Q1 2020 Earnings Call

And one follow up again, we ask that you please limit yourself to one.

On quick.

Welcome.

Question comes from Scott Hanold from RBC capital markets. Your line is now open.

Yeah. Thanks appreciate the in great quarter guys.

I think a lot of the the narrative for the industry in the next couple of months is really going to pivot to.

Full storage in the U.S. and.

Curtailment of production you are you all obviously have factored some of that in your guidance could you give us a sense of exactly how you see that progressing for Matador and first question have you guys shut in production yet when you think it'll start and.

What is your sort of base case, then maybe stretch case on what the short end levels could get too.

Hi, Scott, it's a it's David Lancaster good morning.

So let me try to take those in order.

I think with regard to the question you're asking about.

The.

Percentage of shut in.

We've shut in so our will shut in some of our production in the.

In the Delaware and in the Eagle Ford in May and June.

We anticipate relative to.

To what our expectations were for what that production could have been that will probably be in the 10% to 15%.

Of our production.

Those months will be shut in on average and.

With regard to your question of have we already started to.

We are just beginning to shut in our production.

In the Eagle Ford in the last couple of days and we will will proceed to shut in our.

Our production in the Delaware starting tomorrow.

Okay that you know that that's great I appreciate that and you are that 10% to 15%.

Do you guys with the with some of those obviously pretty strong wells coming on in the back half year do you plan on how do you plan on managing those wells through the course of the back half of this year and into next year do you plan on managing the flow rates until prices improve or can you can give a sense of what.

That path is going to look like.

Yes, I think Scott what we are thinking right now is the most likely thing we will do is probably something similar to what we did with the recent Robby Robin some wells and that to we will go ahead, and Frac and get those wells drilled out and and put on that online.

Get initial tests on them and then if need be we may trend the production back.

On on some of those wells for a period of time I think that a lot of that will depend on.

How prices are looking as we go through the rest of the year and those will be kind of game time decisions as we go along but as things exists now and particularly with the state line wells and the other wells that just talked about in particular the raise in the leatherneck. So our plan is to go ahead and.

Complete those wells.

Drill them out get and tested and then we'll make decisions as to the level of production on those wells as we go through the year.

Yes got this year in anymore.

I just wanted to add to what David saying there in regards to power setting. These wells in which wells are getting showed enough I think glance debts in his head of production has done and his team have done a really nice job of putting together all the wells that we operate in what the operating expenses on those wells and whether economic and whether or not and so.

We're kind of voice to react to whatever the market does in regards to increasing that amount or DC decreasing that amount, we got all that stuff teed up and ready to go.

Okay. Okay sounds good and just just to be clear on on just maybe my question, whether it is clear but in your guidance do you assume there's continued curtailment through the rest of this year.

On the Rodney Robinson and with the Boris Wells.

I think it's fair to say you know Scott that that we have assumed in the in the in the second half of the year that.

We will be able to.

Return on those wells you know to production.

At something closer to what there.

What their original rates are I mean, one reason that I think we were we said that we'd update again on third quarter expectations and fourth quarter expectations. During next times.

Earnings release was just to give us the opportunity to see how things go over the quarter, but.

So I think like I said some of those things will probably be game time decision, but in the.

And I think we've made some allowance for that in the in the current guidance that we have but but for the most part in what we provided I think we expect that to that we'll be able to.

Produce those wells closer to what we would have originally anticipated in the second half of the year.

Okay appreciate that thank you.

Thank you. Your next question comes from Jeff Graham from Northland Capital Management. Your line is now open. Please go ahead.

Morning, guys great results.

Thanks.

Wanted to I'm sticking on the topic of of shut ins can you guys talk about any I guess expectations that you have or maybe drawing on past experiences you can drawn to kind of gauge expectations for how you guys see be shut in wells kind of coming back and is that a meaningful rescue guys to kind of think about are planned for.

Or as far as.

Brand. These wells back on just kind of curious hey, guys envision that playing out.

Well it.

Yes.

Matt I'll go first to the feel finish out but Jeff they.

One thing that we did as we did multiple scenarios so that.

We don't have just one and go with that but we look at.

A number of what EPS.

Bad debt.

Try to build out.

Our plan. So you know they it's more than one variable a lot of its price you also have lease terms.

