Peyto Exploration & Development Corp.

Well, good morning. Thank you, Sydney.

And thanks for everyone for tuning into Peyto's third quarter 2020 results conference call. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in companies news release issued yesterday.

In the room with me today is the entire Peyto management team. We're maintaining our social distancing here, but we've got everybody on the call.

So Kathy Turgeon, our Chief Financial Officer is here; JP Lachance, our Chief Operating Officer; Scott Robinson, our VP of Business Development. We've got Dave Thomas, our VP Exploration; Lee Curran, our VP Drilling and Completions; Tim Louie, our VP of Land and; Todd Burdick, our VP of Production.

I was curious, just with the improvement in gas prices, how much you are looking to shift your capital budget for next year to do more dryer gas wells like your willow ridge and that versus what you've historically done in the last couple of years shifting to Cardium? And if there's any other dryer gas plays that you're looking at here?

Jeremy, I think this year's program is a fairly balanced one in terms of species mix, both Cardium and other Spirit River zones that are in there. We're continuing to work those same zones that we always have, really from the Cretaceous all the way up, the blue sky, the will rich, the flares, they're not acute, the odd, other zone in there, as well as the Cardium.

So it's a fairly balanced mix, which is kind of nice and it's spread out geographically across our asset base as well, which maybe isn't quite as easy for Lee and the drilling group in terms of taking advantage of pad drilling and less moving of the drilling rigs, but it does allow us to diversify the program across different geographic areas that are not interdependent, and then across zones that aren't interdependent as well. So we can move slowly and carefully with a lot of these plays in these areas and get good results and information back before we're making the decision to drill the next well, which is something we really like.

All at the same time though we're taking advantage of our existing infrastructure within the greater Sundance area to tie stuff in quickly and to keep cost down. It's sort of the perfect storm when we do get to spread it out.

I think through 2021, the species mix JP, maybe you can comment on the species mix, whether there's equivalent diversity, or I thought it was.

Yes, pretty close but we're probably going to drill about two-thirds Spirit Rivers and resemble one-third Cardium. We've always been returns focused so if gas prices being stronger is important, but also how much does it cost us to get that as well.

So this is all part of the factor. The Cardium still hunt, certainly, with the economics of it, also, because they're a lot cheaper to drill, and we've got some really good results recently on them, too.

It'll be more balanced, but I would say tips towards the Spirit River for next year, and then probably beyond.

Okay, maybe just a one quick follow-up question. There's been a lot of talk on M&A with different conference calls here this quarter.

What's your guys' view on M&A and just that broader subject?

I talked about it in my monthly report this past month. I think, obviously, consolidation in the industry ultimately gets you supply management, which everybody's looking for a better price these days.

So if that kind of discipline needs to come through consolidation, then I guess that's one of the main drivers, I think that we're seeing. We're already a fairly consolidated Group of Companies in the western Canadian basin, over 50% of production control by 10 companies alone.

We've seen, as you pointed out a lot of more recent consolidation too especially in the basin and the gas industry. We have looked at a lot of opportunities ourselves and we always compare that potential return to what we can do at the drill bit.

Our default tends to be and historically has definitely been to continue to work with the drill bit organically, rather than go buy other people's assets. But we always look.

Scott's group is constantly moving through both property valuations and corporates looking at other companies' opportunities and comparing those to our own. We haven't done anything material yet but we do.

Small deals tend to dominate what we do in any given year. They kind of fly under the radar, but there are little apartments or acquisitions here, there and around our existing areas that just strengthen our greater Sundance core area more than not, but we haven't really found an opportunity yet, beyond our existing core areas that we wanted to pounce on, but we keep looking.

Thanks.

Good morning. Could you give us an idea of across the gas plants and maybe what the throughput is across the nine plants versus capacity of those plants where you think future revenue grabs could take place?

Are you able to contract some of this third party volume on a longer term basis? Are those producers willing to negotiate around that?

It's a good question. I think the nameplate capacity of all of our existing facilities adds up to close to 850 million a day.

I think today, we probably would have to restart some compressors and restart some gear in order to get up to that level. So we've turned down some of our equipment to match our throughput.

That just optimizes costs for us more than anything but leaves us with that capacity availability. We do see, obviously, over the next year, volumes growing up to fill a lot of that capacity up but we will still have some access for third party if we can attract those third parties in.

I think it's difficult today to get real long term commitments out of anybody. Trans Canada, in fact, is seeing a lot of their service getting turned back to them because people are not prepared to make that kind of long term commitment for delivery.

