Q1 2021 Peyto Exploration & Development Corp Earnings Call

[music].

Okay.

Good day, and thank you for standing by and welcome to debate of Q1, 2021 financial results conference call.

Yeah.

Yeah.

Good day and thank you for standing by welcome to the Peyto Q1, 2021 financial results conference call. At this time, all participants are in a listen only mode.

After the speaker's presentation, there will be a question and answer session.

Ask the question during the session you will need the Prez bar one on your telephone please be advised that today's conference is being recorded east.

If you require any further assistance. Please press star Zero I would now like behind the conference over to your Speaker today, Darren Gee, President and CEO. Please go ahead.

Well, thank you Mary sorry for the little technical.

It makes up here this morning.

We got a delayed start by a minute or two.

Good morning, ladies and gentlemen.

Thanks to everybody for tuning into the Peter's first quarter of 2021 results conference call.

Before we get into it today I would like to remind everybody that all statements made by the company. During this call are subject to the forward looking disclaimer and advisory set forth in the company's news release issued yesterday.

In the room with me today, we've got most of the Peyto management team.

J P. The Sean sorry, the VP of engineering and Chief operating officers here, Kathy George on our Chief Financial Officer is here.

Dave Thomas our VP of exploration is here, Todd Burdick, who is our VP of production easier Lee Curran, our VP of drilling and completions and Eric <unk>. Our VP of land is here the only missing today is Scott Robinson, our VP business development.

I think the sign on his doors as he is working remotely today.

Feel free to fire of your questions the way it anybody from the Peyto management team, we're all here to answer the.

First of all David of US are physically distanced in the boardroom and taking all of the safety precautions.

With respect to COVID-19 that we need to take but I cant say that were also somewhat relieved I think everyone in the room, but maybe Todd.

Already had their first vaccination shots. So were all eager to help bring this pandemic to an end.

I think our management team is typical of the larger Pete on staff.

Net close to 80% to 90% of our staff of already had their first shop by now as well, so hopefully that debt lowers our collective risk to COVID-19 going forward.

I do want to recognize the efforts of both our office and field personnel of this past quarter. The continued to conduct operations with safety foremost in mind, particularly with COVID-19 and all of the other operational risks that exist on an ongoing basis in the oil and gas industry.

We didn't have any major outbreaks of COVID-19 that shut us down at all of this past quarter, which was great whether that's on the drilling rigs with the rig crews or big Frac crews that show up for refractory operations during completions. The pipeline crews that obviously have to work closely together, even our own plant and well operations.

True.

It was great to see everybody was.

Making sure we were staying safe and not passing any COVID-19 along so.

We had another strong safety record this quarter, so well done everybody.

And I just wanted to say a big thank you to all our people both here in Calgary and out of the field for continuing to keep the gas flowing so the albertsons can keep the lights on and especially the heat flowing because of this past first quarter, particularly in February was brutally cold.

And so that was the life saving.

Hi of energy that we all need it.

So thank you to all of our people.

Okay on to our first quarter results operationally, we continue to drill some very strong wells in Q1, our base production came into the year at around 86000 barrels a day in that group from our drilling operations to around 88000 by the end of the quarter.

Obviously, we had to offset the annual 25% decline, which is actually steeper of the first part of the year, probably closer to 20% to 30%. So that meant capital efficiency on that organic activity was extremely good.

We are way less than 8000 of flowing on that.

And then we layered on top of that production. The two Cecilia acquisitions. They were effective January one 2021 that added close to 3000 barrels a day for around $36 million, so that ratio would be around 12000 of flowing.

And so collectively we were we were in at around 8000 of flowing for the trailing 12 months, which is some of the best capital efficiency, we've seen at Peyto.

And on a combined basis, we exited the quarter at around 91000, Boe's a day.

About 86% of that was gas on the rest of those Ngls.

We drilled the total of 27 wells in the quarter. So a very active quarter seven of those were our newly designed to extended reach horizontal wells.

