Full Year 2023 Peyto Exploration & Development Corp Earnings Call

Operator: Good day, and thank you for standing by. Welcome to Peyto's Year End 2023 Financial Results Conference. At this time, all participants are in a listen-only mode.

Good day, and thank you for standing by.

Welcome to the pesos year end 'twenty financial results conference call.

At this time all participants are in a listen only mode.

Operator: After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your question is. To withdraw your question, please press star 1 1 again.

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

To ask a question during the session you will need a press star one one on your telephone.

You will then hear an automated message advising your hand is raised.

Your question. Please press star one one again.

Operator: Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, President and CEO J.P. LaChanze. Please go ahead.

Please be advised that today's conference is being recorded.

I would now like to hand, the conference over to your speaker today.

<unk> and CEO J P well Sean Please go ahead.

J.P. LaChanze: Thanks, Daniel. Good morning, folks. And thanks for joining Peyto's 2023 year-end results conference call. I'd like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory set forth in the company's news release that was issued yesterday. In the room with me to answer any questions, we have Kathy Turgeon, our Chief Financial Officer, at least until the end of the month, Riley Frame, our VP of Engineering and Chief Operating Officer, Tavis Carlson, our VP of Finance, soon to be CFO, Todd Burdick, our VP of Production, Derick Czember, our VP of Land and Business Development, and last but certainly not least, Lee Curran, our VP 2023 was an eventful year for Peyto.

Thanks, Daniel Good morning, folks and thanks for joining Pedro is 2023.

Year end results conference call.

I'd like to remind everybody that all statements made by the company. During this call are subject to the same forward looking disclaimer and advisory set forth in the company's news release issued yesterday was issued yesterday.

In the room with me to answer any questions. We have Kathy George our Chief Financial Officer at least until the end of the month rally frame, our VP of engineering and Chief operating Officer, David Carlson, our VP of finance and soon to be CFO.

Todd Burdick, our VP of production.

Eric <unk>, our VP of business development, and last but certainly not least Lee Curran, our VP of drilling and completions.

Before we discuss the quarter and year on behalf of the Magic group I'd like to thank the <unk> team for their contributions to a strong quarter a strong year.

And your efforts towards integration of our new assets.

Slide 23 was eventful year for Pedro.

J.P. LaChanze: We had a few changes, but change can be good. We closed a meaningful acquisition in the fourth quarter. We refreshed the senior management team as part of our quarterly succession plans, and we turned 25 years old.

Got a few changes the change change can be good.

What was the meaningful acquisition in the fourth quarter, we refreshed the senior management team as part of our succession plans and we turned 25 years old.

J.P. LaChanze: One thing that won't change is the team's commitment to the profitable growth of Peyto's assets using the approach that's made us so successful over the last 25 years. And, of course, I'm talking about our focus on being good stewards of shareholder capital by keeping our costs down, owning and controlling our infrastructure, securing our revenues through hedging and diversification, and returning profits back to shareholders. Okay, the big event last quarter and last year was the acquisition of the Repsol asset. I'll forgo the nitty-gritty details of the deal because, by now, you've heard it all, the multitude of quality locations we essentially didn't have to pay for, the synergies with the infrastructure in the field, and the fact that we know these lands like the back of our hands. The important thing is that now that we've been able to operate them for a little while, they are what we thought they were. They're basically what we expected.

One thing that doesn't change is the team's commitment to the profitable growth of payrolls assets using the approach that has made us so successful over the last 25 years.

And of course, I'm talking about our focus on being good stewards of shareholder capital by keeping our cost down only controlling our infrastructure securing our revenues through hedging and diversification and returning profits back to shareholders.

Looking at the Big event last quarter and last year was the acquisition of the Repsol assets.

Ill go into an integrated E mails with the deal because by now you've heard it all of them.

Multitude of all the locations, we essentially didn't have to pay for it.

Energies with the infrastructure in the field.

We know these last like tobacco.

The important thing is now that we've been able to operate them for a little while they are where we thought they were.

J.P. LaChanze: We're getting some fantastic results with our drilling program, and there are numerous opportunities to optimize and drive down costs in the field. And maybe I'll get Todd to elaborate a little later with some details on the projects that his team has been working on over the last few months. Certainly, operating cost reduction will be a focus for Peyto in 2024. Although the acquisition and the metrics of the deal are great, they are not to be outdone by the very effective drilling program that was executed by the team last year. We spent less than the low end of our guidance, and we delivered reserves of PDP fighting costs of $1.15 per MCFE, or if you include the acquisition PDP, FD&A was a total of $1.21 per MCFE. I believe that's best in class amongst our peers.

Basically what we expected we're getting some fantastic results with our drilling program and there are numerous opportunities to optimize and drive dot plots in the field and maybe I'll get touch elaborate later with some details on the prop.

<unk>.

But as soon as they're working on over the last few months.

Certainly operating cost reduction will be a focus.

2024.

Although the acquisition and the metrics of the deal are great.

It's not to be all done by a very effective drilling program that was executed by the team last year.

We spent less in the low end of our guidance we delivered reserves.

Finding costs of $1 15 per Mcf.

Or if you include the acquisition PDP FTE was was a total of $1 21 per Mcf and I believe that's a best in class amongst our peers.

J.P. LaChanze: With the help of our disciplined hedging program and our diversification, we managed to mitigate the impacts on funds from operations despite the significant drop in average daily ECO and NIMEX prices by 50% and 60%, respectively, from 2022 levels. In fact, 2023 was the third highest year of funds from operations per share in the company's history, and even without our hedging program, it's the third best year we've had, and it sort of points to the underlying qualities of the business. One of the qualities, one of those qualities is our, of course, our industry-leading field costs, which helped us to build a solid three dollars and fifty one cents per MCFE field net return. And when you combine that with our FT&A, it yielded a two point nine times PDP recycle ratio for the year. And I think that that competes with the best in class.

With the help of our disciplined hedging program and our diversification, we managed to mitigate the impacts on funds from operations. Despite the significant drop in average daily April with Nymex prices by 15, 6% respectively.

2020 levels.

2023 was the third highest year of funds or funds from operations funds from operations per share.

In the company's history.

Even without our hedging program. It is the same.

Here, we've had and it sort of points to the underlying qualities of the business.

One of the qualities wearables qualities as our horses are industry, leading yields cost, which helped us to build a solid.

<unk> 51 per Mcf.

You'll get back and when you combine that with our FTAA yielded us two nine times PDP recycle ratio for the year and I think that's the piece to best.

J.P. LaChanze: So, we did have a little noise in the corridor with our cash costs. Operating costs are up as we expected with the new facilities, and interest costs are also up as we took on some incremental debt to get the deal done last October. There were some one-time costs relating to the acquisition financing and integration that translate into about nine cents per MCFE and that we don't expect to carry forward.

In class Salt.

We did have a little noise in the quarter with our cash cost operating costs are up as weak as we expected with the new facilities and interest costs are also up as we took on some incremental debt to get the deal done last October there was some one time costs relating to the relating to acquisition financing and integration translates into about <unk> <unk> per Mcf.

