Peyto Exploration & Development Corp

TSX:PEY

Earnings Call Transcript 2021-Q3

[Operator]

Good day, and thank you for standing by, and welcome to the Peyto's Q3 2021 Financial Results Conference Call. [Operator Instructions]I would now like to hand the conference over to your speaker today, Darren Gee, Chief Executive Officer. Please go ahead.

[Darren Gee, President, CEO & Director]

Well, thanks, Celine, and good morning, everyone. Thanks for tuning in to Peyto's Third Quarter 2021 Results Conference Call. Before we get started with the call this morning, 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. With me in the room today is almost all the Peyto management team. Our newly appointed President and Chief Operating Officer, JP Lachance, is here to answer your questions; as is Kathy Turgeon, our CFO; Scott Robinson, our VP of Business Development is here; Dave Thomas, our VP of Exploration; Todd Burdick, our VP of Production; and Lee Curran, our VP of Drilling and Completions are all here. Only one missing today is Derick Czember, our VP of Land, who is home with the flu, I believe, but I suppose it's bad time of the year. Before I get started with my comments today about our results, I do want to recognize the efforts of both our office and field personnel this past quarter. We had a really busy quarter of operations, and we drilled some fantastic wells in the quarter, just in time for the winter heating season and the most recent rally in natural gas prices. So kudos to the team for continuing to deliver the reliable energy that Albertans need to keep them warm in this upcoming winter. And we did it with a terrific score for safety and environmental performance. So a great job, everyone.On to third quarter results. Operationally, as I mentioned, it was a busy quarter. We picked up a fifth drilling rig in August and it's been getting up to speed doing things the Peyto way. So now we have 5 rigs that can run steady throughout next year. This was important because we're seeing a real challenge in the Canadian industry these days, both with available equipment and especially with getting qualified people to work on that equipment. And that is not really a problem that goes away if COVID goes away. That's an issue that's likely here to stay for some time, and it will likely put a cap on activity levels and the development of new production, regardless of what the commodity prices really do. So the fact that we have Peyto have the capability to drill more and develop more will be a big differentiator going forward for us.We did drill some great wells in the quarter in 2 of our expansion areas down in South Brazeau, in an area we call Chambers. We continue to delineate out several different plays there, which is important because it supports the long-term supply for the new 50 million a day gas plant we're building there.And in our Cecilia area, which is an area we acquired at the start of the year, we've had some great results up there that have completely filled the half-empty gas plant there. So now we're offloading incremental volumes to other plants in the area that have excess capacity. But we're also looking at expanding the Cecilia plant with more compression to move more gas through that plant a little later. So looking very good up there as well.So production grew nicely throughout the quarter. We had said that we expected to hit 100,000 boe/d by the end of 2021. And it looks like we're likely to hit that number sometime in mid- to end of November, so about 1 month early. And of course, we're not stopping, which means we should exit this year at something slightly higher than that. It will all really depend on how many wells we can get tied in before Christmas. And then we have a little bit of a Christmas break. And then we'll keep that momentum right into the New Year and throughout 2022. Commodity price realizations in the quarter, especially natural gas prices are rising. And they're continuing to rise significantly from this third quarter into Q4 '21 and on into 2022. As we indicated in the release, our Q4 hedge price is 55% higher than what we just got here in Q3. And our Q1 2022 hedge price is over 80% higher than what we had received in Q3. So that higher price, combined with more production is going to result in a very large increases in revenue and cash flow for the quarter is coming up. And really, our hedge program is still catching up the spot price. So we expect to