We define those extended reach wells is having over two kilometers of horizontal lateral.

And this new well design I think is a real game changer for Peyto.

We're excited about what this means for our future resource potential.

Ian Day, Dave can.

Provide some more color on this later I think.

Drilling was spread out across many of the core areas actually through the quarter.

We continued to take advantage of our extensive pipeline and facility infrastructure capacity. So our spud to on the stream times continued to lead the industry.

I think over the last five quarters, we've been putting wells on production within about 40 days of commencing drilling.

And that's even with all of the pad drilling that we're doing.

So thats very quick conversion, even for us and very quick conversion relative to most other than the industry.

Other operational highlights for the quarter include our emissions reduction work, we continued to swap out measurement equipment in the field that significantly reduces methane emissions.

This lowers of course, our carbon tax bill and increases our methane sales all while being better for the environment. So really that's the.

At the Triple win.

We also continue to work with our suppliers on a new.

Designed for our well site packages that have next to zero emissions.

We have some of the those new designs being installed this year will trial dose and see how they work.

With the ultimate goal of course to minimize our emissions if we can but at the same time, we have to we have to make sure that we have reliable systems for production operations.

I think we all saw the examples of having systems to integrate it and then one of them feeling, causing all of them to fail down in Texas. This winter.

We have to make sure that.

Even though we're putting in more environmentally friendly systems in our production operations they still have to work.

Especially in the wintertime.

Zero emissions.

Albert and freezing the death is not our goal.

We want to make sure that we can get down to very low emissions, but have very reliable energy.

Moving on to the financial results for the quarter, we maintain some very good cash costs throughout the quarter operating costs were lower so nice job Todd.

Royalties of course were predictably higher.

Due to stronger commodity prices those scale of course with commodity prices.

Our interest charges were also a little bit higher which was tied to our revised covenants in our banking agreement.

Those are coming down as we move forward.

Kathy can speak to that later.

Natural gas prices for.

We're obviously very strong during the quarter, we alluded to that on our last conference call and really we made off like bandits in a couple of places, particularly the volumes, we had diversified to the venture market, which is just outside of Chicago.

On the cold spell hit mid February we saw spot prices, there spiked to over $150 of <unk>.

So we cashed in on that for about a week and that windfall actually almost offset all of our expensive market diversification costs for the quarter. So.

In the end.

We were close to achieving equal like.

<unk> prices for the quarter.

Which gives us cash flows that are extremely strong.

And I think.

That's a bit indicative of what will look like in a few quarters from now when the higher cost basis deals globally.

Funds from operations were more than double what they were in Q1 2020.

That was obviously a pretty ugly period. So we're happy to see our funds from operations back up to where they were supposed to be in that $117 million really covered all of our capital program of covered our dividend and it even cover the acquisitions that we made in Q1. So we ended up growing production, while still paying down some debt.

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That's obviously an ideal situation.

Earnings or profits were also way up in the quarter.

Basically back to the level of profit margin were used to of Peyto.

Our average profit margin over the last 10 years has been right around 20%.

The earnings revenue so 22% this quarter was right in line and it's exactly what we expect to see.

On the marketing side, we've added.

Two of our basis deals going out to 2024 with more eco to Henry hub and equal to dawn deals that are significantly below of the pipeline tools.

Very attractive looking basis deals I much prefer the synthetic transportation of the basis deals since there is no physical delivery risks.

We get to market and get market diversification, but we only have to deliver our gas to the sales meter, which is just outside of our plant gate.

Anything happens to the pipe beyond that.

Ransomware attack or some governor of trying to shut it down it's not really our problem. We've already delivered our gas to the to the sales point and we get paid.

But we get access effectively to those.

Those diversified markets across North America. So the basis deals look very attractive to US right. Now we secured 40000 of Giga joule of the data to on at a cost that's almost 25 net.

For you below the LTA P tool, so I really like that.