We don't expect to carry forward.

J.P. LaChanze: Looking forward, with gas prices where they are, we're acting prudently with our capital plan for 2024. We're targeting the low end of our capital guidance, closer to $450M for now, and we'll watch prices closely and adjust our spending accordingly. Similar to last year, we expect to slow down in Q1 during the breakup and then ramp back up when we have greater confidence in the forward strip. The degree that we slow down or bring on production will depend, of course, on the cooperation of spring and summer weather.

Looking forward with gas prices, where they are.

We are acting prudently with our capital plan for 2024, you're targeting the low end of our capital guidance closer to $450 million for now and we'll watch prices closely and adjust our spending accordingly.

Similar to last year, we expect to slow down in Q1 during breakup and then ramp back up when we have greater competency forward strip.

The degree that we slow down or bring on production will depend of course on the cooperation of.

The spring and summer weather.

J.P. LaChanze: If the rains come, which of course, Alberta needs right now, it will slow us down. And there is a real concern about drought conditions in Alberta. If you read the recent Payto Monthly report, you know we don't typically use water from surface sources.

But the range com, which of course, Alberta needs right now it will slow us down.

And there is a real concern around drought conditions in Alberta, If you read the recent monthly report.

We don't typically use water from surface sources, we draw water wells for our drill for our development program and we use a lot less water than most because of the quality of our reservoirs.

J.P. LaChanze: We drill water wells for our development program, and we use a lot less water than most because of the quality of our reservoirs. And, of course, we have a flow-back recycling program that we try to implement as well. So, we don't believe drought conditions will affect our drilling program at this point. We have a major turnaround plan for the Edson plant. It's a one in 10 year turnaround. It's broken up into two parts.

Of course, we have a well.

Recycling program that we try to implement as well. So we don't believe drove conditions will affect our drilling program at this point in time.

We have a major turnaround plan for the Hudson plant one in 10 year turnaround, it's broken up into two parts. One is in April and the balance in September those costs are included in our budget and we expect that there'll be minimal production impacts over those quarters, but of course until we get under the Hood.

J.P. LaChanze: One is in April and the balance in September. Those costs are included in our budget, and we expect there'll be minimal production impacts over those quarters. But of course, until we get under the hood, we'll never really know. But in the long term, we're still very optimistic about natural gas prices. We believe the start-up of LNG Canada and the build-out of LNG shipments in the U.S. over the next couple of years is constructive for the commodity and that demand for natural gas isn't going anywhere anytime soon. In fact, with all the coal-fired plants that are still being built around the world, there's a great opportunity to displace those plants with cleaner-burning LNG in the future.

No.

Longer term, we still have we're still very optimistic.

So gas prices, we believe the startup of LNG, Canada, the build out of LNG egress in U S. Over the next couple of years is constructive to the commodity.

Demand for natural gas isn't going anywhere anytime soon.

With all the coal fired plants that are still being built around the world is a great opportunity to displace those with those plastics cleaner burning LNG in the future.

But in the meantime, our diversification and hedging program has our revenues well protected in 2024, approximately 70% of our forecasted volumes.

J.P. LaChanze: But in the meantime, our diversification and hedging program will keep our revenues well protected in 2024. Approximately 70% of our forecasted volumes are hedged. And even in 2025, where we have about 56% of our forecast gas volumes fixed against gold prices. So that gives us the confidence to execute our capital program, pay our dividend, and pay down some debt for the balance of the year. One of those diversification markets is the 60,000 GJs a day or 52 million cubic feet a day gas supply agreement that we have with the cascade power plant. We're ready and keen to start delivering gas to that plant, but that won't begin until they are fully operational. They did have some startup problems, but they are continuing to work through the commissioning stages, and we expect to be providing them with gas sometime during the second quarter.

Our hedged and even in 2025, where we have about 56% of our forecast.

Gas volumes fixed against low prices. So it gives us the confidence to execute our capital program pay our dividend and pay down some debt for the balance of the year.

One of those diversification markets as the 60000, <unk>, a day or 52 million cubic feet a day.

Gas supply agreement that we have to the gap to the Cascade power plant.

We're ready to start delivering gas to that plant, but that won't begin until they are fully operational.

They did have some startup problems and they are continuing to work through the commissioning stages, and we expect to be providing them. Some.

Sometime during the second quarter.

So that kind of wraps it up but before I go to some questions from the Florida.

Overnight from the E.

So maybe I'll get you to provide an update on your team's latest plans on optimization and cost reduction projects.

Do you guys have achieved so far this year and plan to do for the remainder of the year.

Sure JP.

J.P. LaChanze: So that kind of wraps it up, but before I go to some questions from the phone or from overnight from the emails, Todd, maybe I'll get you to provide an update on your team's latest plans on optimization and cost reduction projects that you guys have achieved so far this year and plan to do for the remaining of the year. Yeah, sure JP. Been a very busy four and a half months.

It's been a very busy for five months.

Prior to closing we have prepared some initial plans and ideas as we see it took a few weeks to get familiar with the assets.

The new employees, new staffs and determine where to focus our initial efforts now.

Now regarding that staff.

We kept about two thirds of the field operations people and about half of that total field people.

Todd Burdick: Prior to closing, we had prepared some initial plans and ideas, and obviously, it took a few weeks to get familiar with the assets, the new employees, and the new staff and determine where to focus our initial efforts. Now regarding that staff. We kept about two-thirds of the field operations people and about half of the total field people. And for many of those folks that we retained, it was a bit of a shock, and we needed to give them confidence that, you know, things would run fine with less people because, essentially, our processes in the field are quite a bit more efficient than the way that the Repsol framework kind of runs. It was imperative that we introduce the pay-to-play culture and explain the company's hands-on and accountability philosophies.

And for many of those folks that we retained it was a bit of a shock and we needed to give them confidence that things would would run fine with with less people because.

Essentially our processes in the field are quite a bit more efficient.

The way that the Repsol framework kind of runs itself.

It was imperative that we introduced the <unk> culture and explain the company's hands on and accountability philosophies.

And as we sit here today I can comfortably say that a large majority of those folks have embraced embraced this philosophy and what Pedro gets out of that as production focused and cost conscious individuals operating the company's assets.

Ironically, I guess, a long stretch of minus 40 degree weather really helps that bring the team together.

Todd Burdick: And as we sit here today, I can comfortably say that a large majority of those folks have embraced this philosophy. And what Peyto gets out of that is production-focused and cost-conscious individuals operating the company's assets. And ironically, I guess a long stretch of minus 40 degree weather really helped bring the team together. So, as we went through that initial period, we were also working on integration and optimization initiatives and started to identify specific projects. In many ways, we felt like kids in a candy store.

So as we went through that initial period. We were also working on integration and optimization initiatives and started to identify specific projects.

In many ways.

Okay.

So much out there that we wanted to do that.

Hope we can do so.

But initially well optimizations began immediately following the acquisition.

We started seeing gains in the first month.

Most part things, where we're in really good shape as far as the assets, we acquired but there were still some things that we were able to introduce.

