Peyto Exploration & Development Corp.

Well, thank you, Mary. Sorry for the little technical mix up here this morning, that we've got a delayed start by a minute or 2.

But good morning, ladies and gentlemen, and thanks to everybody for tuning in to Peyto's First Quarter 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.

I'm just wondering, given your comments on storage access and improving fundamentals in North America, if you tempered your expectations at end of the world -- volatility in August with AECO?

Thanks for the question, Dale. It's 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 and work that's planned for August on the Nova system.

We still anticipate that, that's going to have a fairly significant impact in Alberta. We're hoping it's short-lived.

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 and next winter, it really -- there's not a lot of financial incentive to actually put gas into storage, and yet there is 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 they're trying to get ahead of it a little bit with the injections. Even as it is, we're projecting that AECO storage or the AECO-connected storage, so that's the stuff off the Nova system, is only going to get to about 70% to 75% full.

We were a lot fuller last winter going into that cold winter last year, a good thing because we took about 225 Bcf out. We're only anticipating that we're probably going to refill something a little over 100 or so.

So it still looks to us like a bit of a delicate situation for natural gas storage in Alberta. And we still think that August is going to be a difficult time, particularly for Alberta prices, which is why we diversified away from the AECO market for this summer.

Just a follow-up question on your extended lateral wells. I'm just curious to know how much that -- how much of that is expected to improve your profitability going forward in terms of your payout, maybe the NPV per well?

And how much you've built that 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 that test the risk out, I think.

Maybe JP, you could talk a little bit about the economics of those, and how that changes things for us?

Yes. Sure, Darren.

We drilled about 6 wells last year, where we tested longer reach horizontals of 6.5 miles. And so we drill them about 70% longer, and we probably put about twice as much sand in these laterals.

So we increased the intensity as well. And we did that for a cost per meter that was about 20% lower.

So all a very good program. The rate of return on those -- 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 just under the 2-year mark.

So -- and again, we probably would have seen payouts a lot longer than that. I don't have an NPV number off the top of my head.

But obviously, the economics for these are a lot better. And we have factored in this into our 2021 program, which we have about 20 wells planned for this year to follow-up on that program in different species, in different areas.

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

Jeremy, these extended reach though are -- they are different -- I would characterize them as a little bit different risk profile. But Lee, maybe you can comment a little bit about the drilling risks, whether there are any more dangerous drilling longer laterals than what we traditionally do.

Sure. I guess backing up, I don't know if it's necessarily a truly new design in any way.

We've always stuck with our standard open-all-ball-drop system that we've been doing for the last decade. And many of these targets still carry intermediate casing design in their actual well design.

So it's just really how they factored into our program as a percentage of our activity. We drilled our first extended reach horizontal back in 2014 being our 8028, 5422 Wilrich horizontal.

What's really changed is back then, we were kind of fighting our lift as we drilled it. That well was TD-ed at 6,000 meters with a 3,000-meter lateral.

We were nervous deploying a 21-stage system into that. And the drill cost was just over $3.3 million, I believe.

And that was with a flawless execution. So that wasn't flagged with wellbore challenges.

Our completion cost on that well was $2.2 million. So D&C totaled just over $5.5 million.

It was hard to -- the results didn't really professed to us at that time that, that was the way we should move forward with these wells.

Thanks, Lee. Jeremy, hopefully, that color gives you 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 there's a lot of factors to consider, and risk being one of the primary ones, but it comes in all different forms and shapes and all different steps of the operation. So -- anyway, hopefully, that gives you some color on the new design.

No. No, it does.

And just going back to that payout that you were just talking about at that 2 years. What commodity price assumptions that you using, especially on the NGLs.

Just I know NGLs are starting to move up here a little bit more now. And then just -- it's just -- are you taking advantage of those NGL pricings?

Just maybe a quick comment on that as well.

Yes. Typically, we write all of our new well economics at strip, accounting for sort of where gas prices are headed.

Of course, they're quite severely backwardated at AECO right now. So it's not a great gas price forecast to run gas wells against.

But so be it. It is what it is, and we'll have to make it work.

You're 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 back up to more typical levels, closer to 40% to 50% of light oil price.

2020 butane prices were terrible, obviously, there -- because in that refinery shutdown, that gave us a lot of butane. And it took a while to wear that off.

But I think last year, that came away. Butane prices strengthened quite a bit.

So I think our propane and butane prices in Q1 that we realized that were about $30 a barrel, are more typical. And yes, that is a big driver.

It's helpful to -- we've got a deep cut, only one -- at one of our plants. But obviously, it strips a lot more butane and propane out as well.

So if we can bring these extended reach horizontal wells with more reserves, even if it's leaner reserves into the deep cut, then we're getting more liquids out of those wells, too. And so that helps the economics.

But really, we're not trying to, I don't think, only make economic return when the prices are really good. We obviously have to survive the volatility in the price.

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

I note in your release reference to reducing debt. So I did go back and look at your annual reports and find that your long-term debt has basically been flat.

I went back to 2015. So I wonder if you could comment on your statement in your release about dealing with debt.

Thanks, Trevor. 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, that 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 or 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 pay down 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. And next year, we pay it down in a much more material way.

Really, though, when you look back over Peyto's 22-year history, our debt-to-EBITDA ratio or debt to cash flow ratio has typically averaged about 2x, which, for some people, they might think that's a bit heavy. But we have used debt very effectively, and it's relatively low cost debt.

Obviously, interest rates are relatively low still. And you have to put that into perspective.

Peyto has 9 years of producing reserve life, which is extremely long, one of the longest producing reserve life assets in the industry. And so when we think about 2 years of debt on that 9 years of reserves, it doesn't seem overly levered.