Gas prices are setting up very well for this coming winter.

We're looking at storage refill this summer and both European storage is feeling very very slowly.

Even use storage is in Canadian storage is feeling pretty slowly so.

Even though there is obviously strong demand to get that gas into storage the supplies are pretty thin.

Lot of demand for those supplies, we are seeing a lot of gas exiting the Gulf of Mexico through LNG exports and pipelines down into Mexico, and so that's that's pulling a lot of gas away from the North American market, which is very constructive for gas prices. So we're pretty excited about.

How that setting up.

That's probably pretty much it for the quarter, a very solid quarter, both operationally and financially.

So Mary why don't we.

We take the time to throw it open to questions from those listening in.

Thank you as a reminder to ask the question you will need the pastime Linden number one on your telephone.

<unk> your question.

Please stand by while we compile the Q&A last day.

Your first question comes from the line of Dan Lumen with natural gas Weil. Your line is now open.

Good morning, Garen, Thanks for taking my call.

I'm just wondering given your comments on on star job Samsung on the improving fundamentals in North America.

Paul.

Expectations of edible oil volatility in August of the April.

Thanks for the question of Dell is a good one.

I don't think we have changed our opinion of.

What could potentially happen here in Alberta.

There's a lot of maintenance.

Work that's planned for August on the the Nova system, we still anticipate that thats going to have a fairly significant impact in Alberta, we're hoping it's short lift.

And I think.

When you look right now at the injections in Alberta going into storage and you look at the price differentials between summer of next winter. It really there's not a lot of financial incentive to actually put gas in the storage and yet there are as of.

A fair amount of gas still going into storage right now.

Which kind of tells us that people are anticipating there's going to be a window, there, where they're not going to be able to inject gas.

And so theyre trying to get ahead of it a little bit with the injections.

Even as it is we're projecting that eco storage or the eco connected storage. So thats the stuff off the Nova system.

It's only going to get to about $70 to 75% full.

We're a lot Fuller last winter.

Going into that cold winter last year of good thing because we took about 225 Bcf out.

We're on the anticipating that we're probably going to refill something a little over 100 or so.

So it still looks to us like.

Bit of a delicate situation for for natural gas storage in Alberta, and we still think that August is going to be a difficult time.

Particularly for for Alberta prices, which is why we diversified away from the ACO market for the summer.

Alright, thank you.

Thanks, Bill Thanks for the question.

Again can you ask the question. Please press star followed by one on your thoughts on telephone.

Next question comes from the line of Jeremy next day with Raymond James Your line is now open.

Alright, guys.

Just a follow up question on your extended lateral wells I'm just curious how.

How much of that 15.

How much debt is expected to improve the profitability going forward in terms of the payout maybe of the NPV per well.

And how much.

Net production improvement into your guidance.

Yes, it's a great question Jeremy.

These are this is a relatively new well design for us we drilled a few of these wells last year to sort of push the envelope and test of the risk of it I think.

Maybe J P. You could talk a little bit about the economics of those in.

Of that changes things for us.

Sure Darrin.

We drilled about six wells last year, when we tested the <unk>.

Longer reach Horizontals of six mile and a half for instance, so.

We drilled them of about 70% longer than we.

Probably put about twice as much sand in these lateral so we increase the intensity as well.

And we did that for a cost per meter that was about 20% lower so all very good program.

The rate of return on those on the.

The way on that group of wells is around 40%.

And that might compare to something that was closer to 20% in the past and the payouts here would be.

The largest under the two year, Mark So and again, we probably would have seen payouts for a lot longer than that I don't have an NPV number off top my head, but obviously the economics for these.

All of a lot better and we have factored in this into our 2021 program. We have about 20 wells planned.

For this year to follow up on that program of different species.

And different areas. So yes, we're very happy with the success of that program Jeremy.

Jeremy the these extended reach though.

They are of different I would characterize them as a little bit different risk profile. The Lee maybe you can comment a little bit about the drilling risks weather.

