Peyto Exploration & Development Corp (OTCPK:PEYUF) Q4 2020 Earnings Conference Call March 4, 2021 11:00 AM ET
Darren Gee - President, CEO & Director
Kathy Turgeon - VP, Finance, CFO & Director
David Thomas - VP, Exploration
Todd Burdick - VP, Production
JP Lachance - VP, Engineering & COO
Conference Call Participants
Terry Kavanagh - Oakmont Capital
Aaron Bilkoski - TD Securities
Sean McPherson - Industrial Alliance Securities
Ladies and gentlemen, thank you for standing by, and welcome to the Peyto Exploration's Year-end 2020 Financial Results Conference Call. [Operator Instructions].
And now I'd like to introduce your host for today's program, Darren Gee, President and Chief Executive Officer. Please go ahead, sir.
Okay. Well, thanks, Jonathan, and good morning, ladies and gentlemen. Thanks to everyone for tuning in to Peyto's Fourth Quarter and Year-end 2020 Conference Call today.
Before I get started with remarks about the quarter, I would like to remind everybody that all statements made by the company during this call are subject to the forward-looking disclaimer and advisory set forth in the company's news release issued yesterday.
In the room with me today is most of the Peyto management team. We've got JP Lachance, our VP Engineering and Chief Operating Officer; Kathy Turgeon, our CFO; Dave Thomas, is our VP of Exploration, he's here; Todd Burdick, our VP of Production; and Lee Curran, our VP Drilling and Completions are also here. And our newest member, Derick Czember, our VP of Land, is here today. The only one missing is Scott Robinson, our VP, Business Development, but he'll be back in the office tomorrow.
Of course, we're all physically distanced in the boardroom and taking all the safety precautions with respect to COVID-19. But I can say we're also extremely relieved to see a significant improvement in Alberta's case count and hospitalizations as well as that of a lot of countries around the world. So hopefully, this means that COVID-19 pandemic is coming to an end.
Before I get started talking about the quarter too much, I do want to recognize the efforts of both our office and field personnel this past quarter and for all of 2020 for that matter. They continue to conduct operations with safety foremost in mind, particularly with COVID and all the other operational risks that exist on an ongoing basis out in the field.
We had a relatively busy year, and as usual, executed it in the safest possible manner. Obviously, with that many wells drilled, that many wells completed, tied in and all of the wells that we're operating every day, there's an enormous number of manhours logged and miles driven. So I'm happy to report that our safety record in 2020 was as good as it's ever been.
And so a big thank you then to all our people, both here in Calgary and out in the field for continuing to keep the gas flowing, so Albertans can keep the lights on and especially the heat on during this cold winter that we've had so far.
Okay. Fourth quarter results. Operationally, we continue to drill some of our very best wells in Q4, and we grew our production throughout the quarter from around 81,000 at the start of the quarter to 87,000 by the end. That's just under 0.5 Bcf of gas and close to 12,000 barrels per day of NGLs. So production is coming up nicely. And I have to say, we had success in several areas across our Deep Basin lands from down in Brazeau, all the way up to the northern edge of Sundance and from West Wildhay to the eastern part of Ansell. And in many different zones from Bluesky to Wilrich, Notikewin and Cardium.
So again, we enjoy both geographic and geologic diversity in our program, which I think reduces the risk and the dependency from well to well, so that we're always making the very best investment decision. We've got lots of time to make that decision with the most information about the previous drilling results. So that affords us an opportunity to reduce risk.
And quite frankly, those results were very good. The Cardium wells we drilled are producing more condensate natural gas liquids than the average beta Cardium wells. So that's holding our liquids yields up. And the gas productivities that we saw from some of our Notikewins in the quarter were just phenomenal. So some incredible well results.
And I suppose the best part is that those great well results keep getting cheaper and cheaper, especially relative to how much reservoir we're opening up and how fast we're drilling. I think that was very evident in our PDP F&D costs this year dropping over 30%. And really, I suppose our timing could not have been any better with the rally in both gas and oil prices that we saw in Q4. They were in prices quite back to what we had in Q4 2019, but they were a lot better than what we saw in the summertime. NYMEX was up 25% from Q3 and AECO was up 18% from Q3, and those continue to get better even into Q1.
