Freehold Royalties Ltd. (FRU) Earnings Call Transcript & Summary

Okay, everyone. I think we'll get going right on time here at 10:00. So thanks, everyone, for coming out today. And there's been a lot of work has gone into putting this asset book together. And it's been a while since we shared an update on our business, and we're really excited about the North American asset base that we put together. So first off, I'd like to make a few introductions. So I'll start with myself, Dave Spyker, President and CEO, an engineer by training in the Oil and Gas business for 37 years and a self-professed details junkie. My passion is in building Freehold into a North American royalty company with the right assets in the right places. And I think over my 37-year career, I've seen that the best reservoirs continue to overdeliver, and we've been very conscious about putting our land position into those best reservoirs. Next up is Dave Hendry. So Dave is our Chief Financial Officer. Dave has been in the business for 35 years, and we rely on his expertise to keep the balance sheet strong, ensure that we're managing our business risks appropriately and to ensure we are maximizing our royalty value through audit and compliance. Rob King, our Chief Operating Officer, is responsible for leading the broader framework of business growth and strategic positioning for Freehold. He's also in charge of telling our story. So Rob, along with our new IR Manager, Todd McBride. Todd, where are you? There's back row over there. And a whole lot of our technical and land professionals have been instrumental in bringing Investor Day to you today. Next up, Lisa Farstad. Where is Lisa? Over here, okay. So Lisa is our VP of Corporate Development, and she manages all things people related, but also leads the team that is developing and implementing software that allows us to have all of our data at our fingertips and really drive the value in our asset base. Ian Hantke, over there, VP Diversified Royalties. So Ian is in charge of exploring for opportunities to broaden our royalty base beyond traditional oil and gas. Most recently, he has been leading our [potash] royalty acquisition work and is focused on leasing our extensive mineral rights in Canada that are prospective for helium and lithium as examples. And rounding out the executive team is Susan Nagy, our VP, Business Development. So Susan leads a team of [Indiscernible], engineering and geology professionals in leasing as well as evaluating opportunities that we see across North America. Her team looks at a tremendous amount of opportunities as our quality bar is very high. Before I introduce the directors that are here, we have 2 of our key technical leaders in-house. John Wu. Where's John? In the back, is one of our lead engineers and is the architect of our 2024 asset book that you have on the table in front of you. That document underpins the multi-decades of inventory that we're going to talk about today. Tom Plumridge is a geologist who leads our U.S. acquisitions team and has been instrumental in helping us to find the sweet spots of the Permian Basin, for example. We have 4 Board members in attendance today: Marvin Romanow, Chair of the Board; Doug Kay, Chair of the Governance, Nominating and Comp Committee; Kim Lynch Proctor, our newest Director who joined the Board in May of this year; and Aidan Walsh, Chair of the Reserves Committee. So presenting today will be myself, Dave Hendry and Rob King. And with that, now I've got all the names behind us. I don't need notes. So I'm good to go. Okay. So I just wanted to talk initially about what is our plan? What is Freehold strategy? It is in the front of our AIF. It's in the front of our annual report. Our goal is to create value by increasing our exposure to the best plays in North America under the best operators and drive the development on those lands we acquire through our leasing and royalty optimization. We have a comprehensive audit and compliance program that ensures we're enhancing value. And we like to run a conservative balance sheet at debt to much less than 1.5 turns. And to return value to shareholders, we're targeting a dividend payout of about 60%, and that's supportive down to the low 50s on a WTI price. And so what we've done since we last had our Investor Day? We've done an expansion to the U.S., adding 1.1 million acres focused in the resource-rich Permian and Eagle Ford basins under investment-grade operators. We put together a 430,000-acre Clearwater position, which everyone in this room knows, it's one of the exciting plays that's in Canada right now. We've got rid of all the working assets out of the portfolio, really focusing on long-duration, high-margin royalty business. And we've increased our oil weighting. It's hard to do. It's hard to move that up in Western Canada and the U.S., but we've moved that up from 47% historically to 51%. The focus on our business of just really driving leasing optimization, audit, that adds about 1,300 barrels a day in Canada. So it's a big number. And so with that UF investment, we get about a 19% average return on the capital that we've deployed. And our payout ratio targeting 60%, it's been about 59% on average over the last 3.5 years. So we look at that. We've added value through the A&D work compared to what we deployed for capital compared to year-end net asset value. We've added $56 million in the last few years on audit and compliance. And we've -- in addition to paying down our debt, we've returned 62% to shareholders as dividends in the last 12 months. So that consistent production growth per share, we got a 4% compounded CAGR on oil growth from '19 to 2024. Our production on a per share basis has grown 15%, 8% CAGR on FFO per share. And on the shareholder returns, where we're delivering better than the TSX Energy Index and on par with the S&P. So we think that we've been delivering the value that our shareholders are looking for. So just as a reminder, where -- what are we? So we're North America. We're in all the core oil basins in North America, down in -- in the U.S., we're down in Texas primarily, North Dakota and then up into the oily side of Alberta and Saskatchewan and then a little bit more in the gassy area, Deep Basin and Cardium. We have 360 royalty payers that we collect money from and 6 million acres in Canada, over 1 million acres in the U.S. Production at 14,850 year-to-date is -- from an oil perspective, it's about 52%, but that drives over 80% of our revenue. So one of the things as we position our business and we talk about resilient cash flow margins, 2 things that are driving us being best-in-class when we look at our peers. First off is the oil weighting. And secondly is the U.S. production with 1/3 of our U.S. production driving a 19% premium on oil pricing. It tends to be a little bit oilier. And so on an overall BOE basis, we benefit that as a 43% premium to the pricing that we realized in Canada. So that really drives a high-value barrel on our portfolio. And one of the other things that we've been very conscious about is just moving our business under higher-quality payers. And so over the last 4 years, that's moved significantly. On our payers, almost half of them have a market cap greater than $10 billion. Half of them have production greater than 100,000 BOE a day. Most of them have got a really strong balance sheet with less than 1x net debt to EBITDA. 45% are investment-grade payers and about 25% are private. And so when you look at the 30 payers that make up 80-plus percent of our revenue, big payers in ConocoPhillips, Exxon, CNQ, Whitecap, Diamondback. I mean, these are the quality names that they're not waking up in the morning trying to decide whether they should drill a well looking at WTI oil price. They have long-term development plans, and that's what we want to make sure that we're part of that long-term strategy. So what do we get excited about? We get excited about the U.S. resource advantage. And this can be a little bit hard to get your head around, but in Midland Basin, there's 1,100 meters plus of reservoir pay. And we look at this, that these are all the benches and the drilling density that operators are drilling in the Midland. And so when you look at that, you go, well, there's not much room left to put all these wells in. But when you think of wellbores about the size of a dessert plate, you could stack all these and they'd be about as high as me and another half. And this is 1,000 meters of pay. So you just get a perspective of how much resource is there. The potential, we just don't -- it's not scalable anywhere else in North America. What we like about it is we can buy. We continue to chip away at buying mineral title in these areas under the DSUs and under the operators we want. We get that premium pricing. And we're going to talk a little bit about some of the consolidation work as our assets consolidate under Midland specialists, the biggest and the best that continue to drive improvements in well performance. In Canada, we're super excited about multilateral open hole multi-let adoption. It primarily started in the Clearwater, migrated over to the Mannville Heavy Oil, where we have just under 1 million acres of exposure between those 2 plays. But we're also seeing it showing up in Southeast Saskatchewan and other areas. And so we see that as a significant opportunity on the Canadian portfolio. Back to down South, just success in expanding these development benches. We'll get into that a little bit more, but the Permian has been on production since 1921. And those initial benches that were being developed, if you look at how they've grown over the last 5 years, they've grown about 115,000 barrels a day. This next generation, what we call the second-generation benches is what's been started drilling since about 2020, and that's contributing about 450,000 barrels a day. To put that into perspective, over the same time period, the Clearwater play, which we quite like in Canada, that's grown to about 150,000 barrels a day. So a little better than these first-gen benches, but nowhere near what that second-gen benches are contributing. And lastly, emerging benches, we're going to talk about that. There's still a lot of pay that guys are just starting to get at and seeing more and more capital allocated to that. We like to say the 100 billion reasons to love the Permian. If you look at some of the M&A work that's happened over the past 1.5 years with Exxon buying Pioneer to consolidate into the Midland Basin. Conoco buying Marathon to consolidate into Midland and Eagle Ford, Diamondback buying Endeavor to further build their position in the Midland. We can see on this map here, that's these guys' acreage position. And when we talk about -- this is the core of Midland, what we like to call the jelly. It's the best part of the doughnut. And that's where these big operators are consolidating into because they see the same opportunity set that we see, and we started buying on that 4 years ago. So I'm going to -- before I turn it over to Rob, just what we're really excited about is just the decades of inventory that we have, both in Canada and the U.S. We've got 30 years plus of inventory across a broad range of plays, generally oil-weighted plays and plays that are in high-quality areas. So super excited about that. So I'll turn that over to Rob to just talk a little bit about the asset book, and then I'll dig into some more details.