Todd Burdick: There was so much out there that we wanted. Good. Initially, well optimization began immediately following the acquisition. We started seeing gains in the first month. For the most part, things were in really good shape as far as the assets were concerned. But there were still some things that Peyto does that we were able to do.

Those efforts, especially downhole equipment.

Joining me today.

We've been working hard on improving plant reliability and run time.

The press release had mentioned that looking at several initiatives to improve reliability following the cold snap in January.

And the initiatives.

Todd Burdick: Those efforts, especially downfall equipment work, are continuing. We've been working hard on improving plant reliability and runtime. The press release mentioned us looking at several initiatives to improve reliability following the cold snap in January and the initiatives we're looking at and applying, not only during cold weather but year-round operations. Prior to the acquisition, we were operating 11 gas plants at a runtime of 99%, so we're taking that expertise and applying it to the 4 operating plants that we purchased, and we're seeing results. Reliability and reduced off-rate

Looking at applying not only client cold weather, but year round operation.

Prior to the acquisition, we were operating 11 gas plant run time with 99%.

<unk> expertise in applying it to that or creating bad debt repurchase.

Pete.

Liability.

Reduced operator.

With respect to operating costs, we were modeling slightly higher cost per key for so I'm cautiously optimistic.

<unk> from a lower spot than we expected.

Maybe we were able to do more than we anticipated in the three months, but either way it's encouraging.

We've also been busy connecting pipeline infrastructure in many cases these projects allow pedro to process all that new production underutilized gas plant one of the things we're focusing on.

Todd Burdick: With respect to operating costs, we were modeling slightly higher costs for Q4, so I'm cautiously optimistic that we're starting from a lower spot than we expected. Maybe we were able to do more than we anticipated in those three months, but either way, it's encouraging here early on. We've also been busy connecting pipeline infrastructure. In many cases, these projects allow Peyto to process old and new production at underutilized gas plants, one of the things we're focusing on. And once we received regulatory approval in December, we were able to tie two Repsol pipelines into Peyto pipelines in the Old Man area. This included diverting a compressor station from the Edson gas plant into the much closer Old Man gas plant. And the second project effectively gave us some swing capability to move gas out of the Med Lodge plant into either Old Man or Swan.

Once we receive regulatory approval in December we were able to tie to repsol pipelines into 800 pipelines in the old man area.

This included diverting a compressor station from the <unk> gas plant into the much closer gas plant.

The second project effectively gave us swing capability to move gas out of <unk> into either old man or swaps.

Here moving into 2024, we've done two more infrastructure projects in January we completed a project at Newberg gas from CRE.

Over the river.

That helped to load the currently capacity Cecilia plant and see a better liquid recovery on that diverted gas.

Todd Burdick: Here moving into 2024, we've done two more infrastructure projects. In January, we completed a project to divert gas from Cecilia over to Wild River that helped to offload the currently at-capacity Cecilia plant and see a better liquid recovery on that diverted gas. And the second project is similar to the one I mentioned we did in December, where we added some swing capability between MedLodge, Old Man, and Swanse

Second project is similar to what I mentioned, we get into December where we added some swing capability between Med Lodge hold Matt It's Scott.

We're currently waiting on regulatory approval to do a large header modification that will tie in large diameter infrastructure between old man slots in the Edson.

This is a precursor to a debottlenecking project. We are planning later this year that will connect what liver structure.

This again is to accommodate drill pads in the area, but again gives options to move gas in and out of plans as needed, especially during.

Todd Burdick: We're currently waiting on regulatory approval to do a large header modification that will tie in large diameter infrastructure between Old Man, Swanson, and the Edson Gap. This is a precursor to a deep bottlenecking project we are planning later this year that will connect Swanston infrastructure to the rest of the system. This again is to accommodate drill plants in the area but again gives options to move gas in and out of plants as needed, especially during upsets and outages.

And outages.

And it also gives us more flexibility to reliably deliver gas to the gas to Cascade.

And we're not done so early in Q2, we plan to divert significant volume.

Coffee third party facilities in the <unk> area.

Send them down to <unk> for processing and then later in Q2, we will be reactivating, a large compressor station in the Edson area to accommodate the drilling down there.

Beyond that we have four or five other projects that were either waiting on regulatory approval or internal scoping and cost estimating they may or may not come to fruition, but it's better to happen shovel ready as a work.

Todd Burdick: And it also gives us more flexibility to reliably deliver gas to the gas gate power plant. And we're not done. So early in Q2, we plan to divert significant volumes out of costly third-party facilities in the Wild River area and send them down to Edson for processing, and then later in Q2, we will be reactivating a large compressor station in the Edson area to accommodate the drilling that's happening down there. Beyond that, we have four or five other projects that we're either waiting on regulatory approval or internal scoping and cost estimating. They may or may not come to fruition, but it's better to have them shovel-ready, as it were. And we're always, it seems, coming up with new ideas of things we can do.

We're always seems weekly coming up with new ideas and things we can do.

We will execute on those.

<unk> and <unk> are.

Our development program continues.

But all in all were happy with where we're at.

We know there is lots more to do.

And we're constantly working on that.

Yes.

Okay. Thanks Todd.

Now, let's turn factor. Thank you very much okay, we'll open it up to questions now Daniel please.

Sure.

Thank you.

As a reminder to ask a question. Please press star one on your telephone and wait for your name to be announced to withdraw. Your question. Please press star one one again.

Todd Burdick: We'll execute on those. Transcription by Trans-Expert at Fiverr.com. Our development program continues, but all in all, we're happy with where we're at. We know there's lots more to do.

Please standby, while we compile the Q&A roster.

Our first question comes from Amir Arif with <unk> capital markets. Your line is now open.

Thanks, Good morning, guys I appreciate the color on the different projects.

J.P. LaChanze: We're constantly working on that. Good. Thanks, Todd. Wow, lots to unpack here.

Operating costs, one just curious could you put out.

Operator: Thank you very much. Okay, we'll open it up to questions now. Daniel, please. I imagine there's a few on the floor.

Quantify what the impact could be over the year I understand it's only been a few months but.

Operator: Thank you. As a reminder, to ask a question, please press star 1 1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1 1 again.

Thinking about a 5% or a temperature.

And the Opex over one year two years.

Thanks, Samir, Yes, I think.

I would think about this if it's a bit early to tell exactly what we're going to see here, so we'd like to I'd like to get some some history.

Amir Arif: Please stand by while we compile the Q&A roster. Our first question comes from Amir Arif with AKB Capital Markets. Your line is now open.

Maybe one number but.

I would point you to.

Slide in our corporate presentation of possible cash cost in aggregate and points to sort of what we how we see the business changing over the next three years.

J.P. LaChanze: Good morning, guys. I appreciate the color on the different projects you're doing in the operating cost fund. Just curious, could you help us quantify what the impact could be over the year? I mean, I understand it's only been a few months, but are you thinking about a 5% or 10% improvement in unit opex over 1 year, 2 years? Thanks, Mary.

