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Good morning, ladies and gentlemen. Thank you for standing by. And welcome to the Peyto's Third Quarter 2020 Financial Results Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Darren Gee, President and Chief Executive Officer. Please go ahead.
Well, good morning. Thank you, Sydney, and thanks for everyone for tuning in to 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 the company's 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 Land; and Todd Burdick, our VP of Production. Before I get started with comments about our quarterly results, I do want to recognize the efforts of our staff and field people. Our field people continue to conduct operations in the quarter with safety foremost in mind, especially with COVID risks increasing as we head into the fall, both our production operations, field people and I think our extended service providers on all our drilling rigs, frac crews and pipeline spreads. They all worked efficiently and safely throughout the quarter with no loss time accidents and with very few issues at all. So a very successful operational quarter. I think all of those working for Peyto are proud to continue to provide Albertans with its reliable and affordable energy that they need every day and the fuel to heat their homes, especially as we enter into another cold, dark winter here in Alberta. So a big thank you to all our people, both here in Calgary and out in the field for continuing to keep both the light and the heat on. And also, before I forget, I would like to take this opportunity to thank Tim Louie, our VP Land for 9 years of dutiful service to Peyto. On behalf of the Board, shareholders and employees, we wish him all the best in his retirement. Okay, so on to our third quarter results. Operationally, the third quarter went quite well. We drilled some very good wells and grew production from 78,000 barrels a day to about 83,000 by the end of the quarter. And that growth isn't stopping here as we head into the end of the year. We did get some plant turnarounds done in the quarter actually. So our gear has been fully serviced and is ready for another year of operations. As mentioned in the release, we celebrated our 1,000 horizontal well in the quarter. That number still continues to blow me away, especially since I was here as many in the room were back when we drilled our first horizontal well over a decade ago. Our first horizontal well, as I said, dates back to 2009, in the fall of 2009, I think, is when we drilled our first one. And since that time, we've drilled a total of 4.3 million meters of hole which is an amazing statistic. That's basically the distance from Vancouver to Halifax. So one could say that we've drilled our way across Canada over the last decade. And I don't think too many companies can make claim to that. We've tested out some Spirit River plays and some Cardium in a few different areas this quarter, and I think we're very pleased with the results so far. In fact, our average productivity this year seems to be better than we've seen in the past few years. I think that's also due to the fact that we're drilling longer horizontal laterals and opening up more reservoir on average as well. And of course, the best part of those longer laterals is that we're also doing it cheaper. So when you combine the better productivity and the greater reserves with lower costs, you get much better rates of return. And when you pile on top of that, higher gas prices, well, then things are really starting to look up. Sadly, however, we weren't able to realize a better gas price for all our production, though. We still have the carryover of some expensive AECO-to-NYMEX basis deals that were put in place back in 2018 when the AECO market was completely broken. That costs us around $27 million of cash flow for the quarter, which is a painful pill to swallow. We're still going to have to live with a few of those deals for a few more quarters before they're gone, and we start to see much higher realized prices, but we're eager to get there. Other than that, I think financial results were more or less in line with what we expected. Costs were generally good, although we are looking for some help on the government fees and taxes part of our costs. That becomes more and more of our fixed costs, both the AER fees and the municipal taxes in Alberta, I believe, need to be adjusted a bit to reflect the realities of today. We're working with industry groups to try and make that happen. And I think we're finally starting to make a little bit of headway there. As noted in the release, we did finally attract some third-party production to one of our plants. So we should see some fee income in the future quarters that can help offset some of our costs. It will show up in our financials as a new revenue stream. It's taken a while, but we did finally convince an operator in the area that we can produce their gas for cheaper than they can, and we can both share in that benefit. So hopefully, we could do that with some more operators in the area. Also as noted in the release, we're contemplating a bigger capital program in 2021. We have a lot of very profitable-looking drilling locations that we'd like to drill and think that the combination of higher production from that investment and higher gas prices will give us higher cash flows and lower debt to cash flow ratios. And then if we hold production at those higher levels, we'll be generating a lot of free cash flow beyond next year that we can use to pay down debt and delever our balance sheet and also pay out dividends. And that's actually even considering that the gas price strip right now is in backwardation beyond 2021, where it actually falls for the next few years. If the back end of that futures curve does come up to flatten out, as we've seen on the front end, then we're obviously going to generate even more free cash flow. But we're not going to leave the commodity price purely to chance, of course. We do have an active hedging program that's designed to get us fixed prices for much of our cash flow. We currently have approximately 72% for this winter's gas hedged already and close to 60% of next summer. Those hedge levels fall back to about 40% for the winter of '22 and 20% for the summer '22. But we are still actively hedging, and we'll continue to bring all those levels up to our 75% target before we enter those seasons. So we won't leave too much to chance when it comes to natural gas prices and fixed prices going into those capital programs. So we should know with confidence what our revenues are going to be and what our cash flow is going to be to fund those. So all in all, I'd have to say the future is starting to look much better to us, assuming we can get through COVID unscaled, so far, that's been the case. And while this quarter was a tough one, I think from a price and cash flow perspective, we do expect things are getting much better from here. So maybe that's where I should leave it in terms of comments on the quarter. And Sidney, maybe we can take this opportunity to throw it open to questions from those listening in.
[Operator Instructions] Our first question comes from Jeremy McCrea with Raymond James.
I was curious just with the improvement in gas prices. How much you, who are looking to shift your capital budget for the next year to do more drier gas wells like your Wilrich and that versus what you've historically done in the last couple of years just in the Cardium? And if there's any other drier gas placed that you're looking at here?