There are any.

More dangerous drilling longer laterals than what we traditionally do.

Sure.

I guess backing up I don't know if it necessarily on truly new design in any way, we've always stuck with our standard open on the ball drop system.

We've been doing for the last decade.

And many of the deep targets still carry the intermediate casing design.

The actual well design so.

It's just really how the factored into.

Our program is as a percentage of our activity.

We drilled our first extended reach horizontal back in 2014 being our 28% for 2000 Q1 rich horizontal.

All of them.

What's really changed is back then.

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We were kind of lighten our lift as we drilled that.

Well as TD 6000 meters when the 3000 meter lateral.

We were nervous deploying of 'twenty, one stage system into that and the drill cost.

<unk> was just over $3 $3 million to defend.

And that was with a flawless execution so in the inland.

One of the playbook.

The wellbore challenges.

Our completion cost on that level of $2 $2 million of D&C total just over five 5 million.

It's hard to it's hard to and on the results didn't really for that for us at that time the dose that was the.

That was the the way we should move forward with these debt with these wells.

In 2020 as J P mentioned, we drilled six of these on the 64 of our programs for those of about 9% of our program.

We.

Experimented with a little bit of technical changes as compared to our regular drilling program on the use of Brian in our laterals.

Net development continues to evolve.

We were able to we were able to.

Execute this program for a moment.

These wells for $2 1 million on average for our 5500 meter well and we were.

We were installing 30% to 32 stages.

Sure.

We grew our confidence in this longer design and our ability to to drill it to get our liners on bottom of <unk> successfully completed.

In 2021, we continue pushing that stage count up to 40 stages.

On the risk for us.

Dave.

Following Dr. <unk> for this year a little later.

Kind of give a shout out to those guys.

Give a little bit about hats off to Mike Rees.

The great job of mitigating the geologic risk.

Lot of these are well <unk> and the.

<unk> is the.

Unfortunate.

Unfortunate situation of being bound with an overlying call of it.

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Markedly on stable.

And so as we chase the best rock in the in the upper most portion of this well rich we flirt with debt.

That coal.

And those guys have done a great job.

For the offset.

Offset while research and the seismic review.

Just staying away from that call.

So that helps us execute the wells the full length and reduce the risk of its a huge the stockpile.

Yes.

Historically, Mark Air means more problems.

So as I mentioned, we're pushing the casino.

Hi, <unk>.

The 40 stage count in these wells and we will probably see that continue.

The evolved through the year.

Our vendor alignment and quality control is dramatically improved.

Our confidence in these higher stage count them tight tolerance system for these.

These long laterals require.

Risk of deployments.

That continues to actually improve.

All of these longer laterals.

We adhere to really strong wellbore conditioning procedures, we're seeing our ability to get these long liners with a lot of gear to bottom easier.

And then I would say we used to do a couple of years ago with with lower stage count on the shorter laterals. So.

Experience and our ability to.

To keep those level of horse conditions, along with what I mentioned that.

Geo steering team keeping these wellbore smoothed as really reduce debt risk.

And getting their language of the bottom and then.

Post drill outs thats, the risk more gear more balls.

And the more stages more sand more probability of.

Of the post.

Frac flow back plus.

In the Wellbore.

And we've seen that.

And I don't know if theres anything other than <unk>.

Continued development on Dissolvable material technology is nothing really we can do to mitigate that per se other than.

Our small completions group Joe on Jared.

Have made a big leap on on the cost of cost.

Metrics on on our coiled tubing drill out the post post Frac, we just the <unk>.

Recently drilled two of these extended reach wells.

On a fully to TV to 5700 meters and the weed.

We did it for about 150 grant of well so.

Those are.

Those of those make debt.

Net risk pretty small in the whole scheme of things, it's the big price as J P mentioned on the rate of return.

Through the course of time, maybe or uptake has been a little slower than some of the industry but.