Slide 21 in the January presentation here has a little bit of color around our our cash costs, excluding royalties and taxes. It gives you a sense of where with how we see the total aggregate will be so we of course, we expect some kind of reduction seal five or 10 per se not unreasonable, but I think we need to see some history here first speak to earlier.

J.P. LaChanze: Yeah, I think I would think about this, and it's a bit early to tell exactly what we're going to see here. So we'd like, I'd like to, thank you for joining us. All in favor? Aye. Opposed?

Fair enough I appreciate that color just a question on the hedging side I'm, just given that you're significantly larger gas producer now historically, you've focused mostly on financial contracts for your hedging just curious with the larger size do you plan to include more physicals or do you plan to continue to focus on financials for the majority of your <unk>.

J.P. LaChanze: Aye. Thank you. Our presentation talks about cash costs in aggregate and points to sort of what we, how we see the business changing over the next three years. I think slide twenty-one in the January presentation has a little bit of color around our cash costs, excluding royalties and taxes. It gives you a sense of where we feel the total of the aggregate will be. So, we, of course, we expect some kinds of reductions, you know, five or ten percent is not unreasonable, but I think we need to speak to history here first to be fair. Yeah, fair enough. I appreciate that cover.

Okay.

Yes, right now we do have a little bit of both as you know we have some physical we have physical volumes that go to Emerson.

And we do have some other some of our other contracts are in fact physical relationships.

And so it's not all just financial.

So I think we will continue that sort of mixes that will go forward you know that we like to we'd like to do some will be called basis deals to get ourselves thats, what we call synthetic.

<unk> to other markets and we'll continue doing that where we are continuing to do that to get to allow us to to to access those other hubs and other places without having to make that long term physical commitment, but we do have some some already that are physical right.

J.P. LaChanze: Just a question on the hedging side. I'm just given that you're a significantly larger gas producer now. Historically, you focused mostly on financial contracts for your hedging. I'm just curious, with the larger size, do you plan to include more physicals, or do you plan to continue to focus on financials for the majority of your time? Right now, we do have a little bit of both.

<unk>.

Yes, yes, that's a participant in terms of the incremental gas volumes at those can we must have the financial or do you plan to keep a similar mix.

Do we think we can we get good value for them, we will consider for sure yes physicals.

Okay.

Sounds good and then just a final question on the.

J.P. LaChanze: We have some physical volumes that go to Emerson, and we do have some of our other contracts that are, in fact, physical relationships, so it's not all just financial. I think we'll continue that sort of mix as we go forward. You know that we like to do what we call basis deals to get ourselves what we call synthetic exposure to other markets, and we'll continue doing that. We are continuing to do that to allow us to access those other hubs and other places without having to make that long-term physical commitment, but we do have some already that are physical. Emerson, New York

On the eight wells that you had drilled on the Repsol lines better <unk> on those wells, but then your historic Standalone wells.

And a specific zone or is that a good.

Cross section of different zones that you'd be targeting on the repsol lines in terms of the EUR per well that we saw bodes well.

Yes. Those are obviously, we have to get to drill those first few wells. These were wells that we would've had locations, where we can use our own surfaces or something that we have prepared so, but maybe I'll, let ryan talk to the specifics around the species mix there.

So those wells were predominantly non accruing wells. There was also a couple of upper pillar wells.

J.P. LaChanze: Yeah, but just in terms of the incremental gas volumes, is that going to be most of the financial, or do you plan to keep a similar, To the extent that we can, we can, you know, we get good value for them, we'll consider them for sure, yes, physical. And then just a final question on the eight wells that you had drilled on the Webster land, which had better EURs on those wells than your historic standalone wells. Were those in a specific zone, or is that a good cross section of different zones that you'd be targeting on the Repsol lines in terms of the EUR per well that we saw? Yeah, those were obviously the ones that we had to, you know, to get to drill those first few wells; these were wells that we would have had locations where we could use our own surfaces or something that we had prepared.

Well in there so I wouldn't say it's a.

Total cross section of what we have out there is there's obviously a lot of well rich and vegan and a lot of other plays.

So yes, it's definitely is I'd say at this point, but we are also seeing in the wells that we've drilled in the first half of this year.

We've gotten into the well rich and some of the other plays and we're seeing just as good a results out of those wells.

Overall here.

From last year into the first half of this year. The cross expertise is pretty representative and it's holding up sort of where we would expect is.

Really high caliber results.

Okay, perfect I point, Jim here too our February report it gives us a nice breakdown of what was drilled into those eight wells in our February.

Monthly report there thank you.

Thank you.

One moment for our next question.

Our next question.

Riley Frame: So, but maybe I'll let Riley talk about the specifics around the species mix. Yeah, so those wells were predominantly Nauticuan wells. There were also a couple of upper Calaire wells in there. So, I wouldn't say it's a total cross-section of what we have out there. There's obviously a lot of Willeridge, Dundagan, and a lot of other plays.

Comes from Michael Harvey with RBC capital markets. Your line is now open.

Yeah sure. Good morning, Thanks for taking taking the question. So just a quick one on your.

Horizontal well lengths. So it looks like your your wells got quite a bit longer than 23% after years of being <unk>.

Riley Frame: So, yeah, it's definitely an upset at this point, but we are also seeing in the wells that we drilled in the first half of this year; we got into Willeridge and some of the other plays, and we're seeing just as good results out of those wells. So, I think overall, from last year into the first half of this year, the cross-section we're seeing is pretty representative, and it's holding up sort of where we would expect as really high-caliber results. I point you, Amir, to our February report. It gives a nice breakdown of what was drilled in those eight wells in our February monthly report there. Thank you. Thank you.

Being reasonably flat.

Do you see that increasing further in 2020 forward just with.

The Repsol lands end.

What some of the other operators are doing and then how do you kind of balance that.

Longer horizontal well.

With overall inventory numbers, which would of course come down a bit with longer wells.

Now, let me get right to answer that question here I think generally speaking we would have our location counts would include what we expect to drill for length, but maybe around it.

On our reserve reporting.

I would expect that our horizontal length well continue to increase slightly here over the next couple of years.

Michael Harvey: One moment for our next question. Our next question comes from Michael Harvey with RBC Capital Markets. Your lines know it. Yeah, sure. Good morning.

We're just the quantity of wells in our program is our <unk> qualifiers extended or extended reach is going up.

Obviously with the addition of the Repsol lands it kind of gave US obviously, a reset and so what we've been able to book on those lands is actually mostly mylan.

Michael Harvey: Thanks for taking the question. So just a quick one on your horizontal well length. So it looks like your well's got quite a bit longer in 2023, just after years of being reasonably flat. Do you see that increasing further in 2024, just with the Repsol lands and what some of the other operators are doing? And then how do you kind of balance that longer horizontal well, just with overall inventory numbers, which would, of course, come down a bit with longer wells? I'll maybe get Riley to answer that question here.

Mile and a half from two mile wells.

So yes, so over the next little while here I would I would expect that number to keep creeping upwards.

And then just as far as what was booked.

Is reflective of how we're going to attack. It we went through a process a few years ago of trying to sort of correct. Our reserve book spread sorry, how we were actually drilling wells and so by virtue of how we book the repsol assets and everything else. This year. It is fairly reflective of the longer laterals in the reserves.