Yes, 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 Bluesky, the Wilrich, the Falher, Notikewins, beyond 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. So it's sort of the perfect storm when we do get to spread it out. And I think through 2021, the species mix, JP, maybe you can comment on the species mix, whether there's both equivalent diversity or I thought there was, but...
Yes, pretty close, but we're probably going to drill about 2/3 Spirit Rivers and about 1/3 Cardium. And we've always been returns focused, right? So 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. And the Cardium is still hunt certainly with the economics of it all. So because they're a lot cheaper to drill, and we've got some really good results recently on them, too. So it's going to be -- it will be more balanced, but I would say it tips towards Spirit River for next year and then probably beyond.
Okay. And maybe just one quick follow-up question. There's a lot of 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?
Yes. 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 is looking for a better price these days. And so if that kind of discipline needs to come through consolidation then I guess that's what are 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 controlled by 10 companies alone. So -- and we've seen, as you point out, a lot of more recent consolidation, too, especially in the Deep 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 with 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 out and buy other people's assets. But we always look. Scott's group is constantly mowing through both property valuations and corporates, looking at other companies' opportunities and comparing those to our own. We haven't done anything materially 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 that, but we haven't really found an opportunity yet beyond our existing core areas that we wanted to pounce on, but we keep looking.
[Operator Instructions] Our next question comes from Travis Wood with National Bank Finance.
Could you give us an idea of -- across the gas plants and maybe what the throughput is across the 9 plants versus capacity and -- of those plants where you think future revenue drabs could take place? And 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 excess 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. I mean, TransCanada, 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. And I suspect a lot of the midstream companies too are negotiating with producers over existing contracts, both the term and the cost of them because they're too onerous for companies to digest. So 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.
And ladies and gentlemen, I'm not showing any further questions at this time. I'd like to turn the call back to Darren Gee for any further remarks.
Okay. That's great. Thanks for those questions. We didn't have too many in bounce on our website or through infopeyto.com overnight. I did get one question yesterday, I wanted to pose 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 doing these horizontal wells is amazing. I can think back to when Peyto began. And when we were drilling primarily vertical wells to the Cardium, 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. So the -- 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 industry, state of the industry today? And maybe further on that, are there other technologies coming down the pipe that are going to improve it even more?
Sure, Darren. I guess, this -- it was -- we are very fortunate to see this record well coincide with a milestone of 1,000 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 monobore design concept. And for those that are not completely familiar that means we were able to eliminate the intermediate section of the wellbore. And that included eliminating a complete casing string from the well drilling that surface casing point to TD interval as one interval without an intermediate step. Now this type of design carries some incremental operational risk and 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. And 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 monobore 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, reached that in 6 days. So that's a full half-day faster. And 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, grade is just not good enough, 1,000 horizontals -- 1,000 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 tenure within our small D&C group in Calgary sits at over 13 years of service with Peyto. So that speaks to that travel 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 taken that collaborative environment to a whole new level. Our drilling rigs are fit for purpose. 3 of those 4 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 embraced that performance-based culture. But combined, those 4 rigs have drilled nearly half of Peyto's 1,000 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 1,000 horizontals. So with that kind of experience under their belts, they hold an abundance of pride in 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 fracked nearly half of those 1,000 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 improved performance in the future.
Sounds good to me. For me, if we can get a little bit more collaboration with the municipalities and maybe the Alberta Energy Regulator, we'd even be late or the race is there, too. Thanks, Lee. 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. I appreciate that we don't disclose all of our interest grid in detail to the market. But can you comment a little bit on our interest cost 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. We are subject now to higher staffing fees as we are in a higher grid level. However, we are -- we've managed and maintained 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 -- the cost is really driven by a change to one small change in a pricing level can have a meaningful impact on the actual interest cost on the -- our entire debt. So we managed it to maximize the -- 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 2. And then as our position in the debt to cash flow grid comes down, we're going to see significant reductions in our interest costs.
Okay. Great. 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 Lee 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 comment on where we're headed?
Sure. For context here, Darren, the Wilrich program, we started drilling slightly longer horizontals at the beginning of the year with our first 6 averaged around 1,600 meters. But our last 8 have been closer to 2,200 meters on average and with the longest one being around 2,700 meters. This compares to previous years where we typically drilled 1,300 meter to 1,400 meter laterals. We've also increased our frac intensity in the Wilrich up to about 0.8 tons on average -- sorry, 0.8 tons per meter on our last 8 wells, where that's been closer to 0.4 to 0.5 in the past tons per meter. In the Notikewin and the Falher 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 year. So of course, as you indicate, these increases have also come with lower costs, and that's important. Overall costs are lower. So that -- our unit costs are way down 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 impressive results in aggregate and on the first 6 months of initial production from our previous years. When you combine that with the stronger outlook on prices, we expect our 2020 program to yield us 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'll 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, to increase these lateral lengths and increase the profit intensity. We didn't do this overnight, and we have been experimenting over the last little while with different designs, as Lee alluded to. However, we've been very -- we've always been a very cost-conscious company. And we've been cautious on increasing risk with our operations. Lee alluded to that some of that already. As we push out our longer laterals and attempt more stages of profit, we've wanted to be sure that we could execute in a way that was minimizing risk and still doing it cost effectively. So we might have been a little short on the uptick. But the other thing, too, 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. Another consideration here is that we are drilling in a deep basin, and they are fit type sands, but we're not dealing with 100 meters of rock, layers of rock like the Montney. So staying in the zone. We're in the good stuff. It's important to manage that risk, right? 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 when we get in trouble. Often that happens at 2 in the morning. So it's been a real team effort to both plan and execute the improvements to 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 with Peyto. So thanks again for listening this morning.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone, have a good day.