So it's been a number of years since we've provided a comprehensive review of our assets beyond what's booked in our reserves. The asset book really builds on our book PDP reserves of about $1.3 billion. That's across about 33,000 wells, 80% in Canada, 20% in the U.S. The asset book has about 36,500 gross prospective locations. That's that 30, 40 years of inventory that Dave talked about across our Canadian and U.S. lands. That's about $14 billion of undiscounted value. But probably the part that gets us the most excited is on that future optionality. This is the potential that's on our lands that hasn't been discovered yet, hasn't been valued yet. The reality is we own mineral title forever, and we have long-duration assets with our GOR. So there's significant growth that we continue to expect beyond what's in our booked reserves as well as what's beyond in the -- what's laid out in the asset book. A bit of background on how we made the sausage. We mapped our prospective fairway in the light green on this map, starting with the wells that have been producing for the last 10 years. We then work closely with our geologists to draw buffer around those wells. And then we layer on top our land in blue. And this is a bit of an example of what that future optionality is. You can see there's some freehold blue land that's not in that -- in the green fairway there. The reality is no inventory has been ascribed to about 10% of our 6.1 million acres in Canada. So it's just sort of, again, another example of that sort of broader future optionality that we know is there, and we're going to continue to see some upside beyond what we've looked at. We take a view on well density that varies across our U.S. and Canadian plays. We've taken a 3-year average type curve and inventory is normalized on an average about a 1-mile length in Canada and in the Midland, about 2 miles and in the Eagle Ford, about 1.5 miles to come up with our inventory perspective. We use constant pricing assumptions to get us that undiscounted value of about $15 billion. Why do we put the asset book together? I think the key reason why we did it was to validate and demonstrate the multi-decade value propositions on our lands. This to us is, we're going to come out in -- with our Q4 results in March with our perspectives on what 2025 will look like. The asset book here is to really frame how we see the next 3, 5, 30 years on our assets. But it's not the only reason why we put the asset book together. We've actually found it's a pretty useful tool in a few other constructs. It's a great tool for our U.S. and Canadian business development teams as they look at opportunities and have conversations with operators on our lands about optimization and looking at additional opportunities. It's valuable additional disclosure document for our stakeholders that helps support our financials, our AIF, our investor presentations. The reality is we have a very broad and expansive portfolio across 8 states, 5 provinces. It takes more explaining to understand what our value proposition is. And this will be regularly updated. It's something that we'll be able to demonstrate how our assets are evolving and improving over time. With our Canadian portfolio, about $10 billion of undiscounted value across 18,000 gross locations, we're really concentrated in 4 plays, 4 oil-weighted plays, Southeast Saskatchewan, Mannville Heavy, Clearwater and Viking. Those 4 contribute more than 50% of both inventory and value. And based on a 3-year historical drilling average across our Canadian lands, that does imply that 40 years of inventory that Dave talked about. That's put it in a yearly context. If you look at our average type curve, that would be about 2,500 barrels a day net to freehold. That would be -- could be added each and every year. On the U.S. side, we have about $5 billion of undiscounted value across 18,500 locations. Again, we're quite concentrated in Midland, with about 50% of the value and Eagle Ford, about 40% of the value. Now one thing just to point out, you'll see that it's a relatively similar value between Midland and Eagle Ford, but Midland has 3.5x the number of gross locations, and that really comes back to a net royalty interest. Our average net royalty interest in the Midland is 0.3%. Decimals matter in this business. And our average royalty interest in the Eagle Ford is 1.3%. So that sort of factors into how on a net basis, the Eagle Ford kind of punches above its weight. Again, based on that same 3-year historical drilling average, it implies 30 years of inventory in the U.S. or about 2,000 barrels a day net to freehold of oil-weighted production that we could add each and every year from our inventory. I mentioned 40 years in Canada, 30 years in the U.S. We have more running room in plays like heavy oil and like Southeast Saskatchewan and Canada. And on the U.S. side, Midland has more running room than Eagle Ford, and that really kind of feeds into that stack potential that Dave talked about and is going to talk more about momentarily. Lastly, I just wanted to point out a few key differences between Canada and the U.S. Canada has 6x the acreage. We have 6.1 million acres in the U.S., 1.1 million acres -- 6.1 million in Canada, 1.1 million in the U.S., but we have a similar number of gross locations. Again, back to that stacked nature of Permian. We mentioned the differences in NRI in Eagle Ford and Midland. It's the same issue that we have in Canada and the U.S. as well. Our average NRI in Canada is 5%. Our average NRI in the U.S. is 0.5%. So that's what leads to that 90-10 split on net locations between Canada and the U.S. And so that -- you multiply those together, that's how we have $10 billion of value in Canada and $5 billion of value in the U.S. despite having a similar number of gross locations. I would say on average, our U.S. net location is more valuable than our Canadian net location. And that's a combination of higher productivity, higher reserve recovery. And as Dave talked about, we're more oil weighted and we get better pricing given the Gulf Coast proximity. So with that, I'm now going to turn it over to Dave to profile our U.S. and Canadian assets.