see rising fixed prices for a while as we continue to hedge out the forward curve. For this winter, our gas is around, I think, 71% hedge with a fixed price. And for next summer, we're about 69% of our volume has a fixed price on it. So really, that gives us a high level of confidence in our projected revenue and cash flow. That's going to fund our capital program for '22 and our debt reduction program and our dividend that we just announced. So with this quarter, I think we can finally say that the weaker natural gas prices that we've seen over the last few years are finally behind us. Cost-wise, I'm happy to report we held the line on cost in the quarter. Obviously, royalties were much higher due to higher commodity prices. And that was really responsible for almost the entire increase in cash costs from a year ago. And op costs were good. They would have been lower but we did 10 plant turnarounds in the quarter. So that obviously had some costs associated with it. Todd can perhaps talk more about those later. Transport costs were up and will be for the next year due to some physical transport that we signed up for at the border at Empress and on the main line to Emerson. And then those contracts will start to roll off as we put some other diversification efforts in place. G&A costs in the quarter approach were minimal due to the Peyto's small team and the relative size of our capital program and production base. Our interest costs were down quite a bit as both our debt and our interest rate dropped. And that's because of a falling debt-to-EBITDA ratio this past quarter. This interest charge should continue to fall pretty steadily as we move forward with the lower interest charges of the new credit facility and as our debt is materially reduced. And that lower interest charge should really help offset the higher royalty costs due to the rising commodity prices. In total, though, I think we're doing a good job of maintaining our significant cost advantage over the industry. I think the other advantage we're maintaining over the industry is our environmental performance. Quite frankly, we've accomplished a lot over the last 5 years with methane emissions reduction. After we finish up working on the individual well sites to reduce virtually all the methane emissions there, we can turn our attention to our facilities and see what we can do to lower CO2 emissions at those locations and with that equipment. Like we mentioned in the release, I believe long term that we're going to be able to capture the majority of CO2 emissions from our facilities and dispose of that CO2 in deep underground storage reservoirs. Of course, that's going to take some time. It's going to take some money and perhaps a bit of innovation even to accomplish all of that. But that would be our long-term goal. And that should ensure that Peyto and its natural gas is around for a long time to come into the future. Speaking of a long time, it's -- I've been the President of Peyto for 15 years now. And it's finally time to recognize a guy that's been responsible for Peyto behind the scenes and that is JP Lachance, Jean-Paul. So this quarter, as part of our longer-term succession plan, we decided to make that recognition official by promoting JP to the position of President as well as being the Chief Operating Officer that he was before. Of course, JP has the whole Peyto team behind him for support, as he always has. And he has a very experienced and seasoned management team in this room to help him lead Peyto into the future. And I'll continue to be here for a good while yet to serve as CEO and to make the leadership change seamless and smooth.And lastly and probably most excitingly for the quarter. As part of the quarterly release, the Board decided to reinstate the monthly dividend shareholders at $0.05 per share or about $100 million annually. We've managed to earn close to $150 million over the last 4 quarters while also reducing our debt. And considering the free cash flow that we're projecting for 2022, we can afford to pay a much more significant dividend now while still achieving our ongoing debt reduction targets. So great to see that dividend bump. Anyway, that's pretty much a quick summary of the quarter. Very solid quarter both operationally and financially. And so I just wanted to get to any questions from listeners that are participating today. So Celine, maybe we can throw it open to questions from those listening in.

