Peyto Exploration & Development Corp.

Well thanks, Lina, and good morning, everyone. Thanks for tuning in to Peyto’s third quarter 2021 results conference call.

Before we get started with 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; 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 Completion are all here. Only one missing today is Derick Czember, our VP of Land, he was home with the flue I believe, but I suppose that is not here.

Before I get started with comments 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 the 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 this upcoming winter and we did it with a terrific score for safety and environmental performance. So great job everyone.

Onto third quarter results, operationally as I mentioned it was a busy quarter. We picked up fifth drilling rig in August and it has been getting up to speed doing things to fade away.

So now we have five rigs that can run steady throughout next year. This is important because we are 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 is an issue that is 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 and two of our expansion areas down in South Brazeau in an area that 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 billion a day gas plant we are building there. And in our Cecilia area, which is an area we acquired at the start of the year, we have had some great results up there that have completely filled the half empty gas plant there.

So now we are offloading incremental volumes to other plants in the area that have excess capacity. But we are 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 a day by the end of 2021 and it looks like we are likely to hit that number sometime in mid end of November, so about a month early.

And of course we are not stopping, which means we should exit this year at something slightly higher than that, it will all really depends 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 will 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 are continuing to rise significantly from this third quarter into Q4 2021 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 prices over 80% higher than what we received in Q3.

So that higher price combined with more production is going to result in very large increases in revenue and cash flow for the quarter is coming up. And really our hedge program is still catching up to 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.

For next summer, we are 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 is going to fund our capital program for 2022 and our debt reduction program and our dividends that we just announced.

So with this quarter, I think we can finally say that the weaker natural gas prices that we have seen over the last few years and finally behind us. Cost wise, I’m happy to report we held the light on costs 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 talking perhaps talk more about those later.

Transport costs were up and will be for the next year due to some physical transports 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 of course were minimal due to 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 is 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 are doing a good job of maintaining our significant cost advantage over the industry. I think the other advantage we are maintaining over the industry is our environmental performance, quite frankly.

We have accomplished a lot over the last five years with methane emissions reduction. After we finish up working on the individual wells 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 are 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 is going to take some time, it is 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 it is natural gas is around for a long time to come into the future.

Speaking of a long time, I have been the President of Peyto for 15-years now, and it is finally time to recognize, a guy that has been responsible for Peyto behind the scenes, and that is JP Lachance, John 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 team behind him for support as he always has. And he has very experienced and seasoned management team in this room to help him to lead Peyto into the future.

And I will continue to be here for a good while 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 dividends to shareholders at $0.05 per share, or about 100 million annually.

We have managed to earn close to 150 million over the last four quarters, while also reducing our debt and considering the free cash flow that we are 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 is pretty much a quick summary of the quarter. A 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.

Good morning. And thanks everyone.

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 costs, G&A or otherwise?

Yes. That is a good question.

And it is obviously topical these days. There is probably two places that inflation comes in, Jean, 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 costs, inflation that we might be exposed to.

Sure. I mean, what is going on right now is, just a classic pressuring response to a low supply and the increased demands.

Lack of supplies is the main driver right now. And I think, whether you are out there shopping for a new F-150, or you are looking for a string encasing you are suffering the similar consequence.

We are struggling right now as an industry to keep 170 rigs running, which is startling, the biggest elements we are dealing with right now with a shortage of personnel and steel, specifically tubulars casing and tubing. This is going to keep a pretty short leash on industry.

And it is going to, in turn create a supply issue with our goods. That affect is going to be higher commodity pricing.

Controlling inflation itself, it is sort of things we have put a 15% number in, I think that is conservative, but in reality, it is going to be secondary to most, for most operators, relative to simply getting what they need to still fulfill ambitious capital plans. Those contractors are struggling for several years, they have got an ambition to return earnings.

Along with that they are experiencing direct inflationary pressures, their labor’s going up, their consumables are going up. And a lot of the equipment sitting in the basement has been sitting racks, it has been serving as a part of people and it has been filtered to the point where it is going to take a lot of capital, get some of this idle gear, back up and running.

It just hasn’t been any injected for so long. It is equipment that you can 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 environments right. So we kind of veered off a couple years ago.

And we had a 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 have had long standing and very transparent relationships.

And we are confident, we are 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 is 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 is not to say, we are 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 actually provide a buffer to allow some of those services at that point in time 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 are kind of locked in on rates there we had a little bit of pricing with labor increases wage increases.

So we will see, I think we are sitting pretty good through the winter. We are working hard to manage expectations with our contractors.