So heavier hedging that take into account and depth. So.

It could be multiple scenarios there what lead.

They do at different times.

The one thing I think that is we trying to be consistent we don't want to be.

Ill turn that the wells on full open and then hadn't come back we want to try to be consistent and methodical through the process.

And and also.

You know where on path that makes it easier than where you are on track and nephew circumstances like that Matt Yeah, Joe Joe Thanks, Jeff I'll, just add to what Joe saying there there are some mechanical issues around which wells we showed in that we.

You seriously contemplating and I'll just give you have a couple of examples if we got a sale legacy vertical world. It's it's on Rod pump and it's making let's say, it's making 20 or 30 barrels a day.

That was pretty easy to shut in we go by.

And secure that are shut the pumping unit off secure the wellhead and we're ready to go on that one.

What another example is we've got a actions that we've got a well in the Delaware that has an E.S.P. That's due for an overhaul and so we talked about that earlier into society. The appropriate thing to do is go in full at SPL do the inspection on the TV do the overhaul and he used to be in his prepared to run back in the whole ready to do.

Do that so that's kind of it the opposite ends of the spectrum, but to grant and his team have done a really really nice job.

Unifying which wells, we want to shut in and how we went to shut them in.

Got it great great details there and my follow up on the midstream side released mentioned San Mateo go into a free cash flow positive position next year.

I assume that the two likely decisions with that free cash flow the internet to pay down that bank debt or maybe extract some cash back to the parents I was just kind of wondering how you guys.

Well look at the Optionality that free cash flow and is that a matter decision is that a conversation have with your partner and I guess, just maybe reminding us how much control you have over.

I want to do it that free cash.

Hey, Jeff It's David.

You know certainly you know San Mateo.

Has its own board of directors. It's made up of you know representatives from Matador and from five point in the you know we we have a very good working relationship with the with our partners about a point and the so I would expect that to whatever we would decide would be a unanimous decision between the.

You know between the partnership and everything else has to this point so.

Im sure that if they would be consulted you know there are you know we can use that cash flow to pay down some of the sand to pay is dead or we can also use it to enhance the distributions that are you know that are made to each party and.

It may be that the best thing you know that we said, we'll just have to decide which way the partnership wants to go there so but.

It wouldn't surprise me if.

If you know that that for the most part we just increase the distributions may do each party and then each party can now use those distributions as they see fit I think it Matador is case.

That.

That would provide.

A significant part of free cash flow that that we would.

We would use along with the incentives that we expect to be larger next year, you know two to defer any outspend, we might have enough in the drilling and completions of wells for 2021.

Got it sounds good I appreciate the time guys.

Thanks, Jeff I appreciate your time.

Thank you. Your next question comes from Irene Haas from Imperial Capital. Your line is now open. Please go ahead.

Yeah, Hi, good morning.

I'm wondering you know at you look towards a fourth quarter you have a DMC capex of 56 million were three rigs probably let me know completion can you give us a little color as to how 2021 might unfold how would you kind of step back into a more normal routine if oil were to stabilize like 40 offices.

Dollars.

Yeah, Hey, I mean, it's David.

Well I think that to I think it's it's probably a little early yet to you know to speculate you'd hoped that so I would I would be I'd be pleased for oil to be back at 40 or $50. You know in the in 2021 and if it were then I'm sure we would probably consider perhaps.

You know.

Perhaps adding a rig back but at this point, we don't have any plans to do that and I think certainly through the remainder of this year, we're gonna stay with the three rigs and I think our initial plans for going into next year would probably be similar and I think we would be cautious as we always are in terms of when we decided to.

You know to move forward with the with increasing activity.

I think that actually in the fourth quarter, if I recall correctly youre right. The the number of completions is down but we still do have a few wells being completed.

Even in the fourth quarter with the with the Capex estimate that we have and the and then we would have additional wells being completed in the first quarter of 2021 as well because I think most of our body wells at state line would be a.

Beginning to complete a lot of those wells, we'll have some additional Rodney Robinson wells by that time too.

Okay, Matt had one follow up houses the DNA look on the part per barrel basis. So we kind of your first quarter number and contract for the year. That's all I have.

Can you ask it again, Irene I'm, sorry, kind of cut out and I didn't understand it completely.

He any outlook for the rest of the year.