[Operator]

[Operator Instructions] We have our first question coming from the line of Chris Thompson with CIBC.

[Christopher Thompson, Research Analyst]

So Darren, outside of the 15% inflation that you highlighted in your 2022 preliminary budget, are you expecting any other inflationary impacts, whether it be your operating cost, G&A or otherwise?

[Darren Gee, President, CEO & Director]

Yes. That's a good question, and it's obviously topical these days. There's probably 2 places that the inflation comes in. Lee, maybe you can talk a little bit about the operations, drilling and completions on the capital side about inflation. And then maybe we can turn to Todd, and he can talk about some of the operating cost inflation that we might be exposed to?

[Lee Russell Curran, Vice President of Drilling & Completions]

Yes, sure. What's going on right now just a classic pricing response to low supply and increased demand. Lack of supplies is the main driver right now. And I think whether you're out there shopping for a new F-150 or you're looking for string casing, you're suffering a similar consequence.We're struggling right now as an industry to keep 170 rigs running, which is startling. The biggest element we're dealing with right now is shortage of personnel and then steel, specifically tubulars, casing and tubing. This is going to keep a pretty short leash on industry. And it's going to in turn create a supply issue with our goods. That effect is going to be higher commodity pricing.Controlling inflation itself, it's one of the things we've put a 15% number in. I think that's conservative. But in reality, it's going to be secondary to most -- for most operators relative to simply getting what they need to fulfill ambitious capital plans. These contracts have been struggling for several years. They've got ambitions to return to earnings along with that. They're experiencing direct inflationary pressures. Their labor is going up. Their consumables are going up. And a lot of the equipment sitting in the industry -- in the basin has been sitting racks. It's been serving as a part of people and that's been filtered to the point where it's going to take a lot of capital to get some of this idled gear back up and running. There just hasn't been any injected for so long. It's equipment that you can't activate at the snap of the fingers. So our approach really, we started gearing off on a different path to most other operators a few years back. This industry is notorious for this push and pull relationship between operators and contractors, everybody kind of trying to hold the upper hand when the environment is right.So we kind of geared off a couple of years ago. And we had stable, active capital program. We continue to demand the highest quality personnel and execution. And with that, we were offering at the time a fair level of compensation that certainly wasn't bolstering anyone's bottom lines. But we allowed our contractors to survive for the better days ahead and those days seem to be on our doorstep now. So we need these guys and we reminded them of that throughout the entirety of the last couple of years. We've had long-standing and very transparent relationships. And we're confident we're going to see some advantageous treatment in regards to both supply and pricing on this upswing. Right now, the 15% estimate is just that. It's an estimate. I don't know that anybody has a crystal ball on where this is going to land. Price increases on our tubulars alone have swallowed the lion's share of that already. So that's not to say we're kind of telling everybody that they can hit us with a 15% price increase right now. We expect tubulars to start normalizing towards the end of Q2 or early Q3. And that should provide a buffer to allow some of those services at that point in time to maybe bump up some pricing when we have -- when we see the -- some reprieve in our steel price. And that should coincide -- that coincides with our drilling rig contract renewals. So we're kind of locked in on rates there. We had a little bit of bump on pricing with labor increases, wage increases.So we'll see. I think we're sitting pretty good through the winter. We're working hard to manage expectations with our contractors. And these guys all, I think, recognize that Peyto's capital program and our position on pricing through the last several years has kept many of them afloat. So regardless of the broader inflationary picture, we expect to remain in a top position relative to the rest of the industry. I don't know what else I can really say about that.

[Darren Gee, President, CEO & Director]

Well, and Chris, you probably remember a couple of years ago, when we talked about the fact that even though our capital program had shrunk quite a bit, we were spreading it around. We had 4 rigs running at sort of 50% run rate to try and keep the equipment warm and the people employed and there so that we didn't lose them. So that's serving us well right now because now we have those same people in that same gear. And we can run them flat out in a busier environment. But we're not subject to some of the other inexperienced that's starting to creep its way back into the industry and that kind of thing. So it's I think that was a good plan back then, and we're kind of reaping the rewards of that now. To further answer your question, maybe, Todd, you could talk a little bit about operating costs and some of the inflation we might be seeing there?

[Todd Burdick, Vice President of Production]