So I think our production growth was really well timed, that growth in production and price drove cash flow up 55% from Q3 2020's $49 million to over $76 million in Q4, and we were finally back in the black with respect to earnings, both the - before the effect really of that impairment reversal, we had earnings in the fourth quarter of around $8.3 million. So that's good to see.
Sadly, though, that still meant we recorded a loss for the year, which really is the only blemish on our 22-year track record. That's one we'll endeavor to not repeat going forward.
So 2020, I think, was a good year. It was a good year from an ESG perspective. We reduced our emissions even more on a per BOE basis by capturing more vented and flared methane. We also did some R&D and tested out a new zero emissions controller that we're going to put to work in the field in 2021 on some new wellsite installations. So that emissions reductions trend, I think, will hopefully continue through 2021 and beyond. We're constantly working on that. Todd, can give us some more details later on that.
We also formed an ESG committee that is working on a more fulsome ESG report, that will be out later this year. John Rossall of our Board, is Chair of that committee. So we're continuing, obviously, to take our ESG responsibilities as seriously as we always have.
What else? Oh, the acquisitions. We mentioned in our reserves release, we negotiated 2 tuck-in acquisitions in the quarter that closed early in 2021. They're effective January 1, 2021. It's a very synergistic bit of land and infrastructure that I think plugs nicely on to the North side of Sundance, just under 3,000 barrels a day of - BOEs a day of production, all from sort of 10-year-old vertical wells that are extremely stable production, less than a 5% annual decline.
So quite a bit different than the new production that we're building. All of that for around $35 million. It's mostly gas, around 95% gas, but it also comes with a 30 million a day gas plant, that has about 15 million a day of room. So that's good. And a bunch of gathering lines that we can interconnect. They cross over our Sundance gathering system. And so that interconnects that whole system into our Oldman plants to the south.
Plus, of course, we see some exciting undeveloped opportunity on the lands that we purchased that we can develop with our latest design of horizontal wells. So I'm sure it won't be long before that plant is full, and we'll be filling up even some of the excess room at Oldman and Oldman North with locations on these lands.
I also assume everybody has read our reserves release a couple of weeks ago. If not, I highly encourage it. It's a very thorough analysis, rips apart our reserves, 8 ways from Sunday in far greater detail than anyone else in the industry. I think the biggest takeaway was that our F&D costs for PDP reserves developed in the year was the lowest in the last 18 years, close to $1 an Mcfe. That was our target going into the year, and we just about got there. So a good job by everyone.
We also continued our practice of converting reserves that have been previously booked as undeveloped for even less than we had forecast while getting greater volume. So that's important when it comes to looking at all future locations that we have on our books.
And I think the long-life nature of our reserves continue to shine through, particularly when you look at the difference between undiscounted values and discounted values, there's an incredible free option there for shareholders on those long-dated reserves. If you want to take a look at those numbers.
So that was pretty much it for the fourth quarter and 2020, mostly a pretty steady year of drilling operations, except for those couple tuck-in acquisitions at the end of the year and the volumes that came with those. As for '21, this year has already been even better than we expected with continued great well results. Obviously, some pretty exciting commodity prices in the month of February and even new opportunities coming our way. So the prices we got, particularly at Ventura, over the February long weekend was quite a nice bonus for the year.
And if we can put, I think, COVID in the rearview mirror, this might actually be a fine year ahead of us. I think we're well protected when it comes to the upcoming summer with our hedge book, and - particularly with respect to the AECO market. And I think we're looking forward to next winter and the potential lift that we're expecting to see on the back end of the natural gas price curve which we're pretty confident is going to happen. So that obviously has significant value on all the rest of our reserves that we're about to develop.
Anyway, that's probably it for the year and enough for the quarter. So Jonathan, why don't we take this opportunity through it open to questions from the listeners.