And these guys all I think recognize the Peyto’s capital program and, 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.

Well, Chris, you probably remember, a couple years ago, when we talked about the fact that even though our capital program has 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 is serving as well right now, because now we have those same people in that same gear, and we can run the plat out in a busier environment but we are not subject to some of the other inexperienced with certain previous way back into the industry and that kind of thing.

So, I think that was a good plan back then and we are kind of reaping the rewards of that now. To further add to your question, maybe, Todd, you could talk a little bit about operating costs, and some of the inflation we might see in there.

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 have kept them busy, and we have looked after them.

So, I think we will continue to, with that promise that we will continue to keep them working, I don’t think we will see significant increases, maybe a fuel surcharge here or there, that sort of thing, but nothing that that should be impacted in that way. There is some things chemicals, we have seen some significant pricing increase on methanol, for example, the market prices, double 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 is going to protect us for the remainder of the year, significantly. Although it was a higher locked in price higher than that a year-ago, is protecting us a little bit.

Lubricants, we use a lot of oil, a lot of lot of lubricating oil that obviously floats with the price of WTI to a large part a little bit with CPI as well. So we do anticipate seeing a little bit of increase there.

Power is another one that is, it is a tough one. Alberta produces 70% of its power through natural gas generation.

So is our rate is high then we are making more money selling natural gas. But however we generate power through the grid about, at about 90% of our usage.

So that is we are going to feel that on the operating side, but that is surpassed significantly direct incremental revenue that we are seeing. So overall, I don’t think we are going to see some inflation, but I don’t see it being anything that is going to really shock us.

Great. Thanks for the color.

Next question for me, just in terms of well abandonment and reclamations, I haven’t seen any cash outlays come through on your financials with that. So perhaps you get add a little bit of color on Company’s strategy for how it manages is spent in liabilities?

All our wells are still producing. They are not ready to be abandoned yet.

They are 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 are looking at. Do guys want to jump in on that?

Sure. I think that every year we spend roughly about $1 million on abandonments or certainly suspensions that general lead to abandonments, maybe not so much reclamation work and we have targeted for the next two or three years to continue to spend that.

The recent announcement by the Alberta Government around expectations - sorry, from the ER would be for us to spend around another $1 million next year. So that is in line with our budgets and what we will continue to spend.

But as Darren indicates, we don’t have a lot to do really…

We are in the process right now of consuming our SRP allotment as well. So we are well into that program and that is probably another in total with that Phase 5 funds is close to two million.

So we are active on that right now.

It is just not significant, Chris, because you have - I say that should leave 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 don’t have that liability.

Got you. Okay, last question for 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 of cash flow?

Yes, I mean, for us, it is more of a depth-to-cash flow target that we are looking at. And it should be because we could see some commodity price changes throughout the year, and then that would change our cash flow projections.

But I think we are looking to be a onetime debt-to-EBITDA by the end of next year. I think that is a reasonable expectation.

That is sort of where the industry has gone, I think in terms of de-leveraging, and we have got the majority really of 2022 cash flows locked up with a lot of hedging and that we are continuing to do into 2022. So we feel quite confident about where we are 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.

Okay. Thank you.

I will turn it back.

Great. Thanks Chris.

Good morning. I wondered if you could give us an update on the construction of the gas fired electric generating plant you are 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 fixed into the diversified marketing structure you have been developing in the past couple of years?

Yes. Thanks David.

So that cascade power plant that is being built by Canada Corp, 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 have got guys that drive by there every day.

So what are the guys seeing when they are out there in the field?

Yes. We were meeting with Cascade every know them they are giving us updates, and they are making great progress, they showed us some pictures of the site this summer, and it is pretty amazing, it is quite a big project and they have a lot going on, lot of foundations already stacked getting ready to flip buildings and move equipment in.

And as we understand it. This summer we put the final connection into their facility, the final pipeline connection about 350 meters, so that that is in there.

So that accommodated in some of the construction that they have going on. Then we will look to work on our pipeline later in 2022 or early 2023.

So yes, it is pretty impressive, I think from all our understanding they are on schedule for their anticipated start up late 2023.

Do you want to add Dave?

Yes. Not a whole lot to add.

It is been a very good working relationship with cascade, and we are really looking forward to supplying the gas. One of your questions, Nathan, I think sorry, David, one of the questions was the sourcing of the gas, and we have got a very diversified and flexible portfolio.

So I don’t think it will 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 will be drilling continuously into the startup time, which is likely going to be - it could be early based on the progress they are making here, but it likely will be in 2023. Yes that is impressive what these guys are doing.