Of course, if you had a 3-year reserve life and you had 2 years of debt, you would think, wow, I'm 2/3 levered. And so that is pretty heavy leverage.

And so when you think about our debt relative to our cash flows and 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 7 to 8 years.

And that's what's really supporting our ability to carry debt against it and to use some debt effectively. But as you would probably point out, we've just come through a period here where carrying debt is at risk.

It looks scary to a lot of investors. And for a period of time there where commodity prices were really low, it looked even scary to us.

But thankfully, we're through that. And I think by the end of this year, we'll be at a sort of debt to cash flow level that is very historic for us and very comfortable for us.

Okay. Well, thanks, Mary.

We did get a couple of questions come in overnight, e-mailed in from shareholders. So I did want to approach a couple of topics here.

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, Darren. So at the end of 2020, we had a leverage or debt to cash EBITDA ratio of 4.3x.

In Q1, that came down to 3.36x. And as we decrease our leverage ratios, that actually affects our stamping fees that we pay, which is a significant component of our interest cost.

So when we see that coming down under 4, under 3.5, then we have significant changes in our rates. So our interest rate in Q1 was 6.2% based on the historical 4.3x EBITDA.

So going forward in the next few quarters, we expect that our interest rates will go down more towards the 4.5x -- 4.5% rate, which would save us approximately $2 million, $2.5 million a quarter. So we're expecting to see our interest costs in Q4 to be more in the $0.30 per Mcf range or about $13 million, which is a significant decrease from the $18 million in Q1.

Great. I like to hear that.

Thanks, Kath. One of the other questions that came in overnight was about ESG, 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 that's reducing methane emissions.

Todd, are there other things that we're looking at Peyto, long-term things or short-term things that also help reduce our emissions?

Yes. Absolutely, Darren.

We had set a target back in 2016 of a 50% reduction in our emissions intensity and through Q1 here with our retrofit program. We're pretty much there.

We 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 industry and then implementing a lot of meaningful initiatives that have saved methane 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. All these initiatives that we've implemented are -- go above and beyond the Directive 60 Compliance requirements.

So we're doing better than what the industry would ask of us. So this year, we'll continue with our high bleed to low-bleed controller retrofit program.

We expect that program -- that project to be completed in June. We'll also be removing controllers on some low rate wells.

So essentially turning them from low vent to a no-vent-type well. We'll continue to install collection devices that capture vented methane from legacy pneumatic chemical pumps and use it as fuel gas and well site heaters.

We'll 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, 1 pump can do what 4 pumps used to do, that's injecting different chemicals at different rates with less power consumption than our first generation of electric pumps. As you mentioned, this summer, we'll start receiving our first shipment of fully electric separator skids.

So we've actually been trialing a design and refining that design in the field since 2019. So we've gone through 2 winter seasons with a fully electric skid.

And we now have an extremely reliable design. And as I mentioned, with a really low power consumption.

So with a couple of extra solar panels and a couple of extra batteries, we haven't had any issues through 2 winters. The team has also set to trial an in-stream pipeline power generator at 2 separate pads this year.

And that provides all the power needs for each pad as well as recharging the backup batteries. And if successful, it could replace solar panels in some applications.

So over the past 5 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 at gas plants. That includes compressor waste heat recovery, where the captured waste heat can be used to supplement utility heat duty in a plant and reduce 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 a company to trial a geothermal application that has a 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 like we've seen with well sites, the technology is getting more efficient and the costs are going down. So we anticipate being able to implement some of these applications in the future.

Also, there's been a lot of discussion recently about -- around carbon capture and storage and blue hydrogen. So that's something that we continue to monitor, and we're excited to see what may come of those 2 emerging technologies.

Great. That sounds all really good.

The last question that we saw was actually with respect to acquisitions. We're not typically a big acquirer at Peyto.

We've built almost everything we have today from scratch. But we did a couple of acquisitions in the first quarter.

Those were the first that we've done in a long time, of size. So maybe I can turn to Derick and ask him what else are we seeing coming down the pipe, Derick?

Are we looking at some more sizable acquisitions, is the land sale opportunities starting to emerge now that Crown land sales are back on the table or...

Yes. Thanks, Darren.

We're constantly endeavoring to grow our land base with tuck-in acquisitions, whether they be purchasing assets, farming in with drilling commitments, we're entering into swaps. Generally, I believe activity often creates opportunity.

So with us being active, helps us both be proactive and reactive as required. Also -- I also believe being quick and flexible within the different internal departments helps in this regard.

Our low-cost capital structure, technical know-how and abundant amount of infrastructure can be used as a sort of currency at times to allow us to withstand down promos on farmings and purchases, 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 tuck-in acquisitions like Cecilia, for example.

In terms of Crown sales, it's definitely a lot more active than last year in Q1 2021. There's about $11 million in bonuses for an average of $195.5, which is obviously substantially higher than 2020 when there was about 7.5 months of no Crown sales.

So all in all, as you mentioned, we're not -- we're constantly looking at further acquisition targets, and we mark them as they come up or as we are able to generate them.

Okay. Great.

Well, I think that's all the questions that we saw from people and shareholders. And so thanks everybody, for tuning in.

We'll obviously be back to you mid-summer with Q2 results. We're looking forward actually to another busy year of drilling here at Peyto.

And economics are starting to look stronger and stronger. Prices are looking better.

So cash flows are getting stronger. Our balance sheet is getting a lot better.

So things are definitely looking up. We're excited about the balance of this year.

And we're excited about is probably most people are to put COVID behind us and finally get to maybe have dinner together at some point in the hopefully not-too-distant future. So anyway, thanks for tuning in.

Watch the website. JP and I will get a presentation, an 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 presentation up. And hopefully, that can shed some more light on where Peyto is going, and how we're doing.

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