Okay. I think if you I think if you'll kind of just look in the slide deck that we provided we gave you a pretty good indication of what we see for for DNA going forward for the rest of the year I.

I think we would expect that to you know that are our DNA per be a we would be.

I would be down some from what to what we reported in the first quarter because there are some additional.

DNA steps that we've taken in particular, the pay cuts and things that the Joe referenced just a few moments ago. Those actually didn't begin until the first of April so they will be second quarter items and they're also some.

Some changes that we made we've referenced in previous releases that to some of the staff have moved into positions in the field.

Or maybe in our measurement area in San Mateo that.

So we've had folks I think would you say met 27 or something that.

Actually gone from.

Positions here in the Dallas office too.

Two.

Other assignments, you know and I think thats, all working out real well, but that's helped us to cut down on some of the contract expenses that we had and we'll begin to see more of that.

Begin to find its way into the DNA numbers going forward Irene.

Thanks, Matt I, just I just wanted to tack onto a Dave was talking about visa. These folks transferring job responsibilities a lot of them are people that have gone through our Max OPSM really smacks offs and Max calm programs and they've been out in the field, that's where they learn they spent the first two or three years in the field and so weve, assuming they said they were.

We're excited about being able to go back and run drilling rigs and run frac spread and do all that so I think it from a timing perspective, it's worked out really nice for us to have.

Experienced field folks that we could bring into the office for a couple of years, an incident and back out into the field was there will continue to gain experience and that there will be even better when they come back.

Great. Thank you.

Thank you on the next time.

Thank you. Your next question comes from John Freeman from Raymond James Your line is now open. Please go ahead.

Thank you good morning, everybody.

Not to belabor, the ACA shut ins thing, but I just wanted to verify when you said that roughly 10% to 15%.

Production shutdowns or just kind of what you're assuming when you think seldom does that include in that number.

What I wonder.

And your curtailments or is restricted flow or it's like on the arrival of Robinson is that included in that number or is it sounds like you have circ surgical shots.

Yeah, John It's David Yes. Thank you for a forgive me a chance to clarify that because that is true being when we say when we're saying what I've said shut ins I'm I'm thinking shut ins or can tailed curtailments or restricted flow I've got that all sort of in the same bucket.

Okay, and then is it possible David that may not be but is it possible as sort of break out like how much of that influences physical shut ins versus sort of a curtailment Franklin top and bottom Robinson.

You know I would imagine that I would say, probably maybe John half, maybe maybe two thirds of it is more physical shut ins and the and the other is due to do to curtailments.

Okay, Great and then just my follow up question just to make sure that I've got.

The completion cadence right. So so based on.

The detailed shall gains we eat the five or eight wells in the five Leatherneck wells, which you said summer of this year, if we take the prior guidance at how does comment on roughly from July So meeting those 10 and three Q and then the 13 for us wells, which.

Sure basically straddle three Q4 accumulates September October can you just take half of those bonds and put them in Threeq you for right down the other terming happened for Q.

Yeah, I think what to what's most likely to happen is that the rate wells, we'll end up being a Q2 completions and.

I think the leather next we'll end up being a two Q3 completions and the bars wells I.

I think that maybe it'll be more like a two thirds in September and one third and you know in October, but there's 13 of them and they'll they'll come on you know just a little bit at a time through through those months you know I think we're going to put them on.

You know three or four wells of time.

During September in early October.

Yeah for several reasons number one just don't want to swap the facilities initially number two to get it feel for what the volumes are going to be number three it'll be the first flows into our headed north a on the new pipeline up to San Mateo. So I think we just want to kind of stage things in rather than go out on day, one and just opened all.

The wells immediately.

That's great I appreciate David congratulations to everybody on on a great quarter.

Thank you John Thanks, John.

Thank you on your next question comes from Neal Dingmann from Suntrust. Your line is now open. Please go ahead.

Morning, All my first question just for Piper David or Matt I'm, just wondering David when you do you think that we haven't heard too much you, let's move curtailments in shut ins Im just wondering what what's the time or cost needed to bring that back it sounds like or at least appears like in your press release really not too much timing or cost involved.

But I just wanted to sort of double check that from from the experts.

For for Neil.

I didn't exactly I understand your question. If you are you just asking about to how difficult we bring to bring low back on or what it might.