[Operator Instructions]. Our first question comes from the line of [indiscernible], he is a shareholder.
Yes. Darren, congratulations to you on a very good conclusion to a difficult year and a great start to the new year. My question relates to your ongoing hedging program. And I think it was last quarterly report, you mentioned how much the old hedges had cost versus ongoing pricing. And that was extremely helpful because it gives an idea of future economics because the picture as we roll forward improves, not just because of the current pricing, but also because of the rolling over of hedges that were made during more difficult periods.
So as we look forward, I had noticed that you had put on some basis hedges for next Q1 of '22 that were a very small hedge went on 5,000 at $0.63 versus your existing ones on Henry Hub, the basis trades that were at $1.41, and that's extremely favorable. If you could just comment on the forward hedging and the maturation of the older crop that were more difficult, I would appreciate that.
Yes. You bet, Jerry. That's an acute observation of how the market has definitely changed over the last few years. The high-cost basis deals that we had put in place were put in place mostly in 2018. And at that time, obviously, the AECO market was extremely disconnected from the rest of North America. Lack of access to storage had created some incredibly weak summer prices. And so we were looking at a forward curve there of about $1.50 AECO while NYMEX was at about $3.
So we didn't have a lot of confidence that the AECO market was ever going to get fixed. And so we started to diversify away from it, put basis deals in place to get us down to the U.S. market at many of the different hubs, mostly NYMEX because that was obviously the most liquid one. And those were pretty high cost. Like you say, we had some $1.35 basis for the winter, some $1.40 basis prices for the summer.
And then in sort of later in what was at the fall of '19, I guess it was, we saw the temporary service protocol approved by the CER and the AECO market quickly reconnected with the rest of North America. And so for most of 2020, obviously, we saw a basis that was more typical. It slowly tightened up, and we saw prices anywhere from sort of, I would say, $0.75 to $1 per basis in there, which was quite a bit better.
And of course, so we're having to live with the basis we put in place that were higher cost than that. And so the market diversification cost, as we illustrate, is pretty high at about $1 an Mcf. But as those roll off, as you noted, our realized pricing is going to increase quite a bit. We're continuing to diversify at what the current cost is, which is, as you point out, a lot more attractive, something in the $0.65 range or $0.75 range is even less than the cost of pipe or pipe contracts. So that's attractive to us and gives us the diversification away from the AECO market that is still, I think, subject potentially to some volatility here as we move forward.
So we like that, particularly just in the next few years until I think we start to see LNG Canada's project come on and a little more tension in the Western Canadian market from a demand perspective. We've got obviously pull to Eastern Canada and pull down into the states for exports, but to have pull on the West Coast as well would be really nice. I think that would tighten up that AECO market quite a bit.
So these short-term basis deals to us look attractive. So we'll continue to layer them in as we always do. We try to be sort of mechanical with not only the diversification pieces that we're putting in place, but also with the hedges that we then lay on top of that. So we put the basis deals in place that gives us the synthetic transport to those markets. And then we can hedge those markets and fix those prices, which we've also been doing.
Obviously, the spot price is pretty much right across North America are at prices today that are acceptable to us. They work well with our economics. And so we're taking them off the table, and we're building back the hedge book that we used to enjoy prior to 2018. We had a very strong hedge book then. It was a very mechanical hedging strategy that, that built out a profile of hedges into the future, and we'd like to get back on that train and continue that practice. I think that served shareholders very well, and it was very helpful for us to plan appropriate capital programs and appropriate dividends and balance sheet management. So we're eager to get back there.
I think we're close to there - the target levels that we're looking for in the next few seasons, but a little further out. We need to add some hedges, and we're optimistic that the back end of that curve is going to come up. And we're going to be able to take those prices off the table as well at what looks like attractive gas prices for us. Hopefully, that answers your question.
Our next question comes from the line of Terry Kavanagh from Oakmont Capital.