Yes, for sure. I think to echo some of what we said as far as the service providers that we have out there similarly on the operating side with some of the contractors that are out there, performing services for us, we kept them busy and we've looked after them. So I think we'll continue to -- with that promise that we'll continue to keep them working, I don't think we'll see significant increases, maybe a fuel surcharge here and there that sort of thing, but nothing that should impact us in that way. There's some things -- chemicals. We've seen some significant pricing increase on methanol for example. The market prices doubled what it was a year ago. But we have locked in a really good price. We did that in August. We typically do that in August when the prices are lowest. So that's going to protect us for the remainder of the year significantly, although it was a higher -- a locked-in price higher than a year ago. It is protecting us a little bit. Lubricants, we use a lot of oil, a lot of lubricating oil. That obviously floats with the price of WTI to a large part, a little bit to CPI as well. So we do anticipate seeing a little bit of increase there. Power is another one. That's a tough one. Alberta produces 70% of its power through natural gas generation. So if power price is high, then we're making more money selling natural gas. But however, we generate power through the grid at about 90% of our usage. So that's -- we're going to feel that on the operating side, but that's surpassed significantly by the incremental revenue that we're seeing. So overall, I don't think we're going to see some inflation, but I don't see it being anything that's going to really shock us.

[Christopher Thompson, Research Analyst]

Great. Next question from me, just in terms of well abandonments and reclamations, I haven't seen any cash outlays come through on your financials with that. So perhaps you could add a little bit of color on company strategy for how it manages its abandonment liabilities?

[Darren Gee, President, CEO & Director]

All our wells are still producing, Chris. They're not ready to be abandoned yet. They're going to produce for decades more. No, just kidding. I mean we do have a few odd well that might be a candidate for abandonment that we're looking at. Do you guys want to jump in on that?

[Scott Robinson, Vice President of Business Development]

Yes, sure. I think that every year, we spend roughly about $1 million on abandonments or certainly suspensions that generally lead to abandonment, maybe not so much reclamation work. But -- and we have targeted for the next 2 or 3 years to continue to spend that. The recent announcement by the Alberta government around expectations -- or sorry, from the AER would be for us to spend around another $1 million next year. So that's in line with our budgets and what we'll continue to spend. But as Darren indicates, we don't have a lot to do really.

[Todd Burdick, Vice President of Production]

Yes. We are in the process right now of consuming our SRP allotment as well. So we -- we're well into that program, and that's probably another in total with our Phase 5 fund is close to $2 million. So we're active on that right now.

[Darren Gee, President, CEO & Director]

It's just not significant, Chris, because I'd say that facetiously. But the reality is that almost all of our wells are still producing today. And especially with the higher gas price, even the lower rate wells are still very commercial. So we just -- we don't have that liability.

[Christopher Thompson, Research Analyst]

Got you. Okay. And sorry, last question from me. In terms of debt levels, so for 2022, what are you targeting in terms of an absolute debt level? And then, I guess, on your estimates, what does that translate to in terms of relative debt levels to cash flow?

[Darren Gee, President, CEO & Director]

Yes. I mean for us, it is more of a debt to cash flow target that we're looking at, and it should be because we could see some commodity price changes throughout the year, right, and that would change our cash flow projections. But I think we are looking to be 1x debt to EBITDA by the end of next year. I think that's a reasonable expectation. That's sort of where the industry has gone, I think, in terms of deleveraging. And we've got the majority really of 2022 cash flows locked up with a lot of hedging that we're continuing to do into 2022. So we feel quite confident about where we're going to get to in terms of balance sheet. And that was obviously one of the big drivers in deciding how much dividend we could afford.

[Operator]

We have our next question coming from the line of [ David Bandler. ]

[Unknown Analyst]

I wondered if you could give us an update on the construction of the gas-fired electric generating plant you're going to be supplying. And some information about how you plan to increase production to supply that plant and just review how the gas is going to be priced and how that pricing fits into the diversified marketing structure you've been developing in the past couple of years?

[Darren Gee, President, CEO & Director]

Yes. Thanks, David. So that Cascade power plant that's being built by Kineticor is right close to our Swanson plant. We have been sort of tracking their activity. They have a website as well that you can Google and find and they show updates to their activity on that website. Todd, we've got guys that driveby there every day. So what are the guys seeing when they're out there in the field?

