being built really to.
To do 20000 barrels a day.
And the overhead that goes with that in terms of people in facilities offices and so forth.
What what piece of the cost or efficiency puzzle.
Would most improve with scale from here.
Covering the overhead is one but I.
I, just think about how how far down when you come in service costs.
And of course speed is still and you know speed better benefit the speed or things you are.
Yes, you can learn in achieving that you're running a single rig.
So what.
The opportunity to be harvested if.
If you dig.
Yes.
At a good deal bigger from here.
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 caution operating costs in gionee cost per be are we.
This is something that Weve always worked on in prior public companies and this one and so on.
No I don't think at 71 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 you know the drilling and completion.
Activities.
Robert and I were just out in that in the Midland Basin. In May This may sound corny, but you go out there and you meet with all your field people and.
And your Pat him on the back for doing a good job when you say that improvements come from the bottom up in the top down and sideways and then you and install some.
New software. So we can focus more clearly and they understand where you know where we can drive down the absolute Ll wheat costs. So it's it's really across the board and all of them now I will say.
That that once you have the infrastructure.
Built in the field.
You know you can go to you know.
Do we have to add very much infrastructure, if our exit rates going to be.
15000, BOE, we a day and and you know and we achieved 18000 or 20000, no we don't have too.
To add a lot of people infrastructure fixed costs in the field et cetera.
But then that next group from 20 to 25, I'm, just making this up for illustrative.
Conceptual illustrator purposes, that's right at 20000, you're going to incur some more fixed costs. So you've got a ramp up that variable costs.
The biggest thing that I'm, so proud of our folks and a lot of these folks are the same people that have done with me for for.
15, or 20 years or more.
Is is as you know we're just not you know our officers are senior people are 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 in the off.
This.
600 miles away or several hundred miles away.
So there's there's no one thing it's it's looking at all.
So long winded way of saying it's everything.
Right well just.
As an example, you.
It seems like the days when sand availability and fan costs were a big preoccupation seemed like there so far there you're going to you mirror, but it wasn't all that longer though is there anything on the material side or I don't know maybe on the water handling side.
Any improvements still to be made there would you say.
Well no this is Robert.
With scale, you definitely have some pricing power right and.
That would be beneficial to some degree weather it and it would cover all facets of your bill 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 focused 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 would have less impact if we had downtime related to a frac it 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 in 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 we've talked about it over and over again.
But we scale it would even be better from that consistency and growth standpoint.
Okay.
And just that.
Brian just one one last thing talking about private companies in the environment.
Anything on the sort of on the order of.
Firemen type opportunities where.
If I just can't get to evaluation that they.
Sure.
Sure let go of assets.
Maybe taking in and letting them sort of reduce their their operating teams, but with kind of the current ownership.
That usable.
It is and we are working on.
Several different things and.
There's private and probably some public opportunities where.
Whomever it is the operators not going to get to all their acreage and you're right. They probably don't want to sell it. So is there way we could do some structured.
To earn our way into it and we are looking.
At that particular structure as well and things we we have on the board.
Great. Thanks, that's all for me.
Thanks.
Ladies and gentlemen, there no further questions at this time I'll turn the floor back to management for some closing remarks.
Well, we have to do as say I. Thank you and we hope to be up.
Here in a few months tower here, Bob for fourth quarter, Rob equally good or better. Thank you.
Thank you. This concludes todays conference all parties may disconnect have a great.