Pride.

Sales.

Our cost control and our operational execution and I think.

We're seeing that we're not really adding a lot of risk.

Adding the incremental lengthens additional stages.

Thanks Lee.

Jeremy.

Hopefully that color gives you the some perspective on some of the operational challenges of some of these horizontal multi stage frac wells and also when we talk about changing well designs, it's not a small decision because theres a lot of factors to consider.

Risk being one of the primary ones, but it comes in all different forms and shapes in all different steps of the operation. So.

Anyway, hopefully that gives you some color on the on the.

The new design.

No no.

Going back to that that part that you were just talking about debt at that T. As.

Commodity price assumption with debt.

Using the especially on the Ngls, just I know NGL zone.

Trying to move up here, a little bit more now and then just price.

The vantage of those NGL pricing.

Maybe a quick comment on that as well.

Yes.

Typically we run all of our new well economics at strip.

Accounting for for sort of where gas prices are headed of course, they are quite severely backward dated at acre right now so.

Not a great gas price forecast to run gas wells against but.

So be it it is what it is we will have to make it work.

You are right on the NGL side.

Propane, particularly is quite a bit stronger.

We realized that in the first quarter of this year butane is obviously backup to more typical levels closer to 40% to 50% of light oil price.

2020, butane prices for terrible obviously because.

In the refinery shutdown that gave us a glut of butane and it took a while to where that off but.

I think last year.

That came away butane pricing strength in quite a bit so.

I think our propane and butane prices in Q1 that we realized that were of 30 Bucks a barrel or.

For a more typical and yes that is a big driver as it is helpful too.

We've got a deep cut only one one of our plants, but obviously it strips of lot more of butane and propane out as well so if.

If we can if we can bring these extended reach horizontal wells with more reserves, even if its leaner reserves into the deep cut that we're getting more liquids out of those wells too and so that helps the economics, but really we're not trying to I.

I don't think.

Only make economic return when the prices are really good we obviously have to survive the volatility in the price.

So.

We've got a build of robust investment here that can survive some of the dips as well as some of the strong spikes.

Okay. Thanks.

You bet. Thanks for the question.

Again, if you wish to ask the question. Please press star followed by line on your thoughts on Telecom.

Your next question comes from Jeffrey Huber.

Sure.

At the start of holiday.

Thank you for taking my call.

And I note in your release reference too.

Are you seeing debt. So I did go back and look at your annual reports and find that your long term debt is basically being flat I went back to 2015, So I wonder if you could comment.

On your.

Statement in your release about dealing with debt.

Thanks, Robert Great question.

Yes so.

We are over the long term planning to bring our debt down.

We did mention I think about a year ago debt.

The strategy in the short term was actually to get cash flow up that was something that we could affect quicker and that debt to cash flow ratio of debt to EBITDA ratio is one of the covenants within our debt agreement that.

We were concerned about and so by putting the cash flow from last year to work.

Drilling wells and the majority of the cash flow this year to work drilling wells, we're bringing cash flow up quite a bit.

And that's actually giving us some relief on that debt to EBITDA ratio.

And then as that as we roll forward, we're going to generate more and more free cash flow at that higher level.

And that's where we're really going to materially paydown.

Our long term debt.

Going forward, so we will pay down a little bit of debt. This year, we're forecasting based on the current strip.

The next year, we pay it down in a much more material way.

Really though when you look back over Peyto is 22 year history.

Our debt to EBITDA ratio.

Debt to cash flow ratio is typically.

Averaged about two times.

Which for some people they might think thats a bit heavy but we have used debt very effectively.

The relatively low cost debt, obviously interest rates of relatively low still.

And you.

You have to put that into perspective, Peyto has nine years of producing reserve life, which is.

The extremely long one of the longest producing reserve life assets in the industry.

And so when we think about two years of debt on net nine years of reserves. It doesn't seem overly levered of course, if you had a three year reserve life and you had two years of debt.