[Todd Burdick, Vice President of Production]

Yes. We're meeting with Cascade every now and then. They're giving us updates and they're making great progress. They showed us some pictures of the site this summer, and they're -- it's pretty amazing. It's quite a big project. And they have a lot going on, a lot of foundations already set, getting ready to put buildings and move equipment in as we understand it.This summer, we put the final connection into their facility, the final pipeline connection about 350 meters so that that's in there. So that accommodated some of the construction that they have going on. And then we'll look to work on our pipeline later in 2022 or early 2023. So yes, it's pretty impressive there. I think they're -- from all -- our understanding, they're on schedule for their anticipated startup in late 2023.

[Darren Gee, President, CEO & Director]

Do you want to add something?

[Scott Robinson, Vice President of Business Development]

Yes. Not a whole lot to add. It's been a very good working relationship with Cascade, and we're really looking forward to supplying the gas. One of your questions, Nathan, is it, I think -- David, one of the questions was the sourcing of the gas. And we've got a very diversified and flexible portfolio. So I don't think there'll be a real problem in meeting the needs. Our infrastructure is very well connected out there and should be able to supply this gas for a very long period of time.So we'll be drilling continuously into the start-up time, which is likely going to be -- it could be early, based on the progress they're making here, but it likely will be in 2023. Yes, and that's -- it is impressive what these guys are doing. They're starting to move in the big pieces of equipment right now. And we'll get a better gauge on their completion time here in the next -- during 2022.

[Darren Gee, President, CEO & Director]

Yes. No small construction projects at what, $1.6 billion or something. It's the capital expectation for that facility, something in that order. Contract-wise, David, we're bound by confidentiality with our gas purchase agreement with Kineticor, so we can't really divulge much there. Needless to say, we obviously do have a contract that ties the Alberta power pool price to our realized price. We get paid in -- effectively in the electrical price, but that translates back to us into some sort of realized gas price. But we feel good that the contract that we have with them will realize a fair gas price effectively for us with the types of power pool prices we're seeing. When we did the contract with them, I think Alberta pool price was hovering around in the sort of $30 to $50 megawatt/hour. Today, Alberta power pool prices are...

[Todd Burdick, Vice President of Production]

$90 to $100.

[Darren Gee, President, CEO & Director]

$90 to $100.

[Todd Burdick, Vice President of Production]

$140 to $150.

[Darren Gee, President, CEO & Director]

$140, $150 at times. So I mean Albertans are definitely seeing that in their power bills every month. But that obviously translates into a much higher natural gas price realization for us. Ultimately, I think, by probably 2023, and when this plant is up and running, Alberta will have a very large percentage of its power being generated from natural gas. We'll have turned off the majority of the coal-fired power in the province, and there's only a very small amount of renewables that really contributes. And even that has to be backed up by the natural gas. So there should be a fairly good tie between power pool prices and what the gas price is. And hopefully, we come out at least fair on that relationship. It is a 15-year commitment to deliver gas to them. And we've committed about half of the volume that they're going to need for that 15-year period. And like Scott said, we've got all our gas plants interconnected so that we can flow gas from pretty much anywhere in Greater Sundance to this facility if need be. And I would really say that we're so advantaged by being directly connected to them. We save a lot of cost, pipeline toll. Really, anybody else who wants to supply gas to them has to put their gas on Nova, pay a receipt tool to get on to Nova. And then Kineticor has to pay a delivery tool to get off of Nova with that same gas. And so we save both pieces of that toll by directly connecting to them. And I think likely, we will supply more than just the 50% that we've committed to. It makes economic sense for us to supply more. So whether we supply some for the others that have committed gas to them and in exchange, we do some sort of relationship with those parties. We'll see, but yes, we're excited for the plant to get up and running and excited to be a very significant part of the Alberta pool grid here when it comes to electricity.

[Unknown Analyst]

Can the capital...

[Scott Robinson, Vice President of Business Development]

Yes. The last thing to add the plant efficiency, this plant will be state-of-the-art, one of the best efficiencies environmentally in terms of the energy output or energy input. So that will bode very well on the pricing grid as well.