Riley Frame: I think, you know, generally speaking, our location counts would include what we expect to drill for length, but maybe Riley is that on our reserve reporting, which looks like. Yeah, so I would expect that our horizontal length will continue to increase slightly here over the next couple years. You know, we're just, the quantity of wells in our program that sort of qualifies as extended reach is going up. You know, obviously, with the addition of the Repsol lands, it kind of gave us a reset.

Great. Thanks, guys.

Michael.

Thank you one moment for our next question.

Our next question comes from Gerry Mccaughey, an Investor Your line is now open.

Yes.

My first question pertains to the pre and post Repsol comparison.

The value of our liquids.

<unk>.

Before repsol.

The numbers seem to be 11%, 12% liquids and now the numbers seems to be percentage wise.

On a volume basis, a little bit higher my question is.

Riley Frame: And so, what we've been able to book on those lands is actually mostly mile and a half and two mile wells. So yeah, so over the next little while here, I would expect that number to keep creeping upwards. And then just as far as what was booked, it is reflective of how we're going to attack it. We went through a process a few years ago of trying to sort of correct our reserve books to sort of how we were actually drilling wells. And so, by virtue of how we book the Repsol assets and everything else this year, it is fairly reflective of the longer laterals in the reserve. Thanks, guys. Michael.

If we rather than looking on a volume basis, we would look at it look at it on an economic basis as measured by the dollar value of the <unk>.

<unk>.

It's my impression that the dollar value of the liquids.

Proportionally.

The addition would have declined because the repsol liquids.

Alright different.

Combination of Theres more.

Value.

Components to the liquids.

That I don't know, if ive said that right, but I'm just interested in.

If that is correct and how.

How we should look at that in terms of the numbers alright.

Jerry McCaughey: Thank you. One moment for our next question. Our next question comes from Jerry McCaughey, an investor. Your line is now open.

Alright, the ethane in the Repsol lands for instance is a lower value than the percentage condensate in the legacy payroll production.

Jerry McCaughey: Yes, my first question pertains to the pre and post-REPSOL comparison of the value of our liquids. Before Repsol, the numbers seemed to be 11-12% liquid, and now the numbers seem to be, percentage-wise on a volume basis, a little bit higher. My question is... Rather than looking at it on a volume basis, we would look at it on an economic basis as measured by the dollar value of the liquids. It's my impression that the dollar value of the liquids, Proportionally for the addition, would have declined because the Repsol liquids are a different combination of there are more lower value components to the liquids.

Yes, so hi, Jerry just to frame that a little bit. So we bought 23000 barrels of which 75% of our gas and 25% were liquids, but as you pointed out a fair bit of that and.

And it was in the original presentation is a fair bit but some of it is about 2000 barrels of liquids is ethane so from a value perspective, essentially gas value and one of the things that Tom.

Yes.

Todd was referring to was moving some gas from the Wild River area down into Edson.

In fact to change that up a little bit here, and we're going to rather than paying someone to remove ethane, which we really get into much much more value of this would be a cost savings matter in the second quarter, we plan to move the volumes that we normally would be sending over too.

J.P. LaChanze: I don't know if I've said that right, but I'm just interested in whether that is correct and how we should look at that in terms of the numbers. Like the ethane in the RepSol lands, for instance, is a lower value than the percentage condensate in the legacy Peyto production. Yeah, so hi, Jerry.

To that to that deep cut facility down through to Edson instead.

So that will help increase our utilization and ipsen will also.

We lowered our cost structure, so that will sort of right itself in time here as we as we remove less of the ethane from our gas stream, so minor impact on liquids our liquids volumes.

J.P. LaChanze: So just to frame that a little bit, we bought 23,000 barrels of which 75% were gas and 25% were liquids. But as you point out, a fair bit of that, and it was in the original presentation, is, or not a fair bit, but some of it is about 2000 barrels of the liquids are ethane. So from a value perspective, essentially gas value. And one of the things that Todd was referring to was moving some gas from the Wild River area down into Edson is, in fact, to change that up a little bit here, and we're going to rather than paying someone to remove ethane, which we really don't get much, not much more value. This would be a cost savings matter in the second quarter.

But essentially.

The increase if you think about an increase in value to us right.

Right.

That's great.

And.

Just to.

A couple of quick follow ups.

I noticed in the MD&A that the hedging that's been done since <unk>.

Since the end of the of the.

Quarter on the gas side was pretty limited.

20000, Giga jewels for April one 2006 to October 26.

That would be slower than the normal.

Pace that we've seen in the past.

I'm just curious if that's.

Represents any.

J.P. LaChanze: We plan to move the volumes that we normally would be sending over to that deep cut facility down through Edson instead. That will help increase our utilization at Edson, and it will also lower our cost structure. That will sort of write itself in time here as we remove less of the ethane from our gas stream, so a minor impact on liquids volumes, but probably an increase in value to us.

Change in.

The the approach or.

If it's well I'll, let you answer that sorry.

Yes.

So no we don't.

Look at our past we've.

Or is that sort of three years out we would normally be hedging three years out, which we're doing and we're continuing to do so we will we are still going to take 26 off the table. We'll continue to do that as we move forward in that sort of a mechanical way. We took a lot more opt table 25, when we did the deal and that was to help protect some revenues.

Jerry McCaughey: Right. Okay, that's great. And just a couple of quick follow-ups.

J.P. LaChanze: I noticed in the MD&A that the hedging that's been done since the end of the quarter on the gas side has been pretty limited 20,000 gigajoules for April 1, 26 to October 26. That would be slower than the normal pace that we've seen in the past. So I'm just curious if that represents any change in the approach or if it's, well, I'll let you answer that, sorry. Yeah, so no, we don't. If you look at our past, that's sort of three years out.

On the front end of the deal. So that's why it's a 25 is higher than it normally would be.

And we're happy that it is so we're going to continue on with hedging 2006 here Jerry as we move forward. So there isn't a change in strategy with respect to that and we will.

Continue to move.

More volumes as we move forward here.

Just the pace looked a little slower since the quarter end and.

I shouldnt take that as indicative of the pace going forward is what youre, saying, yes, Okay I'll give you I'll let.

J.P. LaChanze: We would normally be hedging three years out, which we're doing and we're continuing to do. So we are still going to take 26 off the table. We'll continue to do that as we move forward in that sort of mechanical way. We took a lot more off the table in 25 when we did the deal, and that was to help protect some revenues on the front end of the deal. So 25 is higher than it normally would be, and we're happy that it is.

Thomas just elaborate a little bit more on this Jerry.

Yes, Jerry in the MD&A, we are disclosing just the financial transactions that we've done subsequent to the yearend, but we've also been fixing some some of our gas but physical deal.

No.

And we will be presenting our new marketing slides later today, so you'll be able to see where we're at.

Perfect.

Perfect.

J.P. LaChanze: So we're going to continue on with hedging 26 here, Gary, as we move forward. So there isn't a change in strategy with respect to that, and we'll continue to hedge more volumes as we move forward. It's just the pace looked a little slower since the quarter end, and I shouldn't take that as indicative of the pace going forward, as you say.

