Okay, let's get going here. Before I begin, I'd like to make some introductions. On the front table here, we have our directors. I'd start with Nicki Stevens, John Rossall, Stephen Chetner, who's our corporate secretary, Jocelyn McMinn, Michael MacBean, and Debra Gerlach. I'd also like to introduce our senior management team to folks who may not have met them all. I'll start with Tavis Carlson, our CFO; Riley Frame, our COO; Lee Curran, our VP of Drilling and Completions; Todd Burdick, our VP of Production; Derick Czember, our VP of Land and Business Development; and the newest members of our senior management team. We've got Mike Rees, our VP of Geoscience; behind him, Crissy Rafoss, our VP of Finance; and last but not least, Mike Collins, our VP of Marketing. Okay.
I'd like to remind everybody that today, all statements made by the company during this presentation are subject to the forward-looking disclaimer and advisory that can be found at the end of the presentation. It's four pages. So let's talk about what we're going to talk about today. We're going to provide you with a brief introduction about who we are. I think most people in the room know that, but I'd like to talk a bit about who we are, what we do, why we're excited about natural gas, a bit about Peyto's business and how we do it, and then how did we do in 2024, and then what's the plan for 2025 and beyond. And of course, at the end, we'll open it up to questions. So let's start with a quick reminder of who we are.
26 years ago, the foundation for Peyto was set by pretty much what it still is today. It was set by Don Gray. The plan was to run a business that focuses on what's important. It's built to last, it's transparent, and it rewards its shareholders. Back then, the company chose the Deep Basin as its home, and we're still operating there today, and we have grown it from pretty much zero, mostly through the drill bit, to 133,000 BOEs per day, or about 800 million cubic feet equivalent per day. 12% of that is liquids, and we've always had an own and control strategy. Owning and controlling our infrastructure is important to controlling the development in our areas and the production that comes on at our gas plants. It also helps to increase utilization in our plants. That's what drives costs down.
Of course, we have the lowest costs in the Canadian E&P industry, as I'm sure you're aware. In fact, I would argue even in North America. We've always had a focus of running a long-term business with sustainable returns, and so we complement our low-cost structure with a price mitigation strategy. We hedge on a regular basis, and we also have gas market diversification to help with risks. The company believes the best way to measure our success was on a per-share basis and returning profits back to you, the shareholders. Currently, we pay a monthly dividend of $0.11 per share, and that's well protected by our hedging policy and our low-cost structure. We do all this with 88 staff here in the Calgary office and some consultants. Many of them are here today, actually.
All the reps, all folks we brought on board with the acquisition in late 2023 have been integrated into the Peyto culture and have received their tattoos. We also have a very large group of mix of employees and contractors in the field who keep things running for us 24/7. So just a reminder of where we operate. This is Peyto's, I don't want to call it playground or postal code. This is where we call home. 1.1 million net acres in this area. We own and operate 17 gas plants with 1.5 BCF a day of processing capacity. We're 90% working interest of that, and it's only about 58% utilized. So lots of room for growth. It's in an area that has a great location for egress, so we don't have the same challenges of the congestion of the Montney players up to the northwest.
We have a very experienced technical team. They've been drilling lots of wells. 1,400 horizontals we're more or less at now, and half of which have been drilled by the same drilling rigs that we have under contract today. So lots of experience in the field too. And we have a great production operations staff that keeps everything humming out there for us, some of the best online time in the industry at about 98%. And a lot of that has to do with the fact that these plants are interconnected and we can move gas around so we can keep things loaded when there's a turnaround or an upset condition. So let's talk about why we think natural gas is the future and why we think the future of it is so bright. Let's not kid ourselves. Fossil fuels still make up 80% of the world's energy needs.