[Unknown Analyst]

Can the capital cost of any incremental production be funded internally by cash flow?

[Darren Gee, President, CEO & Director]

Absolutely, David. Our plan is obviously to have a portion of our production dedicated to this facility, and it's a portion of our total that we're projecting. If you've looked at our marketing slide section of our presentation, you can see that we've already provisioned for the wedge of volume that's going to go to Kineticor. Much like any other diversification that we would look at, this is the industrial piece that we'd like to get in our portfolio. We want to have some gas obviously exposed to Eastern Canadian markets, some exposed to the U.S. markets, some exposed to the industrial heartland here in Alberta and then eventually maybe even some exposed to West Coast LNG. So it's just a part and parcel of our total diversification.

[Operator]

We have our next question coming from the line of [ Nathan Schwartz. ]

[Unknown Analyst]

My question is about Peyto's green initiatives. Peyto has done a great job reducing Scope 2 and Scope 3 emissions. My question is really about Scope 1 emissions from fuel combustion. The Alberta hydrogen road map has talked a lot about things like blue liquid ammonia and blue hydrogen. And my question really is how do you look at Scope 1 emissions and how and when might Peyto start focusing on that challenge.

[Darren Gee, President, CEO & Director]

Yes. So you're right, Nathan, the Scope 1 emissions for us are defined as what, Todd?

[Todd Burdick, Vice President of Production]

That's basically what's coming out of our plants. That's the burning of natural gas or fuel or [indiscernible].

[Darren Gee, President, CEO & Director]

So it's the energy we consume to produce the energy that we sell in effect, right? So we know that every truck that drives around in our field burns fuel. We know that every drilling rig burns fuel, every frac pumper burns fuel and those are emissions. And then all of our plants obviously run -- we have gas-fired compressors at all of our plants. None of them are electric. So it's the exhausts from those gas-fired compressors. If we have power generation at those plants, then it's the gas that we burn to generate our own electricity. That is the emissions there. And so we talked in the press release about the fact that our first goal when we started to really address our environmental emissions was to look at the fugitive invented emissions at the well site. We knew that there was an opportunity to replace some equipment at our individual well sites to eliminate -- to try and eliminate the majority of that little bit of vented methane because that has obviously a significant impact in terms of environmental emissions, methane being more potent than CO2. And so we started there, and we've been actively working on that program, trying to get our field out at the well sites as clean as possible. And now we're starting to look at our well site -- or our gas plants in our major facilities and those emissions.And so when we look at that, we're looking at capturing, of course, any releases at those sites but also any consumed fuel at those sites, the exhaust CO2, if you will. That's a little bigger challenge, obviously, not unlike trying to capture the CO2 emissions from the tailpipe of your car. We're trying to do it on these great big engines that run our big compressors. It takes a significant amount of capital, obviously, to not only capture the exhaust but then to purify it into the components that we need to dispose of. And then we've got to dispose of that component. So we're just starting to look at that now. We've done a big study to evaluate where we're going to put it all. And we've got a lot of deep Leduc and Devonian reservoirs below all of our Greater Sundance area that can easily accommodate all of these emissions once we try and capture them. And so that's good. In a lot of cases, a lot of producers don't have that available disposal reservoir. They're going to have to ship it to a distant location to have it disposed of. And that's going to be awfully expensive. So we're looking at right below us. We would need to drill some disposal wells, obviously, but we're kind of practiced at drilling wells, having done it for 23 years now.And really, we're looking at bolting equipment onto our existing gas plants to try and capture that. That technology is still kind of at its infancy. But we definitely see that's the path forward to capturing the majority of our CO2 emissions at our gas plants.

[Unknown Analyst]

Okay. That's helpful. Let me just quickly follow up. I suppose my question is more broadly about the energy that you sell. And in the past, you've talked about using Big Sunny as part of a blue hydrogen strategy. And what I'd ask is, how do you view the path to blue hydrogen or the blue liquid ammonia as a product that you sell?