Just just really matter from from the shut ins is there you know we've heard slumbers they talked about a lot as stimulation needed to bring things back and again I get it at your curtailing I'm, just wondering about cost or timing. It you. All don't appear like there's there's too much involved but I just want to sort of double check that.

Yeah, Neel I think it feel very from from well to well, but what I think the for the most part let's just take the legacy wells that are on pumping units I think like I said earlier I think that's pretty simple you turn unit off close valves and when you're ready to come back on you go back up and open them up I think some of the.

The wells that.

Have different type of artificial lift it maybe a little bit different cost structure.

One of the things that will do well just talk about gas lift we haven't talked about that yet so we'll show to gas lift or will this on gas lift and we'll just to go head shut the will and leave the gas with ALS in place, we'll put the compressor on standby for that time period, and then we're ready to go back to work. There. We go back out open a well up if it's built enough pressure to start.

Flowing on its own it will if not then we'll just startup the gas compressors and start gas lifting if you move forward to wells that are flowing which are probably very few of the wells that we would shut in that would flow I think those would would build up natural pressure and kick off on their own. So I don't think we anticipate the whole lot. There are a few wells that we've.

We will take this to be an opportunity to either change out the artificial lift system or overhaul what we've got in place.

Very good details and then my second question is for David David around that the carriers at and tax credit I'm. Just wondering if you all might be eligible for any empty tax credits in 2021, and you could look to potentially accelerate these into 2020.

Ah, Yes, Neal the answer is yes to that I think.

You know, we never had a lot of 80 80 credits.

Even with the passing of the new tax act, but but but yes I believe there is about to.

About 3 million that that we have a have applied or have requested be accelerated into the 2020 as a function of the carriers that going I think there's a there's another 3 million that to you know that were waiting just on kind of the more normal cycle.

Coming in in 2020, so altogether, maybe something like $6 million.

Very good thanks, and not Joe just want to say nice job, leading by example, with the salary reduction at all I think you guys really stand out.

Thanks, a lot I appreciate not failing to hurt their little there because I wasn't getting the question [laughter].

Yes.

But no we really appreciate yet I mean lives are right. Thank you David I'm not an ROIC by any means it just was the right thing to do we were looking at prices going for the first of all year.

$62, a barrel down to 20 and.

No we got shareholders it had an issue.

Now.

The shares last 9% of the right I mean, what.

What else could you do and we're ready do we were raised take a second cat, but it appears that things have been turned around and made that won't have to be done that were.

We want our alignment with the shareholders to be clear.

And I know anybody I think on the saying because I'm not it yesterday I think they're really not saying was without any prompting our board.

At lately one.

Raised his hand, our audit Committee Chairman said I want to volunteer 25% PAETEC too and they went all around the.

The board room, and everybody agreed to do that so I.

I think thats a better it.

Example of people trying to drive think anything that idea in the exact 18, didnt airbase pitch DNS and this past six weeks there has really been a lotta extra effort from people trying to do the right, thank and reposition matador and make it clear.

That we had at plan a good plan to address work through that Corona virus as well as these poor pricing and we were really help on the best moods was David add them restructuring the hedges to take them. So that we got a much larger percentage.

You know that 90% hundred percent for the rest of this quarter coverage.

On the hedges you know whether based pricing the bottom price about 35 to $37, we still have achieved $48, but.

That took a lot of that risk out going forward and.

Our everybody's it's been all hands on deck.

Yes, it keep things moved and so the credits related to other people that appreciate Kate.

[music].

Give me that credit ahead, nail and I'll take it Joe and I'll still consider your St. Joe.

[laughter] right now.

Okay.

Thank you and your next question comes from Noel Parks from Coker and Palmer. Your line is now open. Please go ahead.

Good morning.

I know.

I was.

Wondering about.

The mentioned you made earlier about the bars wells and you expected that they would be even better than Rodney Robinson. One. So I was wondering what you attribute that to and also wondering you know with the outperformance you saw.

In the in the first six wells.

<unk>.

Love to hear some more about what the the components of.

It was whether it's just the rock fact effectiveness.

Yeah, I know, it's David well I think that that's right I think that to its you know it's largely just a function of.

It's just a function of the rocks in the you know clearly.