I suspect a lot of the midstream companies, too, are negotiating with producers over existing contracts, both the term and the cost to them, because they're too onerous for companies to digest. We're not asking for that.

We've got available capacity today and we're offering it to those around us at a very attractive cost, which we think beats a lot of their costs, and we're not requiring them to make long term commitments. But I think if somebody was prepared to look at a long term deal, we would be prepared to look at carving out permanent capacity for them.

But at this point, we just sort of stay flexible with that and everybody gets a chance to see how the future unfolds without too much commitment.

Okay, that's fair. Thank you.

Good question.

Okay, that's great. Thanks for those questions.

We didn't have too many impairments on our website, or through infopeyto.com overnight. I did get one question yesterday that I wanted to post to Lee Curran just to comment on some of the technology that we're using today to drill so quickly.

Obviously, the speed at which we're drilling these horizontal wells is amazing. I can think back to when Peyto began, and when we were drilling primarily vertical wells to the Cardium and we would take a lot longer than 6.5 days to drill down to about 2,000 meters, and now we're drilling double that distance in that same amount of time.

What is the reason for the speed -- for the technology that we're using today? Is it something that's here to stay or is it something that just has to do with the state of the industry today?

Maybe further on that, are there other technologies coming down the pipe that are going to improve it even more?

Sure, Darren. I guess we're very fortunate to see this record well coincide with our milestone of 1000 horizontals.

But on that, there were a number of small design changes that contributed. Those include elements of our fluid program and bit selection.

However, the primary design element that affected that performance was pushing the monitor design concept and for those that are not completely familiar, that means we were able to eliminate the intermediate section of the wellbore. That included eliminating a complete casing string from the well drilling that surface casing point two TD interval as one interval without an intermediate step.

Now, this type of design carries some incremental operational risk. Often in the deep basin, we can see conditions that are very unforgiving in regards to lost circulation intervals, coals, and other intervals of instability.

A lot of those areas demand that extra string of intermediate casing. So this isn't something we can apply as a blanket design change across all of our assets.

That said, improved recent market conditions and a rapidly improving balance sheet is allowing us to invite a little bit more risk tolerance into our program so we're going to push that onboard design concept a little further than we have on the deep targets. Since drilling that particular well, we've actually set the bar a little higher.

The final well drilled off of this pad with the same rig and same crews reached a TD albeit slightly shallower, reach that in six days. So that's a full half-day faster.

When you say that quickly, half-day doesn't sound like much but to keep that in context, that's an 8% time improvement. So not only was it faster, but the full drill costs, inclusive of construction and future reclamation expense was well under $1 million.

So this is really just the product of a team that truly embraces continuous improvement. In our group, great is just not good enough.

1000 horizontal wells designed, drilled and completed by a relatively small, focused and consistent team, this is really the product of that. We maintain a level of tribal knowledge that is simply unparalleled in this industry, and in my mind is the pride of Peyto.

The average 10-year within our small VNC group in Calgary sits at over 13 years of service with Peyto so that speaks to that tribal knowledge. We've built relationships with key service providers that embrace our culture, and they truly see this as a long game.

Hard times in the market over the last couple of years have really driven to collaboration between ourselves and our service providers that's kind of taking that collaborative, environment to a whole new level. Our drilling rigs are fit for purpose.

Three of those four rigs have consumed nearly 8,000 operating days with Peyto. That's not to disregard the one new addition to the fleet that came to us in 2019, as they immediately fell into line and embrace that performance based culture.

But combined, those four rigs have drilled nearly half of Peyto thousand horizontal wells since 2009. Our primary directional service provider, they exist is somewhat of an extension of our company as well, they've pocketed almost 700 of those thousand horizontals.

So with that kind of experience under their belts, they hold an abundance of pride and what they've helped pay to accomplish. Our primary fracturing service provider who really didn't come into the mix in a meaningful way until 2015, is racked nearly half of those thousands of horizontal wells.

So the list continues. I could probably go on for days about that.

But whether it's in the office or out in the field, the concept of healthy competition has just kind of become part of our operational DNA. And this overarching ingredient allows us to continue reporting these performance gains, year after year.

That's what's going to be the recipe for success and improve performance in the future.

Sounds good to me. For me if we can get a little bit more collaboration with municipality's and maybe the Alberta Energy Regulator we'd even there, too.

Thankfully, one other question that came in that I did want to touch on before we end today. Kathy, there was a question on our interest costs in the quarter; they were lower than some analysts expected.

Appreciate that, we don't disclose all of our interest rates in detail to the to the market, but can you comment a little bit on our interest costs for the quarter and where they're headed?