Thanks, Rob. Okay. So U.S., just a quick refresher here. So production in the U.S. is about 62% oil weighted and drives 90-plus percent of our revenue basin-wide. You kind of split Eagle Ford, about 2,400 barrels a day. Midland is 2,050 barrels a day. Delaware on this west side of the Permian is a little bit smaller at 370 and then kind of scattered around some of the other areas will be about 600 BOE a day. So what is the U.S. done for our business, if we do a little look back over the last few years. We've seen that there's a lot of transaction opportunities. We can take advantage of that well-supplied U.S. minerals market, do accretive deals. We get premium pricing. We've talked about that, and that generates a superior return on the capital employed, and we compare that to our royalty peers. From an operations perspective, how do we see it? We see our top drillers over the last 1.5 years. Your Conoco has been the biggest at 42%. And that includes back when it was -- Marathon was a very active driller. So that will be a lot of drilling activity in Eagle Ford. And then as we move along into the Permian, we've got Exxon Surge as a private, high peak EOG. And as we built our portfolio, the gray lines here are the permits that we're seeing on a quarter-over-quarter basis. And the green lines are what we're seeing for spuds. One thing about the U.S. is that we don't get as crisp data on production as we get in Canada. By the third week of November, we can tell you exactly what wells came on in October in Canada and what the production was. In the U.S., that's about 3 months behind. And so that's why we've got this kind of a bit of a gray bar here is that those tallies are still coming in to exactly what those numbers are. But we look forward from a spud, you see that gray bar, what we see typically on the licensing or permits, it's about a 12-month lag before those wells get turned in line or put on production. Spuds, it's somewhere in that kind of 6 to 9 months range. So it is a bit of a lag from what we see in Canada. So good activity here is a bit of a precursor for what we're seeing into 2025. Where the primary activity is you'll hear a lot about the Midland, Martin, Howard County. And that's where our land position has been primarily built. And so the hotter the colors, the bigger the activity. And you can see that 60% of the basin activity is concentrated in those areas, and that's where we've been intentionally building our position. One of the questions that we get a fair bit is on Diamondback. Diamondback being one of the bigger operators now in our portfolio, and they've got a drop-down royalty vehicle with a company called Viper, which also trades publicly. And are they going to preferentially develop those Viper royalty lands on that drop-down company, and we share our royalty lands with Viper. So about 2/3 of the inventory we see on Diamondback are on Viper lands, which we also have a royalty interest. So we feel that we're very aligned with that, and we're going to capture that Diamondback drilling activity because of that alignment. So how does it look since day 1? I would say -- I would characterize it 2 ways. The ability to generate cash flow from these assets has far exceeded our initial expectations. The reservoir benches that we can now underwrite value to and that we see operators developing far exceeded our expectations. Probably where we got a little bit ahead of ourselves, if I'm being honest, is that when we did our first major deal in late 2020, closed it in 2021, we're really basing our development pace on kind of pre-COVID drilling activity levels. And what we saw post-COVID across North America was kind of drop the grow [Indiscernible] to grow concept and really focus much more on shareholder returns. And so a much more measured pace of drilling activity, a much more measured pace of growth, ensuring that returns are sent back to shareholders through dividends and buybacks, et cetera. So from that perspective, I would say the volume deliverability didn't meet our initial expectations, and I imagine most of yours as well. But the quality of the asset has far exceeded those expectations. So to date, we've invested $685 million. We've got $409 million back in revenue right now. It's doing about 5,400 barrels a day of oil-weighted production. I would just put some quotes in here. We're not the only ones that are excited about this. You talk about Diamondback, there 12 years of inventory at sub-$40. Remember, most of our inventory is under Diamondback and Exxon. Exxon is going to come out with their budget next week. They had a pretty good interview that was posted on Hart Energy this morning about the excitement that they have and the rationale behind looking across the world of where to put money and invested $60 billion into Midland. And ConocoPhillips just completing their Marathon acquisition and how they see the ability to grow that business. So another big difference is that unlike Canada, like Texas, it's all for sale. And so what we show here is in this kind of salmony color, the big conventional -- unconventional resource plays in Canada, the Montney and the Duvernay. The pinky color is Crown lands. The green color is private mineral rights or mineral title. And you can see that these plays are dominated by Crown land. If you go down south into Texas, it's the exact opposite where basins like the Midland, Eagle Ford, Delaware, where we've been actively building our positions, it's -- we can go buy those mineral rights. And so we can selectively purchase them in the DSUs we want under the operators that we want. And that's what we see as a huge advantage in how we build that U.S. portfolio. The other thing that what we're learning is that both sides of the border, we both speak English, but there's a difference between American and Canadian and just trying to get people calibrated on that language. We're all in Canada. We're so familiar with the Montney. We're familiar with the Charlie Lake. We're familiar with the Duvernay and all the exciting opportunities that are going on in there. And sometimes we forget just how good that the Permian is. And if we look at Midland for us, these are all these different benches that we're going to talk about a little bit. In the first 24 months, those wells on average are -- assuming somewhere in that 200,000 to 220,000 barrels of oil and condensate. If that stacks up against any repeatable resource play in Western Canada, and if we go back to this slide, remember, it's all available. We can buy that. So how we've been defining this and some of this is just to help us with a little bit of a time slice here, but the initial benches that were developed in Midland were these blue ones, the Wolfcamp A, B and Lower Spraberry. And that really started horizontal development back about 12 years ago. The green wells are what we're calling second-generation benches just to help us tell our story. And then the third, these golden color ones are these emerging benches. We're the only ones that talk this way in first gen, second gen emerging. Every other operator just sees it as 1,100 meters of pay that they want to get after, but it just helps us tell our story a little bit here. So back to these benches, this illustration. So if we look at the drilling density of what we see is typical drilling density across this 1,100-meter stack of pay, what we see on those initial benches or those first-generation benches, our lands are about 30% developed. If we go to those second-generation benches, they're about 10% developed. On the emerging benches, they're just getting started. So we see a couple of wells on there, but not enough to color in a dot. And so on here, again, ignore the size of the dot compared to the stack, you've got 1,100 meters with a whole bunch of 8-inch wellbores in it. And how we think about that as you look at these first-generation benches, horizontal drilling started in 2010 to 2012. There is still a tremendous amount of white space on this map that have yet to be drilled on these first-generation benches. You can see here as it gets a little bit lighter colored, there's still lots of infill drilling to happen. And so that's kind of what everyone thinks of the Permian is these 3 zones. But what's happening with the second-generation benches is a whole new Permian is emerging, and it's just getting started when you look at the drilling density. So very lightly drilled operators just testing these benches across the basin. And then if we look ahead 10 years, we've got these emerging benches that, again, are even more in their infancy and operators testing, drilling and developing them. So we really see 3 phases. And when we look at well performance, we don't see any difference between each of these bench descriptors. I'm not going to walk through these slides, but it just shows you some of the well performance that operators are seeing as they're testing these emerging benches, as they're testing these second-generation benches, as they're expanding the play boundaries out from the jelly that we discussed earlier. And then this Dean Zone, which you'll refer to a little bit here, but it's pretty exciting. We're talking IP180s at 700 barrels a day of oil. And so -- so some pretty impressive results that we're seeing. And so how do we know this basin so well? 1921, remember, the first well drilled, 43,000 vertical wells have been drilled in this basin since 1921. They're still making 80,000 barrels a day of production. The basin is very well delineated. We've got logs across the whole play, so we can map those zones, we can map those intervals. These first-generation benches that we talked about, 1.6 million barrels a day. The second gen benches that just started being really actively developed in about 2.5, 3 years ago, already contributing 600,000 barrels a day. And a little bit of that orange mustard on the top there is these emerging benches that are just getting started. 380 wells, we put that in there as a bunch of the old vertical wells that tested and proved those zones that are still producing. Another question we always get is, yes, but the well performance is getting worse and worse and worse. We don't see that. We see that on a -- if we look at normalized thousands barrels per 1,000 feet. So the wells are getting longer, for sure. Exxon is drilling 4-mile wells now. But if we look at the results going back to 2016, it's a pretty tight band of performance. So if you pick the story, I guess, 2024 here is a little bit below what the very best was. So yes, performance is degrading a little bit. But where we've been really focusing our acquisition efforts is in that core, that jelly that we talked about. And that's what's driving outsized well performance on our asset base. So how does that look on an example? So we just picked this example. It's a Diamondback operated DSU. And so you see there's a thick column of pay, and you can kind of see the green is the program that they started drilling in 2016, '17. So some of the initial reservoir benches, those first-gen benches. They came back in 2018, '19, a little bit more infill drilling, pushed up a little bit here. 2020, '22, a little bit more infill drilling, just picking away at it. And what's that done? Easy math says is 4,000 barrels a day over 8 years. Right now, 2,000 barrels a day. 28 wells have been drilled in there. This is just de information that we're talking about at 700 barrels a day, IP 180. They haven't even touched that yet. And so the other thing that's a good example of, we say there's a lot more production volatility in the U.S. And this is a good indication why. Every time they're fracking a new pad, bringing all these wells, they shut in all the offsetting wells. And so we get these kind of blips as production is shut in for fracking. We get the flush production. And so you get that variability in a monthly production. But when you roll it all up and you think there's 1 DSU with mile-wide 2-mile wells, there's been 11 million barrels of oil come off of that DSU and over 8 years and still doing 2,000 barrels a day. If we like bigger numbers, we can go 15 million BOE a day -- or BOE in there if we want to throw in some NGLs and some natural gas. And you lay that over on to our land and you go, oh, look at this, Freehold has the offsetting DSU there. It doesn't even have a well drilled on it. So the green lands on here are our royalty lands that have not had a horizontal well drilled on them yet. So you look at a DSU contributing 11 million barrels. We've got lots of fresh lands waiting to get drilled. And the grays you can see depending on the density of wells that they're not even fully developed yet. So this is what supports the running room that we see on this asset, 28 wells and kind of just getting started. And so right now, with the land base that we positioned, 1 in every 6 well that's drilled in Midland is on Freehold lands. And how do we acquire it? On average, it's a 25% royalty interest on lands. And we're just buying 100 acres here, 100 acres there, just chipping away from individual landowners or from amalgamated packages to just kind of continue to move this needle around the clock in the DSUs that we want to be in. Back to what I was saying earlier, these are the cume production by bench, again, normalizing it to a 2,000-foot well or 2,000-meter well. These are these first-generation benches. This is a Dean bench at the very top here. These are some of the other second-gen benches that we talked about and emerging benches. And a lot of these emerging benches are just starting to drill these and figure out what the optimum drill design and frac design is. So again, we're pretty -- these performance results speak for themselves. And again, just we're not the only ones saying it. Diamondback and High Peak of what they're seeing on more productivity from each of these zones they're testing. I think it's important when people say, well, who's drilling on your land again? Well, 2/3 of our drilling inventory is under Exxon, Diamondback, Conoco and Avintiv. And when we look at that, where do they line up on this map. So this is the Midland outline. This is what we call kind of the jelly, the best part of the play. And the blue on here are these guys. So they own, control and operate the bulk of the inventory that we have on our lands. As you move a little bit to the east here in Howard County, what we see that, that's where some of the privates and the smaller publics are playing. And these guys are great seed ideas where they're testing these different benches and then they've been getting consolidated by some of these majors as those areas get proved up. So again, I think we're in all the right locations when it comes to the opportunity set in Midland. We'll talk a little bit about the Eagle Ford and where we're at there, that's our biggest producing area. And the 3 primary intervals that produce there are this Lower Eagle Ford, where the bulk of the drilling has been done, Upper Eagle Ford and Austin Chalk. And so there, we have about 3,600 drilling locations, split evenly between the Lower Eagle Ford and the Uppers. And where our land is positioned in is in what they call Karnes County. So