That's an area there at the state line the to that we feel like is.

You know.

Some of the very best to some of the very best reservoir quality are likely to be.

The entire Delaware basin, and so I think we're just we're just very optimistic about to you know the the potential for those wells I mean, we've liked the look of the of the section from the Avalon through the lower parts of the Wolfcamp you know a ever since ever since we've been working in the basin and we think.

It's an area that to that that offers a lot of opportunity and I.

I mean proof will be into putting a course, but I think where we're very optimistic and so far the you know the drilling on those wells has gone well and so we're anxious to get that stays behind this and get to start to frac in some of these wells here before too very long and see what we got no. This Matt I'll, just just said what David.

He said there.

Things that we're excited about is having.

Those rigs on there at the same time, there's lots of synergy lots of efficiencies that you get just by having ever older rigs right. There close by we're we're sharing.

Some of the mud systems were able to share we're sharing some of the supervision was able to reduce some of that or or superintendents or troubleshooters. If you will they're staying on location, they're able to access all four rigs at the same time, there's just a lot of efficiencies that go along with that in the you know this is a.

That's a big batches long laterals for us, but it's not the first we drilled well over 30, because these two mile laterals already and so feel and his team are doing a really nice job on the drilling and I know, Chris and his team will be well completions and Glenn is to do well production. So we're excited about those wells.

Oh listen this is barely hear I'll just to.

Add on to that in the Max calm room, you see the different asset manager you see the geologists and there you see the engineers and.

Well, we have that many rigs running into same place at the same time you get all this group energy there and they're all looking at different things are doing and out of that I mean, I know you see in the slides are we've had 84 records across different.

So asset areas and categories or to the total saving $9 million already and you just use feel it and see it and you're getting more time and in zone, 94% or the time and in zone and all good.

Great.

And just wanted to turn that hedging from that.

With what we've seen with.

The gas strip looking better than it it has been in awhile.

Are you more inclined to Oh look at getting more aggressive on on gas hedging going forward, you're going to the near term or sort of longer term when we get Oh, if we get passed the krona virus.

That looking more likely less likely more in line here.

The spot we're going here.

I think I think they'll it's a it's probably more likely I mean, we we already as you noted in the release a have entered into some some hedges for.

For natural gas in the in the winter month. So we've got some hedges down between November in March already that have to 50 floors and.

I think they've got about 375 on on the top end and we certainly have begun to you know to monitor the move in gas prices and and I would expect that to you know things continue to look favorable and I think we feel like that they will that thats, probably something that we would to that we would look to do.

You know to be able to lock in a little bit better natural gas price.

For next year.

Would you know would help us out quite a bit. So we do have 40% of our production. That's a that's natural gas and when you're talking about the producing 60 or 70 Bcf a year that extra dollar 60 or $70 million. You know so I think it's important in the and something that we're paying attention to.

The ethane grid that this is Joe the other thing is just.

Okay, where right now about 60% all 40% gas and we have a number of knobs that we can turn either in the haynesville or the Eagle Ford or at there in new Mexico.

In the particularly in the wrestler breaks area, where we could rapidly increase our gas production. If we should choose to do so so we're monitoring the hedging, but we kind of like to have a backup to use the hedging the backup what we're doing either in oil or gas.

To try to reduce the risk of commodity pricing.

Great. Thanks, a lot.

Thank you know thanks, thanks, though.

Thank you on your next question comes from Richard Tullis from capital One Securities. Your line is now open. Please go ahead.

Thanks, Good morning, everyone, Joe Congratulations on the strong quarter, particularly on the cost side.

That jumping back.

Going back to 2021, a little bit I know, we've talked about a little earlier, but.

With no four key production benefiting from the state bond wells coming online later this year.

Level of drilling completion, Capex do you think would be necessary in 2021 or rig activity, if you'd rather look at it that way to kind of keep production flattish with the new.

New oil production outlook for this year around 41000 a day.

Good morning, Richard just David.

Well I really believe it to that we will be able to ER to keep our.

We can we'll probably have we could have more growth I think let's say.

You know low single digit kind of growth.

Next year, even if we just maintain the three rigs you know I think that and some of that will be you know timing related but to wish you have noted we do have a significant to influx of production from the first 13 wells there at the state line that will come on mostly in the fourth quarter.

