Peyto Exploration & Development Corp.

Okay. Well, thanks, Jonathan, and good morning, ladies and gentlemen.

Thanks to everyone for tuning in to Peyto's Fourth Quarter and Year-end 2020 Conference Call today. Before I get started with remarks about the quarter, 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.

Yes. Darren, congratulations to you on a very good conclusion to a difficult year and a great start to the new year.

My question relates to your ongoing hedging program. And I think it was last quarterly report, you mentioned how much the old hedges had cost versus ongoing pricing.

And that was extremely helpful because it gives an idea of future economics because the picture as we roll forward improves, not just because of the current pricing, but also because of the rolling over of hedges that were made during more difficult periods. So as we look forward, I had noticed that you had put on some basis hedges for next Q1 of '22 that were a very small hedge went on 5,000 at $0.63 versus your existing ones on Henry Hub, the basis trades that were at $1.41, and that's extremely favorable.

If you could just comment on the forward hedging and the maturation of the older crop that were more difficult, I would appreciate that.

Yes. You bet, Jerry.

That's an acute observation of how the market has definitely changed over the last few years. The high-cost basis deals that we had put in place were put in place mostly in 2018.

And at that time, obviously, the AECO market was extremely disconnected from the rest of North America. Lack of access to storage had created some incredibly weak summer prices.

And so we were looking at a forward curve there of about $1.50 AECO while NYMEX was at about $3. So we didn't have a lot of confidence that the AECO market was ever going to get fixed.

And so we started to diversify away from it, put basis deals in place to get us down to the U.S. market at many of the different hubs, mostly NYMEX because that was obviously the most liquid one.

And those were pretty high cost. Like you say, we had some $1.35 basis for the winter, some $1.40 basis prices for the summer.

And then in sort of later in what was at the fall of '19, I guess it was, we saw the temporary service protocol approved by the CER and the AECO market quickly reconnected with the rest of North America. And so for most of 2020, obviously, we saw a basis that was more typical.

It slowly tightened up, and we saw prices anywhere from sort of, I would say, $0.75 to $1 per basis in there, which was quite a bit better.

I also echo the comments about congratulations for doing a great job last year. I wouldn't mind if you could spend a little more time, it's really a follow-on to the first question.

With respect to these market diversification costs, you - really, with respect to the timing of the roll-off of them, like - I know in the third quarter, I think you guys said they'd be significantly reduced over time. I think on the call, with respect to the third quarter, I think you referred to the coming two quarters, if I'm not mistaken, in the outlook today, it describes the diminishing gas market costs with respect to the '21 outlook.

But in the paragraph under marketing, it talks about these things decreasing over the next two years. I'm really more - I'm interested in when we'll get back to some kind of normalcy?

And the timing of it, is it two quarters? Is it two years?

Is it - are we going to see most of it this year? Just a little more color on maybe even what they - on just how we'll get back to normal, if that makes any sense?

No. It totally does, Terry, and I appreciate.

It's obviously much more difficult for investors to look through now because we've got so much diversity in our marketing. We had to obviously put that in place.

We're not just as simple as selling gas at AECO anymore. But you're right, the - it's a bit tricky to try and predict because, of course, the AECO prices trade somewhat independently of NYMEX.

And that's that basis differential between those 2 markets that sort of floats around. And so at any point in time, when we talk about what's going to be the market diversification cost for that next quarter, it's based on the future strip for both of those commodities as we're looking forward.

And so it moves around a little bit. But I think we're obviously seeing some very strong pricing in Q1.

And I think our market diversification cost in Q1 won't be as high as they've historically been. They will look pretty good.

And then as we enter into summer, there's some softer prices in both NYMEX and AECO. And we'll see that market diversification cost go up a little bit as we see some softening in the summer NYMEX price.

Unless, of course, we see strength in the NYMEX relative to weaker AECO prices, which we could possibly see because the TSP was not extended into the summer of '21 for the Alberta market. So we could see some weakness in volatility there.

And storage numbers in the U.S. look like they're headed pretty low.

And so if the refill isn't as aggressive as you might predict, then we could see some strength in the NYMEX, in which case, our diversification costs will fall for the next summer, a couple quarters. Right now, we're forecasting them to be the higher parts of the year.

And then really, with Q4 of '21, that's when everything starts to fall away, these old basis deals, more and more of them start to fall away, we get a much tighter price. And then entering into 2020, our prediction for the year in '22 is that we would get very close to the current AECO realized price or the current delta really between NYMEX and AECO.