Natural gas is about 30% of that, and it's still growing. It's not realistic to think we're going to replace it anytime soon. It doesn't mean there's not a place for renewables, certainly where they make sense, but I think the world's going to need all forms of energy as we go forward, especially in the developing world. Zooming in a little bit into sort of North America and what's coming for North America. This is some context on LNG export capacity, and I hesitate to use the word exploding because that's not a good thing in the natural gas business, but it's certainly growing rapidly. It's continuing to grow from 16 BCF a day today. It could reach as much as 30 BCF a day by the end of the decade. So that's almost double. That's significant. And the projects are shown on this map.
Not all projects are shown on this map, just the ones that are either under construction or they're imminent or just come online, so this is not everything that's contemplated, and to put this in context, U.S. and Canada supply is about 125 BCF a day right now, and so future LNG expansion of 14 BCF a day down in the U.S. and in Canada, that's 11% of the current supply. Significant. You couple that with forecasts for gas-fired electricity, so this would be for industry or data centers just in general in the U.S., total net gas demand could increase by another 10 BCF a day or 8% of the current supply, so put those two together, and you're looking at a 20% increase in supply if it all comes to fruition, right, and this is at a time when the U.S.
Shale productivity is said to be in decline. So Canada could play a major role in filling this gap. Zooming in a little bit more into Alberta here. Of course, we're excited about LNG Canada starting up. It's imminent. It's exciting. And there are other projects that are on the come. There's going to be increased egress, and it should be very supportive for the AECO pricing environment. But creating demand is equally important, and much of Alberta's power grid right now is supplied by natural gas, especially in the winter when renewables aren't reliable or aren't reliably contributing. So we also believe that we have the right climate here in Alberta and the right business environment and an abundance of natural gas supply, essentially, to attract these hyperscalers for AI. And we're seeing that with the applications on the AESO system. The queue is up to 10 gigawatts applications.
This is excluding Wonder Valley because it's independent and may not be part of the grid. It's not included in this number. But if you look at the 10 gigawatts, that's 1.3 BCF a day of natural gas if it was all supplied with natural gas. And so that's based on our experience with Cascade and what it uses. So for Western Canada, you include LNG Canada phase two build-out. You talk about Rockies LNG and other projects. You can easily get yourself up to 8 BCF a day of incremental supply if it all comes. Even if part of that comes true, it's an awfully big number for a basin. It's only producing 19 BCF a day currently. So that's why we're bullish on natural gas, and that's why we believe in the long term for natural gas, and we think we're in the right business.
Meanwhile, storage capacity in Canada and the U.S. hasn't really changed in the last 15 years. So while both supply and demand have both increased, the buffer we use for seasonal demand, right, to buffer the changes in the seasons is much smaller relative to supply and demand. I like to think of a bathtub as a good analogy. You think about your bathtub. You've got the faucet coming in and the drain coming out. And the bathtub is big enough. It takes a while to fill it, or it takes a while to drain it. But the nozzle, the faucet coming in and the drain going out has gotten so big now that it acts more like a sink. So it's a lot more sensitive. You can empty and fill a sink a lot faster. So that buffer has gotten a lot smaller relative to supply and demand.
So you look at this chart here. It shows how demand has been increasing, the black line there, and the days to cover that demand has actually been decreasing over time, right? And it just means that we should expect prices to be more volatile, right, and positive or negative, depending on conditions. So if you're going to play the commodity cycle, you better be able to step on the brakes quickly or chomp on the gas to accelerate if you're going to take advantage of the price changes. And they don't last that long, so you need to be very quick. So we don't think that's an effective way to drive your car. Certainly, it's hard on the equipment. It's not good on fuel economy. So we think that's exactly how you should run your drilling program: steady. Run a smooth machine.
You get great efficiencies by doing that, and you need to because you need price revenue certainty. And that's one of the reasons why we like to hedge and why we have the market diversification. So we smooth prices from predictable revenues from profits to run a steady program, steady capital program, pay those profits to you, the shareholders, and manage the balance sheet. And over the years, that smoothing of revenues with our hedging and our relentless focus on cash costs has provided us with very consistent returns. So although we might not have as much torque to short-term price increases, we certainly provide a much lower risk in your portfolio of investments over the long term than our peers. So one way to measure this or to think about this is by comparing a Sharpe Ratio across the industry.