That's a great answer and just to sneak in two quick keys Cascade at current electricity prices is there any parallels that you can draw to what that would be on a gradual basis.

The last one is when.

When you look at your Capex choices over the course of the year is the objective to keep that flat for the year or to have it flat.

Tavis Carlson: Yeah, okay. I'll let, maybe I'll let Tavis just elaborate a little bit more on this, Jerry. Yeah, Jerry, in the MD&A, we're disclosing just the financial transactions that we've done subsequent to the year end, but we've also been fixing some of our gas with physical deals. And we'll be presenting our new marketing slides later today, so you'll be able to see where we're at. Perfect. Yeah, perfect. And just to sneak in two quickies, Cascade. At current electricity prices, is there any parallel you could draw to what that would be on a gigajoule basis?

Flat or lower are you using that as one of your disciplines not just price that's it for my questions. Thank you very much.

As far as Cascade goes yes, we don't.

I don't we don't disclose the details.

The contract is.

Because it's confidential but.

Certainly current power prices, we would be doing better than April today. So so obviously, we want to get that up and running as soon as we can.

<unk>.

As far as your second part sorry, Jerry as far as your second question was more about allocation of capital for rest of the year is that where youre going.

Yes, it was.

J.P. LaChanze: And the last one is, when you look at your CapEx choices over the course of the year, is the objective to keep debt flat for the year or to have it flat or lower? Are you using that as one of your disciplines, not just price? That's it for my questions. Thank you very much.

I know that to a certain degree.

If prices were a lot better.

Things look great that that.

And conditions are very good.

Spending more on Capex kind of follows from that but under a status quo where we're.

Where things are more.

J.P. LaChanze: So as far as Cascade goes, yeah, we don't, uh, I don't, you know, we don't disclose the details of the, uh, the contract because it's confidential, but certainly at current power prices, we'd be doing better than ACO today. So, obviously, we want to get that up and running as soon as we can. As far as your second part, sorry, Jerry, as far as your second question, it was more about the allocation of capital for the rest of the year. Is that where you're going? Sorry. Yeah, it was your fault; I know that to a certain degree.

Conservative.

Are you are you targeting to keep the debt.

More or less either here or lower.

And I understand that I don't want to tie your hands here, but in general is that how you would look at the debt levels.

Yes at this point in time with the current plans, we have Jerry going forward.

The current price levels and our production.

Although we have on our revenues with all the hedging we've done here, we don't anticipating we're not anticipating adding that in fact, we expect to pay down debt in the four months of the year it.

It is not at all but we look at it per se when we look at the capital program, we think a lot of that.

J.P. LaChanze: You know, if prices were a lot better, and things looked great like that, and conditions were good, spending more on CapEx, you know, kind of follows from that, but under the status quo where we're, you know, where things are more conservative, what are you targeting to keep the debt? More or less, either here or lower. And I understand that I don't want to tie your hands here, but in general, is that how you would look at the debt levels? At this point in time, with the current plans we have going forward and at the current price levels and the protection that we have on our revenues with all the hedging we've done here, we're not anticipating adding debt. In fact, we expect to pay down debt in the fullness of the year.

Does it make sense to be drilling. These wells are certainly economic at today's prices, but do we want to blow that inventory at lower prices and adapt the prudent thing to do with shareholders money. So that's how we'll look at the capital program going forward, but we do I would think with the current plan expect to continue to pay down debt at least at the balance of the whole year I think.

And Terry our term loan.

Okay.

Amortizing into all right, we'll be paying $58 million.

Got it and that facility in 2024.

Okay. Thank you very much and great job through the quarter team. Thank you.

Thanks Jerry.

Thank you.

Once again as a reminder to ask a question. Please.

One one.

On your telephone.

Again that is star one one on your telephone to ask a question.

J.P. LaChanze: It is not a toggle we look at per se. When we look at the capital program, we think about it as, does it make sense to drill these wells? They're certainly economical at today's prices, but do we want to blow out that inventory at lower prices? Is that the prudent thing to do with shareholders' money?

One moment for our next question.

Our next question comes from Chris Thompson with CIBC. Your line is now open.

Yes. Good morning, Thanks for taking my question here.

Just to follow up on that discussion.

J.P. LaChanze: That's how we'll look at the capital program going forward. But we do, with the current plan, expect to continue to pay down debt, at least for the balance of the whole year. And Jerry, our term loan is... This is amortizing as well, right?

At the time of the Repsol announcement, you had announced.

Leverage of one times debt to EBITDA by the end of 2025 and that was on better pricing back then just wondering when you guys.

Run it using more recent pricing, where do you see yourselves getting to in terms of reaching that threshold.

Tavis Carlson: We'll be paying about $58 million down on that facility in 2024. Okay, thank you very much and great job on the quarter team. Thank you. Thanks, Jerry.

While we expect I think for.

For the most part we expect to be drawing down from here, Chris as far as debt to EBITDA leverage goes as we move forward under the current under it.

Jerry McCaughey: Thank you. Once again, as a reminder, to ask a question, please call 1-1. Unknown Attendee, Jim Grant, Tavis Carlson, Lee Curran, Jeremy McCrean, Riley Frame, Travis, Again, that is star 11 on your telephone to ask a question.

Our current plans so.

We were targeting I think we said in that release, we said something around aiming for the one times.

Closer to 26 now with prices, but we're certainly headed in the right direction obviously.

Yes.

The price for the Repsol acquisition is up slightly from what we paid and so.

Operator: One moment for our next question. Our next question comes from Chris Thompson with CIBC. Your line is now open. Yeah, good morning.

That's that's included Q4 here at <unk> 99 for the acquisitions. So that's why we are up a little bit here post close.

Christopher Thompson: Thanks for taking my question here. Just to follow up on the debt discussion, at the time of the Repsol announcement, you announced leverage of one times debt to EBITDA by the end of 2025, and that was at better prices back then, but just wondering when you guys run it using more recent prices, where do you see yourselves getting to in terms of reaching that threshold? Well, we expect, I think we, for the most part, we expect to be going down from here, Chris, as far as depth of EBITDA leverage goes as we move forward under the current, our current plans. So, we were targeting, I think we said in that release, we said something around aiming for the one times, it'll probably be closer to $26,000 prices, but we're certainly heading that right in the right direction. Unknown Attendee.

On the leverage, but we expect that to go down and we expect that'll be down under one times sometime in late 'twenty early 'twenty six.

Okay and then just.

Yeah.

Just on <unk>.

With respect to <unk>.

<unk>.

Pricing in this environment.

Is there a gas price, where you would actually shut in production.

When someone wants to pay us to take their production I think that's a prudent move honestly if April both negative here this summer.

We've shown that in the past are afraid to shut in production if someone wants to pay me I can save those molecules and producing later, so certainly in that room in.

To that respect.

So that would be.

Prudent thing to do.

But our operating costs are so low for us, it's we're still making money prices. They are today for sure. So I think it has to be awfully low in that range too for us to shut in production is where it would only be a portion of course.