So effectively market diversification costs in '22 we're forecasting right now would be very little, if anything, at all. And then actually into 2023, we would actually start to benefit from a lot of the diversification, getting actual prices realized that are superior to that of what the AECO forward strip shows.

So it's all this sort of layering and smoothing approach, obviously, to the diversification and then hedging on top of that. But realized prices look like they'll be getting back to normal, as you say, by sort of the fourth quarter of '21 and into all of '22.

And then we look to do a better job than just the local AECO market beyond '22 into '23 and after that. So hopefully, that helps a little bit.

It's hard to pin it down, of course, because it's moving every day with the forward curves.

So we're coming up here on NGL recontracting season. How should we think about NGL differentials and realizations in 2021 versus last year?

Yes. From what we're seeing in the market, there is still strong storage of propane and butane, particularly, across North America, high levels of storage relative to the 5-year average as you've probably seen as well.

They're coming down, of course. I mean the; cold winter helped pull those down a bit.

And we'll see what other demands there are, particularly export opportunities. Propane was being exported aggressively here through Q1.

Obviously, the cold weather in Europe and other places, put big demand on any hydrocarbons really that could be moved to those cold winter weather events that were happening. So we've seen particularly strong propane prices on the spot, and in the short term, those weaken as we obviously get into the summer months, but still look not too bad.

So propane prices actually have reversed quite a bit. They weren't all that great in 2020, and we've definitely seen them strengthen a lot lately.

Butane prices, on the other hand, obviously, butane is used principally in Edmonton as a feedstock for the refineries to make gasoline. Obviously, gasoline demands are not great because of COVID, not a lot of driving, not a lot of flying.

So butane stocks remain relatively high. Differential - butane is typically traded on a differential to WTI or light oil price, for instance.

And I would say under normal situations, it should trade pretty close to 50% of light oil. Right now, I think indications for the recontracting year are butane somewhere around the sort of high 30s to 40%, maybe.

I think last year, our average term deals were somewhere in the 46% range. So we might be slightly under that as renewals for this year.

But those 2 are changing quite dramatically. The storage levels of butane are coming down really fast as well.

So if I had to guess, I would say that the blend of propane and butane pricing realizations might be similar to 2020, what we see in 2021, maybe a little bit weaker butane and a little bit stronger propane. So all in all, maybe we see something similar to slightly better, but not a ton better, even though we've seen oil prices obviously recover a lot.

Those two products are still sort of - we're still working through a bit of a storage glut on them as well. So maybe throughout the year, we'll see spot prices improve.

And then by 2022, we might actually see some really exciting looking differentials and prices for those products.

I was hoping you could tell us roughly what percentage of your production is exposed to each sales side?

Percentage of production, I'm going to have to take a guess, Sean. We've got that one slide on our website, and in the presentation, we updated all the time, of course.

It depends really on the season that we're looking at. But the AECO exposure is probably somewhere around maybe a little under 1/3.

And then the other 2/3 is really distributed across mostly NYMEX influenced prices. We've got a fair chunk at the Henry Hub.

And then we've got probably about, again, another 2/3 at the Henry Hub. And then we've got the remaining 1/3, I think, equally split amongst smaller hubs like Malin, Ventura, Emerson, until we get into sort of the fall of '21 and then it redistributes a little bit.

We've got far less really exposed to both AECO and NYMEX and a lot more becoming exposed to sort of the dawn area. We've got a lot of Emerson service that kicks in, in November of '21.

It's good 1-year renewable, lower-priced service that gives us a superior price. Emerson is not really a hub that you can trade a lot of gas at, but it does get us halfway down the mainline towards Dawn and then it branches out from Emerson goes down the Great Lake system, we get more into the Chicago market with that way or we can go over-the-top of the Great Lakes and into Dawn and to sort of Eastern Canadian market and beyond that into the Northeastern U.S.

market. So we think that's going to be a strong market going forward.

So it's really changing and evolving. It's - I mean, those percentages will be similar for, I guess, really through the summer of '21, but then as of the fall of '21, they start to change a little bit, and we get a little more exposure to sort of Eastern Canada and Northeastern U.S.

and a little less exposure to NYMEX. But we're cautious about the AECO market.

I know it's strong right now, but we're still careful in terms of our exposure there. We're not overly confident that the storage system is working effectively on the NGTL, sort of the western Canadian gathering system doesn't seem to have full access to storage yet in a way that makes us really comfortable with it.

So we're cautious with respect to that going forward for the next little while anyway.

Yes. First, let me thank you and your team for everything you do for the shareholders.