Sure, Darren. So our interest costs for the quarter were as a percentage basis were actually higher than in prior quarters, which was to be expected under our new credit facility and also with the note purchase agreements.

Our subject now to higher stamping fees as we are in a higher grid level, however, we managed to maintain our debt to cash flow in a lower level than we initially had forecasted. A few months ago, just because prices are stronger and costs were good.

And, all the cost is really driven by one small change in a pricing level can have a meaningful impact on the actual interest costs on our entire debt. So, we managed it to maximize or reduce the interest as much as possible.

And as I said, the strong price has really helped us. Going forward, we're expecting that as the cash flows continue to be strengthening.

And we're going to see a lot of reduction, actually, in our interest costs. We should see probably about the same for the next quarter or two.

And then as our as our position in the debt cash flow grid comes down, we're going to see significant reductions in our interest costs.

Okay, great. Thank you.

Maybe lastly, I can just hit up JP here, we did talk in the release, obviously, about the increased length, some increased intensity in terms of stimulations, which is driving slightly better productivities this year. Obviously, we're doing that for much lower costs, which we talked about how we're getting those.

JP, maybe you can elaborate a little bit on the direction we're taking here. Some might argue that this has been a slower uptake in terms of pushing the envelope for length and stimulation intensity, to get better results.

But we've been pretty measured in that approach. Any comments on where we're headed?

Sure. For context here during there, it will reach program when we started drilling slightly longer horizontals at the beginning of the year with their first six averaged around 1600 meters.

But our last eight have been closer to 2200 meters on average, and with the longest one being around 2700 meters. This compares to previous years where we typically drilled 1300 to 1400 meter laterals.

We've also increased our frac intensity in the well reach up to about 0.8 tons per meter. On our last eight wells, where that's been closer 2.4 to 2.5 in the past tons per meter.

In the species, we haven't been quite as aggressive on the length, yet we've pushed our intensity up to about 0.8 tons per meter as well, which was up from about 0.6 tons in the previous years. So, of course, as you have indicated, these increases have also come with lower costs.

And that's important, overall costs are lower. So our unit costs are way down, as well.

But of course, that doesn't matter if we haven't gotten the productivity improvements, or those productivity improvements don't show up. So I'll refer back to the table in the press release, where we show that our 2020 program has demonstrated some impressive results and aggregate, and on the first six months of initial production from our previous years.

When you combine that with a stronger outlook on prices, we expect our 2020 program to yield something in the order of around 40% rate of return full cycle, which is certainly one of our best years in a while. So we're going to continue that.

And we expect those efforts to continue through 2021. We will continue to deploy this kind of program, and expect the same kind of improvements in that program next year.

To answer your question on what took us so long, you know, what increase these lateral links and increase the profit intensity? You know, we didn't do this overnight, and we have been experimenting over the last little while, with different designs, as Lee alluded to.

We've always been a very cost conscious company and we've been cautious on increasing risks with our operations. Lee eluded to that some of that already.

As we push out our longer laterals and attempt more stages of profit, we wanted to be sure that we could execute it in a way that was minimizing risk and still doing it cost effectively. So, we might have been a little short on the uptake.

But the other thing to think about is, we have been drilling, mostly Cardium over the last couple of years. So now with our new focus on the drier spirit river program in 2020 again, we've continued to evolve it.

You know, another consideration here is that, you know, we are drilling a deep basin, and they are thick, tight sands, but you know, when drilling with 100 hundred meters of rock, layers of rock, like the Montney. So, staying in the zone or we're in the good stuff, it's important to manage that risk.

So hats off to Dave and his team of geoscientists both in the office and the field. They've helped to reduce those risks and keep us in the zone during these longer laterals, so we don't have to pull back and sidetrack too often or get in trouble.

Often that happens at two in the morning. So, it's been a real team effort to both plan and execute the improvements of the 2020 program.

And as I said, I expect that will continue through 2021.

Okay. Thanks, JP.

All right, well, that I think pretty much wraps up our call this morning. As you've heard this morning, I think the Peyto team is really firing on all cylinders here.

We're achieving good results. And we're headed into a little bit more acceptable gas price environment going forward for us.

And that's really going to translate into some growing cash flows and a much better balance sheet. So we're going to feel a lot stronger here as we head into next year.

And we're looking forward to coming back to you with those results quarterly as they transpire and updating you with how we've been doing. So please stay tuned and keep a watch out on our website for both my monthly report and our quarterly reports and any other news that we've got to show.

We'll get the latest marketing information updated there. And an updated presentation should be up shortly with some additional color on what's going on in the industry and Peytobeta.

So, thanks, again for listening this morning.