Karnes County is generally accepted one of the most productive areas of the Eagle Ford Basin. And that's where both Conoco and Marathon were operating and Marathon got bought by Conoco kind of consolidated under this whole area. And so that's where we see that Conoco is our big operator here. And we're -- again, we'll show you that we're in the right spots in just a second here, okay. So this is these additional Eagle Ford benches. And so on the previous slide, where all the drilling has been done, we still see lots of opportunities to continue to drill, continue to drill along in this Atascosa County and continue infill drilling. Conoco in their press release with a -- saw 1,000 drilling locations in the -- on the Marathon acreage in the Eagle Ford. That will be about half would be on our lands. And so that really aligns well with how we see the world as well. On the additional benches, well performance on these additional benches, have been on par with what the initial development was in Lower Eagle Ford. And again, just getting started as operators are kind of marching along here and marching along here, and that's what drives the inventory in those 2 plays. So kind of heart of the play, best -- this is the best IP365 oil rate, and we've been actively positioning our lands in this high productivity window, where we're getting Karnes County, one of the best ones where half our net acres are. Atacosa is here where another 20% is. So I think we've got a good operator, and we're well positioned in the high productivity area of the Eagle Ford. The other thing that's getting a lot of press more recently, and actually, we're seeing a little bit up in Canada, too, is this refrac concept. And so -- in the Eagle Ford, particularly that Lower Eagle Ford, when it first started being developed in 2010, your much lower profit intensities in the wells than we see today. So kind of modern frac technology in the last 5 years, you look at kind of IP 365 on oil is up in the 220, 250 barrel a day range, kind of half of that in this lower frac intensity area. So as Rob said, we have about a 1.3% royalty interest here. And so these refrac potentials have meaningful value to us, and it's really targeting resource that was left behind in these early stages of development in the Eagle Ford. What does the refrac look like? Just a couple of examples off of one pad. They did 2 different refrac styles, 3 months apart. But you take a well that has already cumed 225,000 barrels, did a refrac on it, added another 150,000 barrels of recovery. Same with this example, 170,000 barrels of recovery. So they're very competitive to drilling a new well when you consider you've got your wellborn in place, you've got your pad, you've got your infrastructure in place. So we see about 500 refrac locations on our Karnes County lands. And again, how does that calibrate to what Conoco is saying? They say 1,000 across Karnes, and we think about half of those with our bottling is on in our land base. Yes. Just -- and again, we're not the only ones. Conoco, Devon, Murphy are using these refracs all the way across their acreage, and it competes with the best drilling opportunities. So yes, so where we're at, I think our oil-weighted U.S. assets, we've really been conscious of being oil weighting and putting them in all the right areas. So $685 million invested, light oil exposure, premium pricing, royalties under leading operators in the top basins that really, I think we're going to deliver a much more consistent development pace as these operators -- these new operators integrate this into their business strategy. Like we said, next week, we'll get a sense of how Exxon is thinking about it as one of our biggest payers. And then like Rob talked about, we have 30 years of development inventory in here, and we see opportunities to continue to chip away at building that -- the business in the U.S. Okay. So on the Canadian side, again, a little bit less --. A little bit lower oil weighting on the Canadian portfolio at about 45%, but it still, again, drives over 80% of revenue. Rob talked about the biggest plays for us at the Viking, Southeast Saskatchewan, Cardium and some of the Mannville plays. The areas that we're seeing a lot of activity right now and that we're excited about is the Clearwater, where we entered into the Clearwater in 2020 or late 2019, partnered with a company called Woodcote, who was subsequently bought out by Tamarack, and they're back at it again, doing some additional exploring. And so with that, we're approaching 500 barrels a day of production out of the Clearwater. We're across the whole play from -- down in south -- from Southern Clearwater and Figure Lake, all the way up through Marten Hills, Nipisi, Peavine and into a lot of the exploration areas in Peace River. The -- if we look at our asset base, we view it as having serious exploration potential. A lot of the assets are just really in kind of early stages of development. If we work our way around here, our core operator at Figure Lake is Rubellite. They've just finished testing a couple of fan type wells. They're testing -- reducing their inter-leg spacing. They're just putting gas conservation in up there. If we go to Jarvie, which is South Clearwater operated by Tamarack, they got multiple exploration sands are being tested. They're drilling these fan wells as well with excellent results. At Nipisi, that's where the waterflood expansion is. So Tamarack is operator, about 20% of our royalty lands are under waterflood right now. And then on the West Nipisi side of it, this is where Woodcote and Headwater are -- have got some really good new step-out areas that they've been developing. Going to West Marten. This is again operated by Tamarack, stacked sand development. They just drilled a fan well in there just before breakup this year, again with some pretty interesting early results. And there's lots going on in this greater Peace River, Peavine area that we have excellent exposure to. So we say this is just at the infancy and 80% of our 430,000 acres of Clearwater land is undeveloped. I think this is an important concept here, and I'm sure a lot of you guys have seen this, but this whole concept of open hole multilaterals and how it's -- you're really reintroducing option value across Canada, and I think eventually, into the U.S., to be quite honest with you. But -- the -- when multilaterals first started, kind of simple concept here, both in the Clearwater and in Mannville heavy, it's kind of evolved to multiple variations of the fishbone, the sweepers, the stingrays, the big central fans or in some cases, a certain zone is really amenable to a very specific well design. And so operators are using that knowledge to go after each zone with a specific design. And so we see this improved drilling economics really allow access to zones that people just didn't think we could recover hydrocarbon out of. And we're going to see that resurgence in Western Canada as more and more of these zones get tested. This is a good example. I've just used the Mannville stack as an example. If we look back in 2016, Freehold had 1,800 barrels a day of royalty production in Mannville heavy oil. And that was all coming from these vertical CHOPS wells, these slant wells, some early-stage horizontal wells. And then today, that had declined to about 750 barrels a day. We're kind of reversing that now where we're back up to 900 barrels a day and growing as all these different well designs are coming in. So right back into all the areas that we have royalties on -- that were such a big part of our business even 6, 8 years ago, are now seeing revitalization through the new well design. And again, for us, we didn't have to invest a cent in there. We've been positioning ourselves in these best areas where there's known hydrocarbon accumulations. And time and time again, operators will figure out a way to access that. And the other area that we have significant royalty position at 525,000 acres of royalty land, including one of the biggest areas of mineral title where we have about 300,000 acres is Southeast Saskatchewan. And in Southeast Saskatchewan, again, we're just starting to see the multilats being drilled out there. So accessing more of the reservoir, eliminating the risk that was associated with fracking in Saskatchewan, where there's underlying or overlying water zones. And most of the spuds that we're seeing year-to-date are multilaterals, targeting the Midale, Frobisher and 21% of our inventory is in Southeast Saskatchewan. It also carries an outweighted portion of value because of the light oil nature. So that 21% of inventory equates to about 1/3 of the future value. So how is that working? We just showed an example here of what's happening in Viewfield Bakken, where historical development in the core of the Bakken has been with horizontal multistage frac wells. You're on the fringes of the Bakken, where we see that there's still really good oil on the logs, but it has an overlying water leg. And so a frac in these wells just brings in that overlying ocean and they're not economic. So what operators are doing now is going in with these multilats, don't have to frac them and you compare the performance that they're getting in the core of the Bakken with these multi-lats out on these fringes, it's a 50% productivity improvement. And we're seeing that as we look at Southeast Sask spuds that the operators are moving toward these multi-lats. And so the Bakken is one example, but we see it across Southeast Saskatchewan in a number of different zones, and they all have that same characteristics of water either above or below a zone with oil sandwich in there and just how do we get at it. Just a little bit of commentary from some of our key operators on that. And finally, just a little bit -- again, a bit of Canadian cash flow machine for us at 1,000, 1,500 barrels a day of oil consistently and it's been the Viking. And when we talk about Viking, we're zeroing in a little bit on this Dodsland, but Viking for us goes across Western Canada. And we've got Viking gas as well. And so that all goes into the inventory that we talk about. But we bought into this area in 2015. And over that time period, just consistent drilling activity. And today, in the Viking here and across the broader portfolio, we see that ability to roll that same type of inventory out across with multiyears of development ahead of us. Again, operators are reducing their well density. They're increasing their lateral lengths. They're putting waterfloods in place. And so the Viking for us and for Western Canada has been a huge contributor. I focus a little bit just on the Mannville heavy, which is over here, but I did want to capture that we do have 1 million acres of Mannville ownership. So outside of the heavy and what shows up here in the Clearwater, this whole West Central Alberta, which is very prospective in the Mannville, whether we're talking [ Glauc or Ostracod, Ellerslie colony ], there's a number of zones in there. And we're seeing, again, good activity out in West Central Alberta, and that's not multilats yet. It tends to be more horizontal multistage frac wells. But if we look at that resurgence between that and the production heavy oil areas, we're getting -- we're seeing those Mannville oil royalty volumes improve across the portfolio, led strongly by the Mannville heavy oil spuds, but also on a broader basis across the portfolio. This is back to what we talked about a little bit earlier, just putting the systems in place to drive that deeper knowledge of our land base. So that helps us with the leasing. We've been quite active leasing in the last number of years, which is really driving production growth from that leasing activity. And where is that happening? Really, what we've talked about in Southeast Saskatchewan in that Mannville heavy oil section, predominantly led by privates and some of the smaller -- some of the juniors that are really driving that. That also helps us with the audit and compliance work that we do. And again, the systems that we put in place, just the understanding of our contractual arrangement allows us to make sure that our operators are effectively developing the lands. And working with them, we've been able to, again, drive that $55 million of, what I call, free money into the portfolio and return that to shareholders. We talked a little bit earlier on with the work that [ Ian ] has been doing on the balance of minerals. And so -- on the balance of minerals side, we've got just over 1 million acres in Canada, and we've also got the same amount of exposure on the U.S. side. Most of the activity to date has been in Canada, where Ian and his team are working with about a dozen companies on leasing the lithium and helium rights as well as with -- primarily with BHP, Nutrien and PADCOM on the potash leasing as they're each looking to expand their potash operating footprint in Canada. So yes, Canadian theme, we've been in business since 1996. And so all the production that -- all the lands that we acquired in 1996 were producing lands. And so that's when Rob says only about 10% of our lands don't have -- doesn't have locations on. It's because all the land that we've been acquiring has generally had production on it. So these are proven fairways, and that's why we continue to see the opportunity set to do the infill drilling, to do the new well technology, and that's what drives that high percentage number. We don't have a lot of moose pasture in the Canadian portfolio. And what that's resulted in is that since 2019, we've invested about $30 million, and that was to put that Clearwater play together. And Canada has held its own despite that and just a statement of where that portfolio is located. We don't -- we're not generally in the gas fairways. We would be in the Deep Basin and some of the Cardium. It's not a huge contributor to our funds from operations. But we kind of view it as a bit of a free option on gas. In 2022, when gas was $5, it was contributing $0.35 a share to our FFO. If we look at this year to date, it's about $0.06 a share that has contributed. So we see the impact of weaker gas pricing on our revenue. We see it a little bit in volumes because you get a lot of volumes that are associated with gas, so they don't derive a lot of the revenue. But we do have that option value on gas with a pretty good land position in the Deep Basin with our primary operators there being Tourmaline as #1, Peyto is #2. And so quite active drillers out there. Again, just a position on multilateral capture. Because of the oil-weighted nature of our operating areas, we see that we're really primed to take advantage of that. And not just the Clearwater, Mannville heavy oil, but Southeast Saskatchewan light oil, we're seeing in Belly River. We're seeing some wells being drilled up in the Montney, Charlie Lake. So we see that, that opportunity to unlock value in Western Canada and with 6 million acres in Western Canada, we're well positioned to take advantage of that. That's a button they told me not to push. Okay. So with that, I'm going to turn it over to Dave to just talk a little bit about the financial parts of our business.