And that'll carry over nicely into the first part of the 2021 and then of course, you know at the moment.

We expect that we'll have a the first batch of wells from the western side as state line the bills were calling Bonnie.

That will you know I think it's another dozen wells that will be coming on.

You know round about probably the beginning of the second quarter. So that will be another you know a boost to our production early in the year and then I think the envelope rich teams also expecting to drill for more wells on the Rodney Robbins and track beginning in the end of this year and those wells also.

So would probably get fracking turned to sales about the same time you know ended the first quarter first to second quarter kind of like the other rodneys did this year. So so I think we feel like that you know that were like likely to have a pretty nice boost in production in the early part of 2021 and that would Ah I think that would help to some.

Staying you know even some you know some level potentially of growth.

Even at the three rigs in 2021.

That's helpful. David Thank you and just for my follow up.

San Mateo adjusted EBITDA kind of flattish the last couple of quarters, what a current thoughts on.

Potentially monetizing all or part of the interest there over the next one or two years, if you could update us on that.

Yeah rich everywhere.

Finally, count today and as such you know we try to play a strike game leap sell things in the past.

You know, we sell first Matador, we sell part of our.

Painful to Chesapeake, Italy cells.

A plant the Italy. So you know that's a hard one to predict particularly the time of volatile pricing.

But if we got a serious offer we give it serious consideration.

The.

You know as far as the.

EBITDA going fairly flat you've had a reduction in race. So there's third party contract should not as plentiful.

As you might lie, but it's also we have a growing production profile out there and we need that capacity.

Just to take care of ourselves and hope to add to it with more third.

Third party.

Contracts and I think our field staff and have done a really good job of servicing those other companies and.

Yeah, we'd like to think that we're getting a good reputation for delivering.

Good service out there and keeping them moving so you know it's a matter of time, a when you build those pipelines to attract.

Other gas and we built the pipelines a particularly the expansion through the state line and that to the Stebbins area, which are are great areas and we think just you know kind of little there's an element.

We're not reliant upon it but there's an element a build is unable com combined with our own production profile and the needs of some of the other third party relationships that we already have Sal.

There may be a little pause here and stayed a little flat, but we expect gross debt pick up.

Taper Lee as Paypal.

You know.

Gas prices improved and people start drilling for gas wells water production.

That's kind of that's been fairly consistent and and sell is.

Also I think outlook is.

Is pretty good.

They did anything.

What's a good answer I would just do that too that Joe and you kind of said it but to win San Mateo contemplated. This expansion. We looked at is the their anchor tenants to make the economics work in the anchor tenants Matador and so the fact that we're running the rigs on the same into acreage does make the economics work for the expansion for that.

Good day.

Simplify things will come back and we'll be there, it's immaterial will be there with the capacity and ready to go for third party.

Alright, thanks very much appreciate.

Thank you Richard.

Thank you on our next question comes from Sameer Panjwani from Tudor Pickering. Your line is now open. Please go ahead.

Hey, guys. Good morning this.

This is a bit of a hypothetical question, but on the shutdowns.

The hedge book wasn't in place would you guys have decided to shut anymore and you know hauling onto that what price do you think the company needs to generate full cycle returns on new drilling on an unhedged basis.

Oh, Hi, Samir it's David.

You know it I think it's always difficult to answer in a hypothetical question. So a movie kind of our where we are I think there are lot of considerations that go into.

That go into making decisions on on shutting in wells and.

You can not only do you have.

Situations with regard to different wells have different levels of operating expenses different wells are producing from different zones different wells have different tons of artificial lift tops that may be you know make them easier or more difficult to shut in.

You know different wells have.

All kinds of different lease you know obligations and so there's there's many different considerations I think that to that all of we operators have to go through in terms of of deciding you know what and how much we're going to shut in and it's not just simply it's not just simply a matter.

Matter of price you know so.

I don't you have you have volume commitments and things like that you know for for gas production. So I think you have to take all those things into account and I don't know that to well I think the the hedge book helps you know I think that to it's only one of the any number of consideration.

Is that but you try to take into account when you're making these kinds of decisions.

Okay. That's helpful and the second part of that question was as you think about.

You know what price do you think the company needs to be generating full cycle returns on new well.

You know again I don't mean too you know.