They are starting to move into big pieces of equipment right now, and I will get a better gauge on their completion time here in the next - during the 2022.

Yes. Those small construction project at a what billion six or something.

It is the capital expectations for that facility. Something in that order, contract wise, David we are, we are bound by confidentiality with our gas purchase agreement with Canada Corp.

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 and 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 power types of power pool prices we are 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 or $90 to $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, then when this plant is up and running, Alberta will have a very large percentage of its power being generated from natural gas.

We will have turned off the majority of the coal fired power in the province. And there is 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 have committed about half of the volume that they are going to need, for that 15-year period.

And like Scott said, we have 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 are so advantaged by being directly connected to them.

We save a lot of costs, pipeline toll, really anybody else, who wants to supply gas to them has to put their gas on Nova or pay a receipt, toll to get on to Nova and then Canada Corp has to pay a delivery toll 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 have 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 will see.

But, yes, we are excited 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.

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 per energy input. So that will move very well on the pricing grid as well.

On the capital cost any incremental production you funded internally by cash flow.

Absolutely, David, our plan is obviously to have a portion of our production dedicated to this facility. And it is a portion of our total that we are projecting.

If you have looked at our marketing slide section of our presentation, you can see that we have already provisioned for the wedge of volume that is going to go to Canada Corp much like any other diversification that we would look at. This is the industrial piece that we had like to get in our portfolio.

We want to have some gas obviously exposed to Eastern Canadian markets. So, I’m 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 is just a part and parcel of our total diversification.

Okay. Thanks a lot.

You bet. Great questions.

Hi. 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 roadmap 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?

Yes. So, you are right.

Nathan, Scope 1 emissions for us are defined as what I thought.

That is basically what is coming out of our plant that is the burning of natural gas for fuel .

So, it is the energy we consume to produce the energy that we sell in effect. So, we know that every truck that drives around in our field need fuel.

We know that every drilling rig burns fuel, every frack pumper burns fuel and those are emissions. And then all of our plants obviously, run - we ha we have gas powered compressors at all of our plants.

None of them are electric. So it is the exhausts from those gas-fired compressors.

If we have power generation at those plants and it is 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 indented emissions at the well site.

We knew that there was an opportunity to replace some equipment with our individual wells 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. So we started there and we have been actively working on that program, trying to get our field out at the wells sites as clean as possible.

And now we are starting to look at our well sites, at our gas plants and our major facilities and those emissions. And so when we look at that, we are 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 is a little bigger challenge, obviously. Not unlike trying to capture the CO2 emissions from the tailpipe of your car.

We are 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 exhausts, but then to purify it into the components that we need to dispose of and then we have got to dispose of that component.

So we are just starting to look at that now. We done a big study to evaluate where are we going to put it all.

And we have got a lot of deep (Ph) 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 is good.

In a lot of cases, a lot of producers don’t have that available disposal reservoir. They are going to have to ship it to a distant location to have it disposed of and that is going to be awfully expensive.

So we are looking at right below us. We would need to drill some in disposal wells, obviously, but we are kind of practiced at drilling wells.

Having done it for 23-years now and really we are looking at bolting equipment onto our existing gas plants to try and capture that that technology is still kind of in its infancy. But we definitely see that is the path forward to capturing the majority of our CO2 emissions at our gas plants.

Okay. That is 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 have talked about using big sunny as part of a blue hydrogen strategy. And what I ask is, how do you view the path to blue hydrogen or blue liquid ammonia as a product that you sell?

Yes, really it is that path I think is demand driven. There is more and more uptake for those types of fuels, then our industry and ourselves will 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 a 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 are going to work part and partial 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 is no point in producing a whole bunch of hydrogen if no one is going to buy it. And we have to see the demand side pick up and then there will 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 some?

Yes, there is a interesting, you ask about ammonia. There is 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 to continue the energy, we can supply that to whatever process it is.

Be it a sin gas process that makes methanol or that makes eventually ammonia or hydrogen. Those are all exciting opportunities that lie ahead, but there is several steps that are in between now and when that happens I think.

There is this one project and we are in early stages of discussion on it.

Great. I thank you.

And I thank you for being such a good steward of my money.

You are welcome.

Well, great, we did have a couple 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.

Sure. Thanks, Darren.

I think this time of year, every year, we have a tendency to go to look back at our program that we drilled to-date and have a close look at the results. And I mean, it is a precursor, it is a requirement.