Thanks, Dave. Good morning, everyone. So let's talk a little bit about money. So one common theme across our portfolio is it's all high-margin, low cost. And that's because we don't need to spend any money on operating costs, and we don't need to spend any money on abandonment liability or reclamation, which can be really expensive. So what's that translated to? Well, you can see -- here we go, let's flip to the next slide here that over the last 5 years that we've generated over $1.4 billion of revenue. And because it's high margin, over 3/4 of that has gone directly to our FFO at $1.1 billion and of which just under half of that has been paid out to shareholders. So of that $1.4 billion of revenue, you're getting over $600 million of dividends that are paid. And so this cash flow is also growing. If you look over that 5-year period, underpinning that revenue is our production per share, and that's grown over 10% over that period. Funds flow from operation per share has grown over 50%. And then dividends to shareholders has grown by over 70%. So that strong low margin or high-margin business with a growth profile of cash flow is a meaningful contribution. So when we look at it, that growth, I think it's best illustrated about our dividends, our annual dividends over the last 5 years. You can see that trajectory, now trending at over $160 million of dividends paid annually. And so what we've done is we partnered that with a conservative capital structure. As an illustration of that, you can take a look at what our net debt to funds flow from operations have been over the last 5 years. And it's been averaging each year below 1x. So what does that mean? It means that we're paying a lot of that cash flow back to shareholders, but we're also accretively redeploying that to acquisitions. We're actually pretty proud of our acquisition and our return on capital. So we charted that against our royalty peers for the last 5 years. And you can see that how we're performing. It's exceeded the royalty peer average year in, year out. And in the last 3 years, it's been trending over 15% versus the royalty return on capital employed average is more like 10%. And so that's contributed to a growing cash flow. So we've been balancing that out with a dividend payout ratio of 60% of our funds flow from operations. And that allows it to keep sustainable across the commodity cycle. So as you can see from this, you look at a discrete year, our payout ratio may vary some years below that 60% and some years higher than the 60%. But you can see that trend on where it averages. And that just reflects setting that reasonable amount means it's sustainable and deliverable. So I want to point out that since our IPO back in 1996, we paid a dividend every single year. We don't need high commodity prices to pay a dividend. It happens. It's just the nature of the low-cost, high-margin structure that we've got. And so to date, since our IPO, that's over $2.2 billion to shareholders. And with all of that upside that Dave and David or Rob have been talking about, that bodes well for the future, where we see, let's call it, years of dividends yet to be paid from that portfolio. So talking a little bit about where we are today is so we're at $0.09 per share on our dividend. And so that equates to a yield of over 7%. So what we did is we charted that against our liquid weighted peers and to show where we are and that sustainability of our dividend right now is the breakeven is around $50 WTI. And so we're in a very strong position of having a relatively low breakeven, but also a higher yield. You take a look at some of the peers, yes, they have a good over 5% yield, but look at their breakeven points, right? Can they deliver that in a low commodity price environment? Or you have peers, yes, they've got great lower breakevens, but they're not necessarily delivering as competitive a yield as we are. And so the power of us is that we're doing both of those. And so that just bodes for the resilience of our dividend and the value that we're creating for our shareholders. So with that, I'll turn it back to Dave for his final remarks.