Okay.

Would that be specific to a certain asset in the portfolio or just broad based shut ins.

J.P. LaChanze: The price for the Rapsol acquisition is off slightly from what we paid, and so that's included in Q4 here, the $699 for the acquisition. So that's why we're up a little bit here post-close on the leverage, but we expect that to go down, and we expect that it'll be under one time at some time in late 2025 or early 2025. Okay, and then just. Just on with respect to, you know, pricing in this environment, is there a gas price where you would actually shut down production? When someone wants to pay us to take their production, I think that's a prudent move. Honestly, if ACO goes negative here this summer, we've shown that in the past, we're not afraid to shut down production. If someone wants to pay me, I can save those molecules and produce them later.

I would look at we would probably look at the wells that we could bring on the fastest as well like east and easily shut in because when this happens it's over a weekend generally with everybody goes home and we're on top of our game here. So we can quickly react to that situation were to arise.

We also have the infra services that we have which allows us to.

Which should blow out in that cases should be very valuable. This summer. So we have incremental interest service that we could also use but as far as shutting in production I think for us it would be.

We'll look at our list of the best wells to shut in to allow us to bring back office. Usually this is only a short term thing.

Got it okay.

And then in terms of actual.

Expansion deferrals or drilling deferrals.

And what pricing would you wanted to potentially delay even bringing some wells on production would you intend to build the DUC inventory through the summer and rather than bringing those wells on how are you thinking about that.

J.P. LaChanze: Certainly, in that respect, it would be... So, that would be. It's a prudent thing to do, but our operating costs are so low for us; we're still making money at the prices they are today, for sure. I think it has to be awfully low in that range for us to shut down production as it were. It would only be a portion, of course. Okay. Would that be specific to a certain asset in the portfolio or just a broad-based shut-in?

Yeah, we typically we're pretty fast that bringing wells on stream. So.

R R.

By Dr.

One of the best in the industry.

Our average sale, so, but we will look at it as it makes sense, where we won't be rushing out to bring wells on production.

Prices really bad at the time, but.

But generally speaking you will continue to bring production on.

J.P. LaChanze: We would probably look at the wells that we could bring on the fastest as well as the ones that are easily shut in because when this happens, it's generally over a weekend when everybody goes home, and we're on top of our game here, so we can quickly react to that situation if it were to arise. We also have the Empress service that we have which should blow out in that case and so should be very valuable this summer, so we have an incremental service that we could also use. But as far as sitting in production, I think for us, it would be, we'll look at the list of the best wells to shut in to allow us to bring back on because, usually, this is only a short-term thing. I got it.

We won't be holding on the docks.

Okay. Thank you.

Then just on the operating costs you had mentioned Q4 came in lower than.

You're potentially modeling.

And there is some cautious optimism there, but yes.

I'm just wondering.

At what point would you.

Would you think about updating the slide in your in your corporate presentation that that does look at those costs like how much how much data gathering do you think is needed before we are more confident in the direction that that's that's going.

Let's get a quarter or two under our belt here and prove it to you first.

J.P. LaChanze: Okay. And then, in terms of actual, expansion deferrals or drilling deferrals. What pricing would you want to potentially delay, even bringing some wells on production? Would you intend to build duck inventory through the summer rather than bring those wells on? How are you thinking about that? Yeah, we typically have, you know, we're pretty fast at bringing wells on screen. So, you know, our supply docking. One of the best in the industry, 45 days on average, I think, still.

Sure.

Okay.

Alright, and then I guess just on the.

Last thing on the water side.

And I noticed that certainly in the public data. It does confirm a lot of a lot of groundwater sourcing for the wells.

Can you maybe give us a bit more color just on.

Operationally how does this work like do you do.

Do you have to pull that water up put it in reservoirs move into pad sites or does it.

J.P. LaChanze: So, but we'll look at, you know, if it makes sense; we won't be rushing out to bring wells on production if the price is really bad at the time. But generally speaking, we will continue to bring production on, we won't be curtailing it, we won't be holding on to ducks as it were. Okay, thank you. Then just on operating costs, you mentioned Q4 came in lower than you're potentially modeling, and there's some cautious optimism there. But yeah, I'm just wondering at what point would you?

Does it just go from Noel directly to the Frac crew like just help us understand that a little bit better. Please.

Sure I'll get Lee to talk to that here Baker sure.

Thanks for the question.

Not all not all of.

All of our candidates are set up.

So.

We do we have.

Material infrastructure.

The rain.

Storage mechanisms flatlined. So at the end of the day, we're generally not limited by.

J.P. LaChanze: Would you think about updating the slide in your corporate presentation that looks at those costs, like how much? How much data gathering do you think is needed before we are more confident in the direction that that's going? Let's get a quarter or two under our belts here and prove it to you first.

The short term productivity.

The aquifer.

Yeah.

Pretty substantial network.

Surface storage containment those aquifers.

Our current program were usually three to four months out on our preplanning.

Lee Russell Curran: How's that? Sure. All right, and then I guess just on the last thing on the water side. And I noticed that, certainly, in the public data, it does confirm, you know, a lot of groundwater sourcing for the wells. Can you maybe give us a bit more color just on how, operationally, how does this work?

Most of that system.

And on weather impacts.

We will adjust sometimes on the fly whether we got better.

Our haulage.

So at the end of the day, when we looked at the numbers.

Lee Russell Curran: Do you have to pull that water out, put it in reservoirs, move it to pad sites, or does it just go from the well directly to the fracking crew? Just help us understand that a little bit better. Sure, I'll get Lee Curran to talk about that here.

Conference call with various.

Ministers yesterday.

Surface water per se is going to be in.

Dire shortage in the province, primarily in the southern part of the Robinson.

Matt.

Red River watersheds, so we're outside of those areas, which is beneficial.

Lee Russell Curran: Sure. Yeah, thanks for the question. Not all of our candidates are set up branded by the same iron, so it's a bit of a complex formula.

But.

Our focus is going to be surface water.

Lee Russell Curran: We do, we have a material infrastructure of bits and C-rings, storage mechanisms, and laid flatlines. So, at the end of the day, we're generally not limited by.. www.peytoexploration.com, Transcripts provided by Transcription Outsourcing, LLC. Uh, you know, in a current program, we're usually three to four months out on our pre-planning of most of that system, and whether impacts will... We'll adjust sometimes on the fly whether we've got to pump it or haul it. So at the end of the day, when we looked at the numbers, you know, and we had a conference call with Transcribed by https://otter.ai, Water is in dire shortage in the province, primarily in the southern part of the province and the Old Man Bow River and regular river watersheds. So we're outside of those areas, which is beneficial. The focus is going to be surface water, so those that are pulling large volumes from lakes and rivers. They're going to have to get their ducks in a row. We utilized 0.3% of our water last year from surface water sources.

Those that are on large volumes from lakes and rivers.

They're going to have to get the ducks in a row.

We utilized 3%.

Of our water last year from surface water source those purchased a couple of things.

Water out of existing programs.

Our 99 point.

7% of our.