I also echo the comments about congratulations for doing a great job last year. I wouldn't mind if you could spend a little more time, it's really a follow-on to the first question. With respect to these market diversification costs, you - really, with respect to the timing of the roll-off of them, like - I know in the third quarter, I think you guys said they'd be significantly reduced over time. I think on the call, with respect to the third quarter, I think you referred to the coming two quarters, if I'm not mistaken, in the outlook today, it describes the diminishing gas market costs with respect to the '21 outlook.
But in the paragraph under marketing, it talks about these things decreasing over the next two years. I'm really more - I'm interested in when we'll get back to some kind of normalcy? And the timing of it, is it two quarters? Is it two years? Is it - are we going to see most of it this year? Just a little more color on maybe even what they - on just how we'll get back to normal, if that makes any sense?
No. It totally does, Terry, and I appreciate. It's obviously much more difficult for investors to look through now because we've got so much diversity in our marketing. We had to obviously put that in place. We're not just as simple as selling gas at AECO anymore. But you're right, the - it's a bit tricky to try and predict because, of course, the AECO prices trade somewhat independently of NYMEX. And that's that basis differential between those 2 markets that sort of floats around. And so at any point in time, when we talk about what's going to be the market diversification cost for that next quarter, it's based on the future strip for both of those commodities as we're looking forward. And so it moves around a little bit.
But I think we're obviously seeing some very strong pricing in Q1. And I think our market diversification cost in Q1 won't be as high as they've historically been. They will look pretty good. And then as we enter into summer, there's some softer prices in both NYMEX and AECO. And we'll see that market diversification cost go up a little bit as we see some softening in the summer NYMEX price. Unless, of course, we see strength in the NYMEX relative to weaker AECO prices, which we could possibly see because the TSP was not extended into the summer of '21 for the Alberta market. So we could see some weakness in volatility there. And storage numbers in the U.S. look like they're headed pretty low.
And so if the refill isn't as aggressive as you might predict, then we could see some strength in the NYMEX, in which case, our diversification costs will fall for the next summer, a couple quarters. Right now, we're forecasting them to be the higher parts of the year.
And then really, with Q4 of '21, that's when everything starts to fall away, these old basis deals, more and more of them start to fall away, we get a much tighter price. And then entering into 2020, our prediction for the year in '22 is that we would get very close to the current AECO realized price or the current delta really between NYMEX and AECO. So effectively market diversification costs in '22 we're forecasting right now would be very little, if anything, at all.
And then actually into 2023, we would actually start to benefit from a lot of the diversification, getting actual prices realized that are superior to that of what the AECO forward strip shows. So it's all this sort of layering and smoothing approach, obviously, to the diversification and then hedging on top of that. But realized prices look like they'll be getting back to normal, as you say, by sort of the fourth quarter of '21 and into all of '22. And then we look to do a better job than just the local AECO market beyond '22 into '23 and after that. So hopefully, that helps a little bit. It's hard to pin it down, of course, because it's moving every day with the forward curves.
Our next question comes from the line of Aaron Bilkoski from TD Securities.
So we're coming up here on NGL recontracting season. How should we think about NGL differentials and realizations in 2021 versus last year?
Yes. From what we're seeing in the market, there is still strong storage of propane and butane, particularly, across North America, high levels of storage relative to the 5-year average as you've probably seen as well. They're coming down, of course. I mean the; cold winter helped pull those down a bit. And we'll see what other demands there are, particularly export opportunities. Propane was being exported aggressively here through Q1. Obviously, the cold weather in Europe and other places, put big demand on any hydrocarbons really that could be moved to those cold winter weather events that were happening.
So we've seen particularly strong propane prices on the spot, and in the short term, those weaken as we obviously get into the summer months, but still look not too bad. So propane prices actually have reversed quite a bit. They weren't all that great in 2020, and we've definitely seen them strengthen a lot lately.
Butane prices, on the other hand, obviously, butane is used principally in Edmonton as a feedstock for the refineries to make gasoline. Obviously, gasoline demands are not great because of COVID, not a lot of driving, not a lot of flying. So butane stocks remain relatively high. Differential - butane is typically traded on a differential to WTI or light oil price, for instance. And I would say under normal situations, it should trade pretty close to 50% of light oil.