I feel fortunate to have you guys managing some of my money. My 2 questions are related.

First is the bank borrowing and the penalty interest rate, when do you anticipate that falling away? And the related question is, how are you thinking about the dividends?

And when might you anticipate an increase in the dividends?

Sure. Good questions, Nathan.

Maybe actually, I shall just pass over to Kathy Turgeon, our CFO, to talk a little bit about the banking situation.

Okay. Yes, thanks for the question.

As you could see in our Q3, Q4, our interest rates are significantly higher than historically they have been, and that is due to our debt-to-EBITDA stamping fee costs. So as we see those coming down, obviously, we're going to normalize back.

And we're seeing that in Q1. Definitely by Q2 of 2021 will be back well below 4x, which will bring us down in the actual costs on our interest.

It takes a little while for that to flow through on the way stamping fees work. But by the end of 2021, we should see a more normalized interest cost that would be on a per Mcfe basis, more in the mid-20s as opposed to $0.38 per Mcfe that we're seeing right now.

And from an interest rate point of view, we should be seeing like 100 to 150 bps less. We also have our bank deal coming up for renewal.

Our term date is October 2022. So we'll be looking to renew that this summer.

And obviously, pricing will be part of our discussion.

And then, Nathan, your second question with respect to dividends. Obviously, we're looking closely at our cash uses, cash inflows, cash outflows, wanting to ensure our balance sheet stays front of mind as well.

We're looking at - right now, we're forecasting quite a bit of free cash flow over and above our capital requirements to get us really back up to that 100,000 a day level. We think we can exit the year somewhere between 95,000 to 100,000 barrels a day, close to that 100,000 level, if we get the efficiencies we're looking for.

That's with about $350 million or a little less of total capital for the year. That, like I say, is far less than the cash flow we're forecasting with commodity prices we're looking at today.

So that gives us a bunch of free cash flow to consider what are we going to do with that. I think, obviously, initially, we just put that on the bank line.

But also looking at how the earnings are evolving and earnings are strengthening. Our forecast of earnings for the year is coming up nicely.

We're getting back to the type of profit margins that we used to enjoy, which we want to feel confident about. And so I think as we get into the back half of this year, obviously, the Board will start to think about dividends again more seriously.

And weigh that against the cost of capital for the company and what the 2022 year starts to look like. I think it will really be sort of fourth quarter '21, 2022 decision.

And there's still a lot of backwardation in the commodity tape right now, both oil and gas prices fall away pretty hard as we look out into '22 and '23. And so that - we expect that to change.

We expect the back end of that curve to come up. And I think as it does, obviously, we'll gain a lot more confidence in the total amount of free cash flow that we're going to be throwing off in '22 and '23.

I think we want to probably have both a combined use for that free cash flow, both in terms of balance sheet strengthening, reducing our debt as well as dividend rewards to shareholders. Like I say, I think it's really a sort of the back half '21 into '22 type of discussion at the Board level, and we'll see what the future looks like when we get to that point.

I think we want to see really the solidification of commodity price strip into the '22 and '23 years. Right now, it's - like I say, it looks a bit odd to us to see such severe backwardation in the forward curve.

And so we'd want to see some of that coming out of there, so we can lock that away and secure the pricing that we need to generate a lot of that free cash flow.

Okay. Well, that was good.

Lots of good inbound questions. I think we obviously have some big plans for 2021.

It's going to be a busy year. We did have some inbound e-mail then over the last week or so, questions about this new acquisition that we've recently picked up.

And so maybe if I can take a moment and just - I wanted to ask Todd Burdick, our VP Production, a little bit about the integration of those assets. Obviously, we picked those up just after the New Year here, closed those deals, and we're still integrating a lot of those.

Sometimes acquisition integration is a difficult process if the acquisitions are large. But I don't think this one was - or is expected to be overly difficult.

Todd, maybe if you could elaborate a little bit on how that's going and maybe some of the upside that we're seeing in that asset?

Yes, sure. So things have gone really smoothly so far.

We kind of took over operatorship at the beginning of February. I got to give kudos to Scott and his team for sort of facilitating a transition.

And along with the previous operator as well, they've made it a lot easier for us and so that we can make a transition really quickly. But last week, we finished the integration of the SCADA system for both plant and wells into Peyto system.

So now we have real-time visibility on all of the wells and all of the plants, which is nice to see, so we can start working on optimization. So we've been looking at well optimization opportunities.

They've been evaluated. In this week, we've been busy in the field, implementing changes that should result in seeing more gas at the plant gate.