[Darren Gee, President, CEO & Director]

Yes. Really, it's -- that path, I think, is demand-driven. As there's more and more uptake for those types of fuels than our industry and ourselves, we'll be well positioned to respond to that by turning our natural gas into those fuels for consumption. That obviously requires some process -- refining process, if you will, or further facility process. We can look at either being the owner of that process or we can look at outsourcing that similar to, say, how we outsource fractionation of our LPG. So I think, obviously, we're going to work part and parcel with the industry and with even some of the government initiatives on that. But I think a lot of it, too, has to be driven by the demand side. There's no point in producing a whole bunch hydrogen if no one is going to buy it. And we have to see the demand side pick up and there be a call for that type of fuel. And I think we will be able to respond as an industry quite quickly to that call as it evolves. Do you want to add something?

[Scott Robinson, Vice President of Business Development]

Yes, there is interesting -- and you asked about ammonia. There is an early stage project concept in our area. And should that project get some traction and move forward, we certainly would be a candidate to supply gas. But like Darren says, most of these things are beyond our scope. And the methane -- the carbon hydrogen bonds that contain the energy, we can supply that to whatever process it is, be it syngas process that makes methanol or that makes eventually ammonia or hydrogen. Those are all exciting opportunities that lie ahead, but there are several steps that are in between now and when that happens, I think. There is this one project, and we're in early stage discussion on it.

[Operator]

And there are no further questions on queue. Presenters, please continue.

[Darren Gee, President, CEO & Director]

Well, great. We did have a couple of questions come in overnight. One of them was about the statement that we made in the press release about how our internal rate of returns were extremely high right now. And JP, I wondered if you could maybe expand upon that comment?

[Jean-Paul H. Lachance]

Sure. Thanks, Darren. I think this time of the year, every year, we have a tendency to look back at our program that we've drilled to date and have a close look at its -- at the results. And I mean it's a precursor. It's a requirement. It sets up our plan for next year. So it's an important process that we do every year. And we look back at about 61 wells so far this year that we have some production history. And that's made up of about 1/3 Notikewin,1/3 Cardium and 1/3 of our Wilrich predominantly, our extended reach horizontals. So when we look at that program to date, we're pleased to see that the rate of return of that drilling program looks like it will yield us around 112% rate of return, which is pretty impressive. I mean an important part of that, too, is that these wells, we expect -- well, some have paid out already. And we'll -- we expect a lot more to pay out by year-end and into early next year. So the program has certainly been very successful. And of course, that includes a provision for other costs outside of just the drill fleet and tie in of those wells. The pipelines and the plant work that we've done is included in that as sort of a guide or a measure of full cycle economics. So certainly, a good program. And these successes have happened all across Peyto's assets. But the standout clearly as you indicated, Darren, earlier, the Notikewin in Cecilia, Cardium and Chambers and our -- of course, our Wilrich extended reach horizontals are working out quite nicely, and that's both in Sundance and the Brazeau area. So quite pleased with that. And clearly, price is the reason why these economics are so good. But the team has also managed to get both our -- the productivity of these wells up and the cost down. When we look at cost per meter, cost per stage, cost per ton, they're all lower across all our key species. And then when you factor in the purchase that we made earlier this year, the about $35 million we spent on buying the Cecilia assets and you add in the base production that comes along with that, our total capital program this year should yield us around 100% rate of return. So that's certainly the best returns that I've seen since I've been here. And why is that important? Well, looking forward to 2022, we plan to drill a similar program, similar size program, similar mix of the species that we've drilled this year. And we obviously added in some inflationary costs, as Lee alluded to and Darren and we did in our press release. But even with those costs, inflationary costs in there, we see a lot of these species returns that are in that 100% range. And we expect that to -- and those payouts will be in less than a year. So it helps take some of the pressure off with respect to commodity price risk as it were. And we hope to actually partially mitigate at least the cost inflation with operational efficiencies as well. So that factor as well. So I think the team, they're ready and they're excited about the '22 program and certainly pleased with the results so far this year.