Water resources, either by our recycling initiatives mature market and.

Sure.

Water wells groundwater aquifers.

Those are completely immune per se.

Further down the line.

Looking at other ways to further enhance.

Protection.

Okay.

Travel situation gets even more severe.

When you say that they're they're not immune.

Are you referring to not immune to like government issued curtailments or just not immune to shortage in I guess.

Do you have a sense of.

How how many years out.

Lee Russell Curran: Those were just a couple of... Our, you know, 99.7% of our water was sourced either by our recycling initiatives, which are marketed, and, uh, and, uh, water wells, groundwater aquifers, and you know, although those aren't completely immune per se. Further down the line, and we're looking at other ways to further, www.peytoexploration.com Tran FEMA.gov When you say that they're not immune, are you referring to not immune to government-imposed curtailments or just not immune to shortages? And, I guess, do you have a sense of how many years out would you feel an impact if conditions didn't improve? Oh, the immunity would all be on a regulatory basis, the aquifer productivity, because most of them are, terminology is not necessarily consistent, but they're medium to deep aquifers.

Would you feel an impact if conditions didn't improve.

Yes.

Immunity, we'd all be on a regulatory basis, the aquifer productivity because most of them are.

The terminology is not necessarily consistent but they are medium to the progress we have won shallow water producer but.

Lions share of our water comes from E Commerce.

Re charges.

Decades.

So it would be a regulatory constraint, but again.

The government of Alberta.

Yes.

Pretty sophisticated on their understanding of the water resources products.

So I would say our level of immunity is very high.

It would just become a situation where maybe there is.

Stream fire situations, where they would.

Once.

<unk> industrial sources of water or things like that.

Lee Russell Curran: We have one shallow water producer, but the lion's share of our water, Unknown Attendee, Jim Grant, Peyto Exploration & Development Corp., is decades out. So it would be a regulatory constraint. But again, the government of Alberta is pretty sophisticated in its understanding of the water resource in the province. So, I would say our level of immunity is very high; it would just become a situation where maybe there was. You know, extreme fire situations where they would, you know, want, you know, various industrial sources of water or things like that, very much an outlier. And, of course, our blowback to our recycling initiatives. I would say bulletproof, you know, that's a basic piece of architecture.

But very very much an outlier.

And of course, our flowback our recycling initiatives.

I would say.

Yes.

Yes.

Piece of our business.

Okay.

Great. Thanks, sorry, JP go ahead, well thank you.

Okay.

Sure.

Thank you.

One moment for our next question.

Yes.

Okay.

Our next question is a follow up from Gerry Mccaughey, an investor Your line is now open.

Hi, J P. This is Ed.

Because of some of the content of the Q&A.

You had touched on.

Yes, <unk> were to go negative.

That Mike.

Have a shut in some production.

Christopher Thompson: Okay. Thanks. Great. Thanks. Sorry, JP.

And.

You then did mentioned Empress.

J.P. LaChanze: Go ahead. Thank you. One moment for our next question. Our next question is a follow-up from Jerry McCaughey, an investor. Your line is now open. Hi, JP. This is because of some of the content of the Q&A you had touched on. If AECO were to go negative, that might have us shut down some production. And you then did mention Empress and all that.

All of that.

So I think that's part of the answer but to my question, but I just would like you to elaborate a little bit. So I'll give you the question.

I think that there has been considerable effort put in.

Over the last few years.

To be prepared for particularly.

Jerry McCaughey: So, I think that's part of the answer to my question, but I just would like you to elaborate a little bit, so I'll give you the question. I think that there's been considerable effort put in over the last few years to be prepared for, particularly... the volatility in pricing in ACO. And I think that we actually have a bit of a drag cost which we offset, but in order to be prepared, in other words, built into our existing run rate is an optionality that costs money to maintain. So are we not?

The volatility in pricing in eco.

And.

I think that we.

Actually have a bit of a drag cost, which we offset but.

In order to be prepared in other words built into our existing run rate is a certain.

Optionality that costs money to maintain.

So.

Or not.

Sure.

Extremely.

J.P. LaChanze: Extremely prepared for eco volatility or weakness, specifically if it went negative or anything like that. So I'll leave the question there because I think it's not well phrased, but I think you know what I'm asking. Yeah, so we obviously don't have exposure to AECL, essentially, and we have, like you say, taken great care not to be exposed to AECO; all of our gas is sold elsewhere. So to the extent that AECO goes negative, it's just an opportunity, right, to shut in and take advantage of and save that gas. But, you know, for the future, that's the only reason we would do it. And it would be very, very short term, I'd anticipate. My comments around that, and we've done that in the past, right? We've shut in over the weekends. So, the transportation costs we incur include a little bit of the extra Empress service that we have, which is about 19 cents a GJ.

Prepared for eco volatility or weakness specifically, if it went negative or anything like that so that I'll leave the question there because I think it is.

Well phrased, but I think you know what I'm asking.

Yes, so we obviously don't have exposure to April essentially and.

We have like you said, you're taking great care not to be exposed to eagle are.

All of our gas is sold elsewhere, so to the extent that a Google is negative it's just an opportunity right.

But in and take advantage of concede that gas but.

For future future. That's the only reason we would do it and it would be great very short term I'd anticipate so my comments around that and we've done that in the past right. We shut in over a weekend.

The transportation cost we incur include a little bit of Empress extra Empress service that we offer that are about 19 GJ caused us to have that service. So it's fairly cheap insurance.

J.P. LaChanze: It costs us to have that service, so it's fairly cheap insurance to get us out of ACO should we have anything that's not diversified to another market. So, if prices at ACO were to drop significantly below, or even go negative, we certainly have the opportunity then to either monetize the value of that, or shut it down, or do whatever we want with it. We are very flexible here, so we will do that. So, I think, I think, you know, the point of this is that we really don't have any exposure to ACO. But we might want to react to it and take advantage of it if it presents itself, right?

I guess to get us out of automaker should you be have anything thats not diversify come to the market. So.

Prices are equal were to drop significantly below.

Low or even go negative we certainly have the opportunity to into to either monetize the value of that shut in or do whatever we want with it we are very flexible here. So we will do that so I think I think the point of this is that we don't have really any exposure to <unk> in a sense.

Wanted to ask you would it be.

Take advantage of it if it presents itself right.

Yes, thank you very much okay. Thanks Gerry.

Thank you.

I am showing no further questions at this time I would now like to turn it back to J P. <unk>.

Okay, well, thanks folks for attending the conference call, we will get back to you.

Jerry McCaughey: Yeah, thank you very much. Okay, thanks Jerry. Thank you. I'm showing no further questions at this time. I would now like to turn it back to J.P. LeChant. Okay, well, thanks, folks, for attending the conference call. We'll get back to you next quarter.

Next quarter. Thank you very much.

Thank you. This concludes today's conference call. Thank you for participating you may now disconnect.

Yes.

Okay.

Okay.

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Okay.

Yeah.

Okay.

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J.P. LaChanze: Thank you very much. Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect. Transcribed by https://otter.ai. Thanks for watching.

Yes.

So.

And.

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