<unk>.

You know to be obviously scale here or anything but I think that's also kind of a difficult question to answer because of the fact that.

That price and service costs tend to go hand in hand and.

You know.

Currently some of the you know prices that were.

Projecting that we're going to be able to drill and complete these wells or are the best that we've ever seen you know so now I'm not going to I'm not going to tell you that I think that to you know that the.

Takes $20 work for every well that we're going to drill, but but I will say that to you know it's again to me. It's just not a one variable you know.

Situation, we have certain wells you know that that to you know like all operators you got to you've got a portfolio of locations in the portfolio of opportunities and and some you know we're going to have higher returns you know than others and in this period, where.

Assets are low and costs are low if it makes a difference in terms of the you know the decisions you make on on which wells to drill and whether they're going to be.

With that they're going to be a.

Economic in the long run so I just I just hesitate to you know it to give you a specific price because I think it it there's a lot that goes into making those decisions and it's not just all about price cost makes a lot of different sue and I can tell you several years ago, when we look back and do some of our own.

Studies a 2016.

It was another time when prices were very low then there was the increase in process following that and we think those are some of the most economic wells that we ever drilled because the fact that we're able to construct them for for a very low cost and so.

It's just it's not something I think you can leave out of the equation when you're when you're thinking about this.

Okay, Okay got it.

Maybe switching gears on San Mateo There was a question earlier on liquidity and free cash flow implications for Matador as the midstream business turns free cash flow positive, but can you talk a little bit about how San Mateo to cut further enhance Ah. That's one some of those facilities come online both in terms of liquidity and free cash flow.

Well I think I.

I think we think it can do both very well first of all with regard to the liquidity part of the question the.

The current facility credit facility that we have in place with regard to San Mateo is tied or simply to San Mateo ones assets. So none of the assets belonging to San Mateo to yet are part of the credit facility, we believe that to that once the merger of same detailed.

One in San Mateo too is completed which should both parties are working on you know at this time and I think we would expect that to happen you know down the road here then the assets or San Mateo two will be brought into the credit facility. When they are we feel like that to there is very good likelihood.

At the Bank then with the Bank group would agree to increase the size of that facility because they'll have substantially more collateral and with that then.

Once that's accomplished then we would have sufficient substantially more liquidity just under our under the credit facility associated with San Mateo Secondly, I don't think theres any doubt that to once the new plant is online and the new pipelines are in place.

That we're going to see a significant increase in the revenues from San Mateo with the.

Emphasis perspective, specifically from San Mateo too as a as the gas from the state line begins to travel to the from the north and the gas and oil from Stebbins start to come to the South and we've already added a couple of additional salt water disposal wells up in the Stephens area, which are already contributing to the revenue San Mateo.

So you know so I think that to as we have expected in projected that we're going to see it a nice bump in the in San Mateo said, you know financials as you know coming the fourth quarter and beyond into 2021, as we get everything turned on with the Stateline.

And sevens.

Understood that's great color. Thank you.

Yes sure. Thanks.

Thank you I know last question comes from Gail Nicholson from Stephens. Your line is now open. Please go ahead.

Hi, Thanks for fitting in the wrong Robinson and the bar I thought that the higher end, our I could you remind me and the 20 activity level, what is average and all right and then how do you think that could potentially change in 21.

You know again the.

Gets David the so you're right the Rodney Robinson wells had the 87.5% all the boroughs wells have 87.5% anything on state line. So the bonnie's will have 87.5% or the wells that at Rustler breaks probably tend to run between 75, an 80% on the enterprise.

The that's probably pretty pretty good elsewhere too you know I mean, we have we have.

The wells at run if they're feeling says, they're mostly 75% if their state leases they tend to be a little better than that maybe plus or minus 80, and if they're in the federal leases or you know, we often have the full one eighth or 87.5% and so as you think about next year I mean.

We probably will continue running you know a couple of rigs at the state line and that will those wells should all have the 87.5% we'll drill a few more Rob Lisa, but we'll also have.

We'll also have I'm sure eight or 10, other wells, but we'll have something closer to 75%.

Okay, Great and then just a follow up on San Mateo when that.

Third party Nbcs for 20, I do believe that Inc. upticks in 21 for the not NBC for third party is that correct and can you just kind of quantify that.