All right. So what is the Freehold story? So we've got the royalty ownership, focus on royalty ownership. So it provides significant exposure to high-margin assets with 0 maintenance capital. We've been intentionally positioning ourselves at what we view as the low end of the North American supply stream cost curve. So in times of commodity price variability, we're confident that we're going to still attract capital to our land base, both in the U.S. and in Canada. In the U.S., we're continuing to align with the best, with the Exxons, the Diamondbacks and the ConocoPhillips as our big payers in the U.S. really driving the activity and really coming off $100 billion of investment and wanting to get in there and grow those businesses. And we've got over 30 years of development locations. So as Dave said, we got a very attractive dividend yield. It's covered down to $50 WTI, and we've got locations, locations, locations in all the right areas for multiple years to come. And so the team has a lot of pride in the work that has been done over the last 5 years to really transform the portfolio from where it was when it started in 1996. So with that, we're going to turn it over to a Q&A session. And Todd is going to moderate that, right, Todd?

[Operator Instructions] So I'll be doing an online portion, and Nick has a microphone in the room if anyone has a question from the floor.

Jeremy McCrea from BMO Capital Markets. So a few questions here. The first one is when you're putting this playbook together and the valuations, you said you're taking a 3-year historical average for the well productivity rates. How does that compare when you look at the upside? How much of the upside is based on that 3-year average versus some of the more recent well results are there? Like how much more upside could there be? And then you talked about lots of inventory. How do you -- I think, just bring that -- how do you expedite this to bring forward today?

Yes. I think I'll answer the expedite question, and then I'll turn it over to Rob just or John is back there on the inventory valuation. But from expediting, really, what we wanted to do is move it in our inventory into hands of people that have the capability to expedite it. So we don't know exactly what Conoco's pace or Exxon's pace is going to be or Diamondbacks yet. But when we look at what they talked about when they're building that portfolio, Exxon, for example, when they bought the Pioneer position, they're talking about taking that combined 1.3 million barrels a day in the Permian in the Midland side to 2 million barrels a day by 2027. So you think about that, that's 50% growth over that time period. And so we're going to learn a little bit more about the pace of that as we get -- as we see some of these budgets with [ G&A ] but with the new companies that have been created through the M&A work. But what we do know is that the locations are really good. The operators are really good. And depending on their view of commodity price, that's what's going to set the pace of development. So we're going to learn a little bit more of that, Jeremy, to be quite honest with you. But the quality of the locations is what gives us the confidence that they're going to develop at a reasonable pace. And maybe, Rob, on the math.