Right now, I think indications for the recontracting year are butane somewhere around the sort of high 30s to 40%, maybe. I think last year, our average term deals were somewhere in the 46% range. So we might be slightly under that as renewals for this year. But those 2 are changing quite dramatically. The storage levels of butane are coming down really fast as well.
So if I had to guess, I would say that the blend of propane and butane pricing realizations might be similar to 2020, what we see in 2021, maybe a little bit weaker butane and a little bit stronger propane. So all in all, maybe we see something similar to slightly better, but not a ton better, even though we've seen oil prices obviously recover a lot.
Those two products are still sort of - we're still working through a bit of a storage glut on them as well. So maybe throughout the year, we'll see spot prices improve. And then by 2022, we might actually see some really exciting looking differentials and prices for those products.
[Operator Instructions]. Our next question comes from the line of Sean McPherson from Industrial Alliance.
I was hoping you could tell us roughly what percentage of your production is exposed to each sales side?
Percentage of production, I'm going to have to take a guess, Sean. We've got that one slide on our website, and in the presentation, we updated all the time, of course. It depends really on the season that we're looking at. But the AECO exposure is probably somewhere around maybe a little under 1/3. And then the other 2/3 is really distributed across mostly NYMEX influenced prices. We've got a fair chunk at the Henry Hub. And then we've got probably about, again, another 2/3 at the Henry Hub. And then we've got the remaining 1/3, I think, equally split amongst smaller hubs like Malin, Ventura, Emerson, until we get into sort of the fall of '21 and then it redistributes a little bit.
We've got far less really exposed to both AECO and NYMEX and a lot more becoming exposed to sort of the dawn area. We've got a lot of Emerson service that kicks in, in November of '21. It's good 1-year renewable, lower-priced service that gives us a superior price. Emerson is not really a hub that you can trade a lot of gas at, but it does get us halfway down the mainline towards Dawn and then it branches out from Emerson goes down the Great Lake system, we get more into the Chicago market with that way or we can go over-the-top of the Great Lakes and into Dawn and to sort of Eastern Canadian market and beyond that into the Northeastern U.S. market.
So we think that's going to be a strong market going forward. So it's really changing and evolving. It's - I mean, those percentages will be similar for, I guess, really through the summer of '21, but then as of the fall of '21, they start to change a little bit, and we get a little more exposure to sort of Eastern Canada and Northeastern U.S. and a little less exposure to NYMEX.
But we're cautious about the AECO market. I know it's strong right now, but we're still careful in terms of our exposure there. We're not overly confident that the storage system is working effectively on the NGTL, sort of the western Canadian gathering system doesn't seem to have full access to storage yet in a way that makes us really comfortable with it. So we're cautious with respect to that going forward for the next little while anyway.
Our next question comes from the line of Nathan Schwartz [ph], a private investor.
Yes. First, let me thank you and your team for everything you do for the shareholders. I feel fortunate to have you guys managing some of my money. My 2 questions are related. First is the bank borrowing and the penalty interest rate, when do you anticipate that falling away? And the related question is, how are you thinking about the dividends? And when might you anticipate an increase in the dividends?
Sure. Good questions, Nathan. Maybe actually, I shall just pass over to Kathy Turgeon, our CFO, to talk a little bit about the banking situation.
Okay. Yes, thanks for the question. As you could see in our Q3, Q4, our interest rates are significantly higher than historically they have been, and that is due to our debt-to-EBITDA stamping fee costs. So as we see those coming down, obviously, we're going to normalize back. And we're seeing that in Q1. Definitely by Q2 of 2021 will be back well below 4x, which will bring us down in the actual costs on our interest. It takes a little while for that to flow through on the way stamping fees work.
But by the end of 2021, we should see a more normalized interest cost that would be on a per Mcfe basis, more in the mid-20s as opposed to $0.38 per Mcfe that we're seeing right now. And from an interest rate point of view, we should be seeing like 100 to 150 bps less. We also have our bank deal coming up for renewal. Our term date is October 2022. So we'll be looking to renew that this summer. And obviously, pricing will be part of our discussion.