So we're excited about that. We'll also be reactivating and redirecting some wells that had flowed to third parties, but were shut-in due to low gas prices and high fees.

So that redirection, which is really going to be done at very little cost will bring those wells into the Cecilia gathering system as well. We're just waiting on the license transfer piece with the AER before we can do some of that work.

As far as pipeline infrastructure, we've evaluated any constraints. And we're making changes to operating strategies.

Those will be implemented where applicable. Essentially, without going into too much detail, the result will be more consistent flow in the gas gathering system unless liquid hold up so that the wells will produce and perform better.

That was one of the things we spent a lot of time on looking at. We've already - we've had one 6-inch connection to the Oldman system in place for years with the original operator and developer of the assets.

The - a portion of that pipe had been decommissioned. So we're going to recommission that line.

Again, once the license transfer happens, we'll be able to do that. So then we'll have a connection with part of the Cecilia infrastructure into the Oldman and the Oldman North infrastructure.

And then as well, we've been looking at little sort of short tie-in opportunities. It won't cost much capital.

But will give us some flexibility to even get gas tied in and into the Wildhay area. So we'll move on those sort of adds the development dictates, I think, for most part, but we've identified a lot of opportunities.

And that will give us, obviously, flexibility to swing gas around multiple plants, like we have elsewhere in the greater Sundance area. And then finally, I think we've been - we're going to leverage our relationships with some of our key vendors out there.

So we'll get those vendors working in the Cecilia area and with the long-standing relationships and pricing that we see with them will not only get reliable service, but we'll also see an impact on an operating cost reduction basis. So a lot of work has been happening, and we're excited to keep pushing this forward.

No. That sounds really good.

Thanks, Todd. Dave, I know you were eager to get your hands on these lands.

There were some interesting opportunities there. Without telling our competitors too much, did you want to elaborate on some of the things we're excited about there?

Sure. Darren, maybe just a bit.

The opportunities we're most excited about are in the Spirit River and the Dunvegan. We've got 3D Seismic over pretty much all of the new lands.

And we have 8 Notikewin and 2 Wilrich locations already teed up to drill later this year. We're especially keen on Notikewins because they've been a pretty big part of this year's success, and we see them as helping us continue that momentum into 2021 and 2022.

In 2023, we'll follow those wells up with more Notikewins plus some flares. And we're keen to target the Dunvegan, which is present over the northern part of the lands.

There's also a good amount of Cardium opportunity, which we're very familiar with. But ultimately, we see the potential for over 100 locations on the 54 sections.

And I'd just like to complement the BD team. They worked very hard to make this happen, and we're really keen to start drilling.

Sounds really exciting. Scott's, not here.

JP, I don't know if you want to stand in for him. But obviously, the industry is talking a lot these days about M&A.

We haven't typically been a company that does a lot of M&A. We tend to do a lot of organic development on our own, but we've had a few little complementary deals that we've tucked-in here there and maybe smaller stuff.

What's the strategy going forward? Is it big stuff or small stuff?

What are you thinking?

I think like you said, we've always had great success with the sort of bread-and-butter kind of tuck-in acquisitions around our assets. We do that, be it farm-ins or poolings or swaps or whatever the case may be, our land department and the BD Group are both busy doing that.

So it's tough for us. When we add production at 9,000 a flowing BOE.

It's hard for us to sort of look at major acquisitions in some sense because the value expectation on the other side is usually quite high as well, and for us to get that, we want to make a profit here. So I mean, there's going to be these opportunities like we just discovered.

And especially when they come with infrastructure, we'll continue to look at these. There are other operators out there and there are other lands out there similar to this, that we'll continue to pursue, that is the strategy.

I mean, I think with our cost structure and acumen in that regard, we will certainly have more of these opportunities available to us. And that's a real strategy to continue.

Okay. Great.

I think that's probably it for the quarter and for the year for us. We're obviously excited about '21.

And already, we've seen some interesting developments with commodity prices. And obviously, we're continuing to perform here.

We've got an active year plans, a bigger capital program, quite a bit bigger than 2020. So we're going to be busy.

But that's not all that we can do. Obviously, we're looking to do even more than that.

So we're going to keep working on some of those future opportunities, and we'll report back to you guys on how that's coming. But obviously, the strategy at Peyto has never changed.

We're all about generating the maximum return we can on every dollar that we can put to work for shareholders. So we're going to continue that vein, and keep pushing to lower costs and improve profitability as we go.

And so we'll be back to you reporting on the first quarter, how that went and how we're headed into breakup here in May, I guess. So thanks for listening in, and we'll talk to you then.