It sets up our plan for next year. So it is 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 is made up of a boat third not the queue, and a third Cardium, and a third of our well rich predominantly our extended reach horizontals. So when we look at that program to-date, we are 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, in important part of that too, is that these Wells we expect, well some have paid out already and will exp we expect a lot more to pay 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 drills, complete tie in of those Wells, to the pipelines and the plant work that we have done. This included in that as sort of a guide for a measure of full cycle economics.

So certainly a good program. And these successes have happened all across Peyto’s assets, but standards clearly, as you indicated earlier, not a Q1 in Cecilia and Cardium and chambers and of course our well rich extended reach horizontals are working out quite nicely, and that is both in Sundance and the Brazeau area.

So quite pleased with that. And you know clearly price is a reason why these economics are so good.

But the team has also managed to get both the productivity of these wells up and the costs down. And when we look at cost per meter, cost per stage, cost per ton, they are all lower costs across all our key species.

And then when you factor in the purchase that we made earlier this year, 35 million we spent on buying the Cecilia assets and you adding the base production that comes along with that, our total capital program this year should yield this around a 100% rate of return. So, that is certainly the best returns that I have seen, since I have been here.

And why is that important? We are looking forward to 2022, we plan to drill a similar program, similar size programs, similar mix of the species that we have 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 in that 100% range, and we expect that those and those fields will be in less than a year.

So, it helps take some of the pressure off with respect to commodity price risk as it works. And we hope to actually partially mitigate at least, the cost inflation with operational efficiencies as well.

So, there is that factor as well. So I think the team, they are ready and they are excited about the 2022 program and certainly pleased with the results so far this year.

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.

We issued that note, I guess it was after the quarter, but it was included in our press release pretty good price to interest rate. But, how much interest rate risk do we have with sort of some of this inflation pressure that we are all talking about?

Well, that is a good question, Darren. Obviously, the interest rates are tend to be forecast to rise a Bank Canada rates probably mid next year, and that is going to affect the underlying interest rates that we pay on our revolving debts.

So, as part of our strategy is the debt repayment, and so, we are 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 is 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 would be quite small. Therefore the risk is - well it is certainly there, but it is not going to be that material to us.

Okay, good. And then maybe just a final question.

Dave, maybe I can ask you about, some of the future drilling inventory that we are looking at. We obviously drilled, started to drill on that new acquired property in Cecilia.

We have had some good results there, without giving too much away. Maybe you could speak a little bit about what plays we have started to delineate, maybe what interesting things we found and what is our inventory looking like up in that area?

Sure, Darren. The Cecilia acquisition is really turning out to be a big success story for us.

It is one of those instances where the upside is unfolding just as we had hoped and perhaps even better. The wells drilled table in the press release, maybe doesn’t tell the story, the table groups, wells by which gas plant they grow to.

But so Cecilia is located wonderfully smack dab in the midst of our infrastructure. So gas has a choice of separate plants to flow to.

So, we have actually drilled eight wells so far, six Notikewin, and two upper fill layers on what we term as the Cecilia lands. Plus we have two more not acute ones to finish up drilling here in Q4.

There is also three additional wells that were drilled farther itself in the Ansul area. Those lands are actually also linked to the Cecilia acquisition.

And next year we will have one rig dedicated pretty much entirely to Cecilia. And we hope to drill about 18 wells there in the budget of those are mostly Notikewin, but we plan to also test the liquids rich Dunvegan.

So that is really going to be a first for us in the greater Sundance area. Cecilia lands are far enough up north to with include some Dunvegan opportunity.

The actual inventory at Cecilia was estimated to be just shy of about a 100 wells, including 30 Notikewin and 50 Cardiums. But what we are seeing so far are giving hints that the depth of the Notikewin inventory may actually be underestimated.

And that is really important because the Notikewin, we have drilled so far turned out to be very prolific with several estimated to pay out less than a year. All-in-all, it is a great success story, and I’m sure you will be hearing more positive updates in the future.

Alright. Good stuff.

Well, that is a pretty good note maybe to end on. I don’t see any additional questions.

So, thanks everybody for listening in. And it has been an exciting quarter for us and really start to I think the next chapter of Peyto, which is looking very interesting.

We have got some pretty fantastic commodity prices driving some incredible returns, we have got lots of inventory. We have got the gear to get it done and the people as well.

So, we are pretty excited about the next 12-months. We are going to put our heads down and get that activity done and make sure that we can achieve those fantastic looking financial that we have.

And we will be back to you every quarter to update you on how that story? So we encourage everybody to listen in and check the website often and I will keep the monthly reports coming.

Thanks again for listening in this morning.