And then, Nathan, your second question with respect to dividends. Obviously, we're looking closely at our cash uses, cash inflows, cash outflows, wanting to ensure our balance sheet stays front of mind as well. We're looking at - right now, we're forecasting quite a bit of free cash flow over and above our capital requirements to get us really back up to that 100,000 a day level.
We think we can exit the year somewhere between 95,000 to 100,000 barrels a day, close to that 100,000 level, if we get the efficiencies we're looking for. That's with about $350 million or a little less of total capital for the year. That, like I say, is far less than the cash flow we're forecasting with commodity prices we're looking at today. So that gives us a bunch of free cash flow to consider what are we going to do with that.
I think, obviously, initially, we just put that on the bank line. But also looking at how the earnings are evolving and earnings are strengthening. Our forecast of earnings for the year is coming up nicely. We're getting back to the type of profit margins that we used to enjoy, which we want to feel confident about.
And so I think as we get into the back half of this year, obviously, the Board will start to think about dividends again more seriously. And weigh that against the cost of capital for the company and what the 2022 year starts to look like. I think it will really be sort of fourth quarter '21, 2022 decision. And there's still a lot of backwardation in the commodity tape right now, both oil and gas prices fall away pretty hard as we look out into '22 and '23.
And so that - we expect that to change. We expect the back end of that curve to come up. And I think as it does, obviously, we'll gain a lot more confidence in the total amount of free cash flow that we're going to be throwing off in '22 and '23. I think we want to probably have both a combined use for that free cash flow, both in terms of balance sheet strengthening, reducing our debt as well as dividend rewards to shareholders.
Like I say, I think it's really a sort of the back half '21 into '22 type of discussion at the Board level, and we'll see what the future looks like when we get to that point. I think we want to see really the solidification of commodity price strip into the '22 and '23 years. Right now, it's - like I say, it looks a bit odd to us to see such severe backwardation in the forward curve. And so we'd want to see some of that coming out of there, so we can lock that away and secure the pricing that we need to generate a lot of that free cash flow.
[Operator Instructions]. And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Darren Gee, President and Chief Executive Officer, for any further remarks.
Okay. Well, that was good. Lots of good inbound questions. I think we obviously have some big plans for 2021. It's going to be a busy year. We did have some inbound e-mail then over the last week or so, questions about this new acquisition that we've recently picked up. And so maybe if I can take a moment and just - I wanted to ask Todd Burdick, our VP Production, a little bit about the integration of those assets.
Obviously, we picked those up just after the New Year here, closed those deals, and we're still integrating a lot of those. Sometimes acquisition integration is a difficult process if the acquisitions are large. But I don't think this one was - or is expected to be overly difficult. Todd, maybe if you could elaborate a little bit on how that's going and maybe some of the upside that we're seeing in that asset?
Yes, sure. So things have gone really smoothly so far. We kind of took over operatorship at the beginning of February. I got to give kudos to Scott and his team for sort of facilitating a transition. And along with the previous operator as well, they've made it a lot easier for us and so that we can make a transition really quickly. But last week, we finished the integration of the SCADA system for both plant and wells into Peyto system. So now we have real-time visibility on all of the wells and all of the plants, which is nice to see, so we can start working on optimization. So we've been looking at well optimization opportunities. They've been evaluated. In this week, we've been busy in the field, implementing changes that should result in seeing more gas at the plant gate. So we're excited about that.
We'll also be reactivating and redirecting some wells that had flowed to third parties, but were shut-in due to low gas prices and high fees. So that redirection, which is really going to be done at very little cost will bring those wells into the Cecilia gathering system as well. We're just waiting on the license transfer piece with the AER before we can do some of that work.
As far as pipeline infrastructure, we've evaluated any constraints. And we're making changes to operating strategies. Those will be implemented where applicable. Essentially, without going into too much detail, the result will be more consistent flow in the gas gathering system unless liquid hold up so that the wells will produce and perform better. That was one of the things we spent a lot of time on looking at.