Bit of a half answer, Jeremy, because we'll kind of split it Canada and U.S. So on the U.S. side, as you mentioned, 50% of our inventory is in Midland, 40% is in the Eagle Ford. And so when we look at the big step change in Midland type curves, that's kind of been over the last 10 years. We've seen about 100% improvement in the type curves in the Midland over the last 10 years. But in the last 3 years, they've been relatively similar type curve. Yes, there's been a longer laterals, but in terms of the actual type curve, it's been relatively consistent in the last 3 years. Similarly, with the Eagle Ford, there's been about a 50%, 5-0 percent improvement in the type curves over the last 10 years. But the real step change for that was about 2019, 2020 time frame when they materially increased the amount of proppant intensity, as Dave reflected on one of his slides. And so again, the last 3 years, Eagle Ford has been relatively consistent type curve. On the Canada side, that's where I think we have seen incremental better type curves in 2024 versus 2022. So we haven't quantified that, but that would be -- directionally, we could see Canada has gotten better year-over-year over the last 3 years.

Maybe just one last question here. When you guys are putting this playbook together, I'm sure you had some ideas of what this would probably look like before you started. But what would be your biggest surprise that we should take away from this that you guys -- once you sell the final product?

Today on the U.S. side, it was just the sheer amount of stacked inventory that we had. I'll kind of give a bit of an example. When we did the bulk of our acquisitions in the U.S., so in 2021, 2022, we did not underwrite any value to those secondary -- those second-generation benches that Dave talked about. We knew they were there, and they were starting to be tested, but they, for the most part, weren't being actively developed. Now they are. They've added 0.5 million barrels a day of oil from those secondary -- those second-generation benches. So the fact that when we look at the inventory that we have in the Midland, half is from the first gen, the Wolfcamp A, the Wolfcamp B and the Lower Spraberry and half is from those 5 other benches that are now being actively developed. So that was probably the one that got us a bit excited. I was just seeing the sheer amount of locations that are there, and they're not the equivalent of air barrel locations like they're actively being developed today. So that's on the U.S. side. On the Canada side, I think it's really just seeing what is happening with multilats, like it's not -- this is not just a Clearwater story. This is not just a Mannville stack story. This is also -- we're seeing it in Southeast Saskatchewan. So it's kind of giving us some confidence that we can see it elsewhere within the portfolio. So I think that -- those would be the Canada U.S. side, we guess most excited.

I have a specific question on Slide 5. I want to flip back there. All right. That chart on the left that shows the value creation since you entered the U.S. Is it fair to assume you're selling yourself a little bit short there because that excludes the revenue generated on those assets since you bought it?

Yes, that's fair. And it doesn't include what we see as the opportunity set on those lands. So when we -- this is what we spent in that time period, the $585 million. This is what we had booked. So that doesn't include the revenue. It doesn't include any of these benches that we're talking about that are in our asset book. And so this is just strictly paid versus year-end value, excluding the -- what would have been at that time, about $320 million of cash flow generated. So yes, you're right.

Okay. I have a follow-up question that's a little bit harder. Of the value creation between the black bar and the green bar, how much of that is better-than-expected commodity prices? And how much of that would be better-than-expected asset performance?

I would say that on that, typically, at the time, we were running probably a $60, $65 deck on that. So particularly in 2022 when we had that really strong commodity pricing that drove some of that for sure. But it is -- I would say, the performance -- when we model this thing, we -- initially, we had quite a production increase, and we had quite a tail off. And so what we're seeing now and that models in this value a little bit is that we didn't get the peak, but it goes forever, right? And so that's not captured in there yet. So I would say the price was probably 50% of it and probably just the performance of certain basins has been the other half. And that will just continue to reflect as we get our new reserves evaluation. So...

Can I ask one more?

Yes.

So Freehold has gotten bigger over time. Your related entity, Rife has gotten smaller, is in the process of selling assets. How do you think about the management relationship between Rife and Freehold going forward?

Yes. I think the management arrangement is something that we look at every year. And so we just finished a review of that. And I think you hit the nail right on the head. The businesses are evolving and going in 2 separate directions. And so the historical management agreement, is it as relevant as it used to be, especially when you go through a time period where Freehold had a lot of working interest production and Rife was helping manage that. So those discussions, I could say, have certainly taken a different direction as the companies have both evolved. And so we'll continue to have that. But I think you're seeing the same things that we're seeing as far as that structure is still the right structure from where it was in 1996.

David and team. Maybe a bit of a similar question to what Aaron asked here, but if you were to apply an NPV to the undiscounted value that you have presented here, like the $15.6 billion, like what would a 5% or 10% discount rate on that sort of look like in your assets?

I get you to handle that one.

I might actually ask you that, [ Jamie ], because it's sort of one where we've sort of provided the undiscounted one, which you can take a bit of your own perspective in terms of how fast or slow you think our key payers are going to be. It's one when -- I think as Dave mentioned and we've talked quite a bit about and Exxon as an example, when it acquired Pioneer, it talked about a year-over-year more than a 10% production growth rate between now and 2027. That's half of our inventory is under Exxon in Martin and Midland County. So it's kind of one where -- I'm not sure the right time frame to put it on, but...

Okay. No problem. And then maybe on the U.S. side again, David, I think you mentioned that the asset performance when you initially entered the jurisdiction perhaps didn't meet initial expectations from when you're acquiring these different assets. Can you just talk about how your approach to M&A down there has changed then? Like how have you changed your production performance expectations? Has it changed what you're willing to pay for assets down there, just things to that effect?

Yes. So the performance of the assets, that's not the driver. It was the pace of development on those assets. And so if we look at initially setting a pace based on a pre-COVID, we had a view that was the only data set that we had. And this is how many wells typically were being drilled on those assets prior to COVID in spring of 2020. And so we use that pace and the type curves to help set a production forecast. Today, when we look at it, we can see what that pace actually is. It's a consistent reduction in pace. We see it with reduced drilling rig activity. And so we can model that. So I would say the acquisitions that we did in 2022 are much more bang on the expectations from an inventory perspective. If we use that Eagle Ford example where we paid USD 150 million for that position in the Eagle Ford, when we bought that, we modeled it as kind of 5 years of drilling inventory where Marathon would keep the pace that they had kind of ramp up production. And then by year 5, by year 2027, that asset was in a steep decline. What we're seeing today is that moderated pace, so we never hit that peak that we thought. But all those drill locations are still just as valid, then we see we're laying in these refrac opportunities and then these additional benches. And so from a reserves perspective, we are going to get more reserves, but it's just that initial expectations on productivity in those first couple of acquisitions, the one in January 2021 and then the Eagle Ford one is probably where we got tripped up a little bit using that historical pace. But we're recalibrated now. And from a return perspective, we're still seeing mid-teen rate of returns. And how do we compete? We're finding that the development inventory is pretty well defined. So a lot of people were bidding. We have the same geo development inventory. You have a -- take a view on pace. Everybody is using strip pricing. And so the difference between winning and losing, we're all targeting this kind of mid-teen rate of returns is quite small, actually. So that's where it becomes uber competitive. And so one of the things that we're doing when we started back in 2019, it was a ground game in North Dakota. And we're reintroducing ground game into the Permian right now, where with the work that we've done on the asset book and really understood where the thickest parts of the pay was, we're going in and just really targeting specific LSDs that -- or not LSD, specific interest in a given DSU and going back to that ground game. And that's giving us returns that we think are going to be up into the low to mid-20s kind of thing. So just continually evolving our game based on what we're learning. So back to the ground game, also at the -- looking at bigger opportunities, but recognizing it's super competitive.