[Darren Gee, President, CEO & Director]

Thanks, JP. The one other question that came in overnight was with respect to sort of our debt profile, rising interest rates potentially as a response to inflation. Kathy, we issued that note, I guess, it was after the quarter, but it was included in our press release. Pretty good priced interest rate, but how much interest rate risk do we have with sort of some of this inflation pressure that we're all talking about?

[Kathy Turgeon, VP of Finance, CFO & Director]

Well, that's a good question, Darren. Obviously, the interest rates are starting to be forecast to rise, Bank of Canada rates probably mid next year. And that is going to affect the underlying interest rates that we pay on our revolving debt. So as part of our strategy is the debt repayment. And so we're seeing our revolving debt or variable rate debt declining from about $700 million right now at the end of Q3, down significantly by the end of 2022, where our fixed portion of the debt is actually going to start to be the more higher portion of our mix. And that's going to expose us to less and less variable interest rate risk. So by the time we see interest rates really ramping up in 2022 and into 2023, just the actual dollar amount that we will see being exposed to that will be quite small. Therefore, the risk is -- well, it's certainly there. It's not going to be that material to us.

[Darren Gee, President, CEO & Director]

Okay. Good. And then maybe just a final question. Dave, maybe I can ask you about some of the future drilling inventory that we're looking at? We obviously drilled -- started to drill on that new acquired property in Cecilia. We've had some good results there. Without giving too much away, maybe you could speak a little bit about what plays we've started to delineate, maybe what interesting things we found and what's our inventory looking like up in that area?

[David Alan Thomas, Vice President of Exploration]

Sure, Darren. The facility acquisition is really turning out to be a big success story for us. It's one of those instances where the upside is unfolding just as we'd hoped and perhaps even better. The wells drilled table in the press release really doesn't tell the story, the table groups wells by which gas plant they flow to. But Cecilia's located wonderfully smack dab in the midst of our infrastructure. So gas has a choice of several plants to flow to. So we've actually drilled 8 wells so far, 6 Notikewin and 2 Upper Falher on what we term as the Cecilia lands plus we have 2 more Notikewin to finish up drilling here in Q4. There's also 3 additional wells that were drilled farther south in the Ansell area. Those lands are actually also linked to the Cecilia acquisition. And next year, we'll have 1 rig dedicated pretty much entirely to Cecilia. And we hope to drill about 18 wells there in the budget. Those are mostly Notikewin, but we plan to also test the liquids-rich Dunvegan. So that's really going to be a first for us in the Greater Sundance area. So the Cecilia lands are far enough up north to include some Dunvegan opportunity. The actual inventory at Cecilia was estimated to be just shy of about 100 wells, including 30 Notikewin and 50 Cardium. But what we're seeing so far are giving hints that the death of the Notikewin inventory may actually be underestimated. And that's really important because the Notikewin we drilled so far have turned out to be very prolific, with several estimated to pay out in less than a year. All in all, it's a great success story. And I'm sure you'll be hearing more positive updates in the future.

[Darren Gee, President, CEO & Director]

All right. Good stuff. Well, that's a pretty good note maybe to end on. I don't see any additional questions. So thanks, everybody, for listening in. And it's been an exciting quarter for us and really the start of, I think, the next job for Peyto, which is looking very interesting. We've got some pretty fantastic commodity prices driving some incredible returns. We've got lots of inventory. We've got the gear to get it done and the people as well. So we're pretty excited about the next 12 months. We're going to put our head down and get that activity done and make sure that we can achieve those fantastic-looking financial forecasts that we have. And we'll be back to you every quarter to update you on how that's going. So I encourage everybody to listen in and check the website often. And I'll keep the monthly reports coming. Thanks again for listening in this morning.

[Operator]

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