We've already - we've had one 6-inch connection to the Oldman system in place for years with the original operator and developer of the assets. The - a portion of that pipe had been decommissioned. So we're going to recommission that line. Again, once the license transfer happens, we'll be able to do that. So then we'll have a connection with part of the Cecilia infrastructure into the Oldman and the Oldman North infrastructure.
And then as well, we've been looking at little sort of short tie-in opportunities. It won't cost much capital. But will give us some flexibility to even get gas tied in and into the Wildhay area. So we'll move on those sort of adds the development dictates, I think, for most part, but we've identified a lot of opportunities. And that will give us, obviously, flexibility to swing gas around multiple plants, like we have elsewhere in the greater Sundance area.
And then finally, I think we've been - we're going to leverage our relationships with some of our key vendors out there. So we'll get those vendors working in the Cecilia area and with the long-standing relationships and pricing that we see with them will not only get reliable service, but we'll also see an impact on an operating cost reduction basis. So a lot of work has been happening, and we're excited to keep pushing this forward.
No. That sounds really good. Thanks, Todd. Dave, I know you were eager to get your hands on these lands. There were some interesting opportunities there. Without telling our competitors too much, did you want to elaborate on some of the things we're excited about there?
Sure. Darren, maybe just a bit. The opportunities we're most excited about are in the Spirit River and the Dunvegan. We've got 3D Seismic over pretty much all of the new lands. And we have 8 Notikewin and 2 Wilrich locations already teed up to drill later this year. We're especially keen on Notikewins because they've been a pretty big part of this year's success, and we see them as helping us continue that momentum into 2021 and 2022. In 2023, we'll follow those wells up with more Notikewins plus some flares. And we're keen to target the Dunvegan, which is present over the northern part of the lands.
There's also a good amount of Cardium opportunity, which we're very familiar with. But ultimately, we see the potential for over 100 locations on the 54 sections. And I'd just like to complement the BD team. They worked very hard to make this happen, and we're really keen to start drilling.
Sounds really exciting. Scott's, not here. JP, I don't know if you want to stand in for him. But obviously, the industry is talking a lot these days about M&A. We haven't typically been a company that does a lot of M&A. We tend to do a lot of organic development on our own, but we've had a few little complementary deals that we've tucked-in here there and maybe smaller stuff. What's the strategy going forward? Is it big stuff or small stuff? What are you thinking?
I think like you said, we've always had great success with the sort of bread-and-butter kind of tuck-in acquisitions around our assets. We do that, be it farm-ins or poolings or swaps or whatever the case may be, our land department and the BD Group are both busy doing that. So it's tough for us. When we add production at 9,000 a flowing BOE. It's hard for us to sort of look at major acquisitions in some sense because the value expectation on the other side is usually quite high as well, and for us to get that, we want to make a profit here.
So I mean, there's going to be these opportunities like we just discovered. And especially when they come with infrastructure, we'll continue to look at these. There are other operators out there and there are other lands out there similar to this, that we'll continue to pursue, that is the strategy. I mean, I think with our cost structure and acumen in that regard, we will certainly have more of these opportunities available to us. And that's a real strategy to continue.
Okay. Great. I think that's probably it for the quarter and for the year for us. We're obviously excited about '21. And already, we've seen some interesting developments with commodity prices. And obviously, we're continuing to perform here. We've got an active year plans, a bigger capital program, quite a bit bigger than 2020. So we're going to be busy. But that's not all that we can do. Obviously, we're looking to do even more than that.
So we're going to keep working on some of those future opportunities, and we'll report back to you guys on how that's coming. But obviously, the strategy at Peyto has never changed. We're all about generating the maximum return we can on every dollar that we can put to work for shareholders. So we're going to continue that vein, and keep pushing to lower costs and improve profitability as we go.
And so we'll be back to you reporting on the first quarter, how that went and how we're headed into breakup here in May, I guess. So thanks for listening in, and we'll talk to you then.
Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.