You would think while arm two thirds levered and so that is pretty heavy leverage.

And so when you think about our debt relative to our cash flows the end relative to our reserve life you have to consider those factors because we have an asset here that has very long life to it.

Very significant value beyond the traditional sort of seven to eight years and that's what's really supporting our ability to carry debt against it to use some debt effectively but.

As you probably point out we've just come through a period here where.

Carrying debt is at risk.

It looks Gary too a lot of investors.

And.

For a period of time, there with commodity prices were really low it looks even scary to us, but thankfully we're through that.

I think by the end of this year will be at a sort of debt to cash flow level that is very historic for us and very comfortable for us.

Thank you very much that debt.

For me much better feel for your the business model and your strategy.

You bet the great question.

There are no further question at this time. Thank you you may continue.

Okay, well, thank you Mary.

We did get a couple of questions come in overnight emailed in from shareholders.

So I did want to.

Approach of couple of topics here of one with respect to further on the debt side with respect to our interest charges and so maybe I can turn it over to Kathy and she can talk a little bit about.

How our interest charges are going to look going forward here they are changing quite dramatically.

Sure Dan so.

At the end of 2020, we had of leverage or debt to cash EBITDA ratio of <unk>.

For three times in Q1 that came down to 336 times and as we decrease our leverage ratios.

That actually affects our Sam P fees that we pay which is of significant component of our interest cost. So.

When we see that coming down under for under three.

And we have significant changes in our rate. So our interest rate in Q1 was $6 two based on the historical four three times EBITDA sales going forward in the next few quarters, we expect our interest rates will go down.

More towards the four and a half times.

The four 5% range, which would save us approximately $2 $5 million per quarter.

<unk>.

To see our interest cost in Q4 to be more in the 30 per Mcf a day.

Mcf range or about $13 million.

<unk>.

Which is a significant decrease from the 18 million in Q1.

Great.

Like to hear that thanks Scott.

One of the other questions that came in overnight.

ESG some.

Some of our ESG initiatives and so maybe I can put this one to Todd.

The question was just what other projects really are we looking at in addition to some of our controller work that's being swapped out for do you think thats, reducing methane emissions Todd are there other things that we're looking at Peyto long term things of short term things that also help reduce our emissions.

Yes, Ed.

Given the absolutely Darren.

We had set of target back in 2016 of the 50% reduction in our.

Emissions intensity and through Q1 here with the retrofit program.

We're pretty much there, which should be very close if not there now so we'll have a new target coming out here sometime in the next few months.

We're in our sixth year really with our emissions reduction team.

Of researching and trialing engaging with the industry and then implementing.

Lot of meaningful initiatives debt that.

Net of saved.

The thing going into the atmosphere. So we can sell it and as you mentioned, it's good for Peyto and it's good for the environment.

That work continues on.

Of these initiatives initiatives that we've implemented our goal above and beyond the director of 16.

Compliance requirements zone.

We're doing better than what the industry would.

Good luck.

So this year, we will continue with our high bleed to low bleed control of retrofit program.

We expect that program that project to be completed in June.

We will also be removing controllers on some low rate wells, so essentially turning them from low Vance two of no event.

Well.

We'll continue to install collection devices that capture vented methane from legacy pneumatic chemical pumps and use it as fuel gas in well site heaters.

We will also be retrofitting older high rate wells equipped with pneumatic pumps with electric pumps. This was something that didn't really make sense economically when we started installing electric pumps on our new wells in 2017.

But with advances in power efficiency and pump technology, we can now do it effectively and reliably.

Today, one pump can do for pumps east.

That's injecting different chemicals at different rates with less power consumption than our first generation of electric pumps.

As you mentioned the summer will start receiving our first shipment of fully electric separators to get so we've actually been trialing.

The design and refining that design in the field since 2019, so we've gone through two winter seasons with the with a fully electric <unk> and.