Patrick O'Rourke, ATB. Maybe just build on the comment you made there. In terms of the M&A strategy going forward here in specific DSUs, are you looking to target sort of filling in white space DSUs? Or is there an opportunity to increase the networking royalty interest in existing acreage you have exposure to already?

Probably a little bit of both, Patrick. Our preference would be what we tend to call wall-to-wall carpeting. Ideally, we'd have wall-to-wall carpeting in Midland, where we have an ownership in every DSU. The thickness of the carpeting, we can debate, but priority one comes to getting wall-to-wall carpeting, so exposure across all DSUs. Second would be building that ownership up on targeted DSUs. And yes, we are definitely targeting white space so that the operators can come in using the latest and greatest kind of drilling and completion technologies, this cube development strategies that people are using to really drive maximum value. And so that's what we're really targeting right now. So wall-to-wall carpeting first.

Maybe this is for Rob, but just you didn't really hit on any enhanced oil recovery directly. I think it's implicit in the Canadian value. But can you help us kind of think about how that value could be captured in terms of the NPV and then maybe more short term through '25, what type of activity you see versus primary drilling from existing operators?

Yes, you're right, Travis. We didn't explicitly include additional EOR opportunities in our asset book. Existing EOR opportunities we quantified, but anything in addition to that hasn't been quantified at this point. We know it's there. It's in that future optionality, green circle or yellow circle that we talked about. And sorry, just to repeat, what was your second question?

Just in some of the activity that you're seeing come through production accounting, like are you seeing a shift from primary development to get some incremental value from the production from EOR initiatives in budgets or just general activity in different shifts in solvents or however you just kind of think about broader EOR opportunities? Yes.

I mean in terms of the sort of 3 plays that we have meaningful EOR right now, Clearwater, about 20% of our volumes would be under waterflood, mostly with Tamarack and Nipisi. We have about 30% of our net production in Southeast Saskatchewan under waterflood. And that's kind of quite broad, and that's what I think we definitely see that increasing over time. And then we have about 20% of our net production in the Viking under waterflood today.

Just wondering if you could give us maybe for Rob, your current multilateral production, if you kind of add up all the different areas, the top 4 or 5 payers in those areas just collectively? And then what do you think is a reasonable growth rate if you were to kind of add it all together and recognize you don't have all the granularity, but just any kind of general thoughts you might have on that?

That's a good one, Mike. In terms of trying to think through the areas where we have our multilateral production, I might phone a friend here a bit with Dave Spyker as well just to try and think through the areas and the key payers.

Yes. So the biggest payer on the multilats would be Tamarack Valley. Second, I would say would be Rubellite on the multilats. Starting to see Baron creep into that with some of the work that they're doing in Southeast Saskatchewan. But for the most part, the kind of names on the screen here would be Tamarack Valley, biggest. And then as we move into Mannville, where we're starting to see the payers, that will be -- [ Caltex ] would be a big payer for us on multilats. CNRL more and more is, we're seeing as a payer, a little bit of Rife as a payer on some of the lands in Lloyds that has been an active multilat driller. And so it's a wide variety, but tend to be some of the privates and smaller juniors right now as that's ramping up.

And any estimate for this pace of growth? I know you don't know exactly what folks are going to be doing, but just percentage-wise, if you were to kind of guesstimate some guardrails here, would you have any numbers? And just the total volume to.

Just trying to think of my feet through that.

Yes, no worries. We can always follow up with.

Yes. So I think multilat production right now is probably -- given that it's almost 500 barrels a day in the Clearwater, add on Mannville heavy. We're probably getting close to 700 barrels a day of multilat production across the portfolio. Where will that go? Do I think that, that would be 1,000 or so next year. I don't think that's out of realm when you consider where that I don't have that here, but just the pace of what that's going. So yes, it's hard to say. But I think that we're 500 in the Clearwater across the portfolio, if that doubles in a year, that's not surprising.

We'll go for one online. Can you view the company's view on natural gas and how well is the portfolio positioned to benefit from positive shift in long-term fundamentals of the commodity?

I think our view on natural gas is that we've got good natural gas exposure in Canada in the Deep Basin. And in the U.S., Midland Basin is also one of the fastest-growing natural gas areas associated with solution gas. So we've intentionally hooked our wagon to oil production and really focused in those areas. But half of our production is still natural gas and associated NGL. So any strengthening of natural gas pricing as it shows in the forward strip, you will benefit from that in Canada back into a return of drilling activity on our land that's been a bit more muted this year with gas around $1. And in the U.S., a couple of places that we're going to benefit from that, just the growth that comes with natural gas. In Midland, pricing in Midland has been a little bit under pressure with pipeline constraints. That takeaway constraint has been mitigated with Matterhorn Express pipeline that came on second half of this year. So you're seeing a rebound in pricing activity. But that gas is an area that they're talking about AI facilities or proximal to LNG exports in the U.S. And so we think that even though the gas has not been a focus of build areas in our portfolio, we've got a lot of exposure to it in a number of areas, although it tends to be more solution gas and then liquids-rich gas in Deep Basin.

One more from online. I realize I stand in the way of lunch, so I'll be brief. How would a 25% tariff in the U.S. affect freehold?

Yes. I think there's lots of speculation on what a 25% tariff would do if it -- but I don't know what -- how that's eventually going to play out. But when I look at our portfolio, we've got 1/3 of our production and about half of -- just under half of our revenue comes from the U.S. I would say that having that U.S.-based oil production puts us in a little bit better place to manage that than if we had 100% Canadian exposure. So we're just going to have to see how that plays out. But I do like the fact that we have U.S. exposure.

Yes. How do you guys think about dividend growth? And what are kind of the key areas in your portfolio that are going to support future dividend growth?

Yes. So the dividend growth, to provide more dividend growth, we need to grow. We need to grow our portfolio. And we are a commodity-based business. So we need certainty in commodity prices. So where we're at right now? We're at that roughly 70% payout. That feels about right now. And so if we saw some further strengthening in commodities, and that would be an indicator of being able to grow our dividend. When we walk through all the opportunity set on our lands, we are confident that capital is going to get put in to work on these assets, both in Canada and the U.S. The pace of production growth. We'll get a better sense of that as we get through operators' budgets through late this year and early next year and we release our guidance. But we think that we're in the right places that operators are going to invest in. So with stability in commodity prices and continued investment by operators, those will be the catalysts to grow our dividend. All right. Well, thank you all for participating today and some great questions. 1.5 hours seem to go by pretty quick for me. So I hope it went quick for you as well. And we encourage you to stick around and engage with the leadership team that's here and have a bite to eat as well. So thank you all for attending.