We now have an extremely reliable design and as I mentioned with a really low power consumption. So in the couple of extra solar panels in a couple of extra batteries.

<unk>.

We haven't had any issues through two winters.

The team has also set the trial and in stream pipeline power generator at two separate pads. This year and that provides all of the power needs for each pad as well as recharging the backup batteries.

If successful that could replace solar panels in some applications.

So over the past five years, our efforts are really focused on well sites.

It was sort of low hanging fruit from a cost perspective.

But we've also engaged with technology providers that have been developing solutions for gas plants.

That includes compressor waste heat recovery.

Where the captured weighted can be used to supplement utility duty in of plants and reduced the gas the fuel gas by fired heaters.

Later this year, we'll initiate a feasibility study for a solar panel farm that could supplement the power needs of one of our gas plants.

We've also been working with the company to trial of Jim of geothermal application that has the multitude of potential applications, both at well sites and gas plants. So we hope to advance that trial by the end of the year.

Obviously, the facility implementations can be quite capital intensive, especially compared to what we've been able to do at well sites, but likely seen with well sites. The technology is getting more efficient and the costs are going down.

We anticipate being able to implement some of these applications in the future.

Also theres been a lot of discussion recently about around carbon capture and storage in blue hydrogen.

So thats something that we continue to monitor and.

And we're excited to see what may come on those two of emerging technologies.

Great that sounds really good.

The last question that we saw was actually with respect to acquisitions, we're not typically of big acquire Peyto, we've built almost everything we have today.

From scratch, but we did.

Couple of acquisitions in the first quarter.

Those were the first that we've done in the long time.

Size.

So maybe I can turn to Derek can ask him.

What what else are we seeing coming down the pipe Derek or are we looking at some more more sizable acquisitions of the land sale opportunities starting to emerge now of the Crown land sales are back on the table or yeah. Thanks Darren.

We're constantly in the room to grow our line abuse.

And the acquisitions, whether they would be purchasing assets for.

I mean with drilling commitments, we're entering into swaps generally I believe.

The activity often creates opportunities for with us being active.

It helps us both be proactive and reactive as required also.

Also believe being quick and flexible within the different internal departments helps in this regard.

Our low cost capital structure technical Knowhow and abundant amount of infrastructure.

Can be used as a sort of currency of times to allow us to was down per months on farm ins and purchases.

Whether.

Where others may not be able to do so.

Our BD group is actively looking at additional growth areas. While also continuing to look at it tucked in the acquisitions like facility for example.

In terms of Crown sales, it's definitely.

More active than last year.

In Q1 2021.

But one of $11 million in bonuses for an average of.

On a 95.

$1 of off which is.

Obviously substantial higher than 2020, when there was about seven five months of the chrome sales so.

All in all.

As you mentioned we're not.

We're constantly looking at for.

Further.

Acquisition targets and remodel of them.

They come up or as we are able to generate them.

Okay great.

Well I think thats all the questions that we saw for people and shareholders.

Thanks for everybody for tuning in.

Obviously the back too.

Mid summer with the Q2 results.

We're looking forward actually to another busy year of drilling here at Peyto.

Economics are starting to look stronger and stronger prices Youre looking betters of cash flows are getting stronger our balance sheet is getting a lot better. So things are definitely looking up we're.

We're excited about the balance of this year.

And we're excited us probably the most people are to put COVID-19 behind us.

Finally get to.

Maybe have dinner together.

Some point in the non <unk>.

Hopefully not too distant future.

So anyway, thanks for thanks for tuning in.

What's the website.

P&I will get.

The presentation and updated presentation videotaped and we'll get that up on the website since we can't have an AGM with everybody in the same room.

We'll get a video of presentation.

Hopefully that can shed some more light on where Pete is going and how we're doing so.

So thanks for tuning in this morning, and we'll be back to you in August.

This concludes today's conference call. Thank you all for your participation you may now disconnect.

Okay.

Okay.

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Moving forward.

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The year.

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