A higher ratio indicates less volatility, so less risk or volatility in our returns. If you look at the chart top right there, we compare quite well to I think we use in this case, we're using return on equity over the last 10 years. We rank up there as the highest amongst our U.S. peers in Canadian E&Ps, both large cap, small cap, medium cap. In this case, we feel like because we do have such a less risky business that we should trade at a higher multiple. We should see that. Another important point on this slide is how we compare our costs against all of North America. On the left-hand side, you can see that. I think more importantly, though, on the bottom right, you see the margins. At the end of the day, that's what really matters.
And you can see how we stack up even against sort of the richer players out there and our margins. Even in a year last year, for example, where gas prices were at one of their worst, and our margins were still fantastic and compete with the oilier players. At the beginning, I talked and I mentioned about per-share growth. So I want to highlight these slides. They're slides that have been in our presentation for a very, very long time, and it's because we think this is important. So if you think about the two graphs on the left-hand side, that's the stuff that we control directly: production per share, reserves per share. It's what we drill. It's how we produce it. That's directly in our control.
Funds from operations per share, we do control elements of that, obviously, with our cash costs, with how we risk mitigate against price changes. But it is driven more by price, so last year, it was down slightly, as was our value per share, was down last year slightly because of the fact that, again, the forward-looking price deck used by the reserve evaluators was lower. But nevertheless, if we're growing our production per share and our reserves per share, we should see cash flows and value per share grow over the long term as we do here in this plot, right? Otherwise, we're not doing our job. Okay, this is my favorite slide, so I got to get excited here. I call this the Deep Basin advantage, and it reminds me of the fact that the Deep Basin is a world-class reservoir.
It's often forgotten, and all the hype over the Montney and the Duvernay plays. And I think it was Warren Buffett that said, "Know your circle of competence." And I would say Payto's circle of competence is drilling low-cost wells and operating them in the Deep Basin. And some of the attributes of the Deep Basin really relate to its better reservoir quality. And so just a quick comment on that. We're chasing a tight sandstone versus a Montney siltstone or a Duvernay shale. So we don't need to stimulate our wells as much as those other plays to create that permeability to get those molecules to float to surface. So what does that mean? It means less water, less sand. And so the plot on the top left shows you that. It illustrates the fact that a typical well that we drill uses far less water.
And that means we don't have costs to bring that water in for the stimulation or costs to handle that water later. And it also means we can put these wells on a much smaller footprint because we don't need the space to hold that water in the first place. We don't need to drill super long laterals because our rock is better than those plays. And so we can keep to smaller rigs, cheaper day rates, easier to move around. So that helps us with our cycle time. So we can start paying out the capital that we're spending right away. Another attribute on these areas and the plays that we pursue here in the Deep Basin is it's a sweet gas. So it's easier, cheaper, safer to operate. There's no bottom water as well to deal with in this Deep Basin.
The only amount of water, material amount of water we need is the water that we put in there, right? Geographically, on the bottom right, that's the map there. We are situated downstream of all that Montney digestion, as I mentioned, all the activity that is to the northwest. We still can get capacity on the system downstream on NGTL if we want to grow. We have lots of extra capacity already, but we could get more. The other thing is the advantage is it's lower tolls. We pay less because we use less of the system. That's another cost advantage, as it were. Of course, we have a lot of spare capacity at our gas plants, so we can also grow there.
We might move things around to optimize where they're located, but for the most part, we don't need to buy new. So what have we done with all this over the last year? Let's talk about some of these accomplishments. We acquired the remaining Repsol assets in Canada at the end of 2023, closed the deal in October 2023. And 2024 was the first full year that we had those assets and were able to work them, as it were. And essentially, we did what we said we were going to do. Drilled some great wells, 40% better outcomes than prior years as compared to Peyto's legacy lands, the wells we were drilling in the past on our own lands. More than doubled the production on these assets using just over half of our drilling capital for last year.
We've integrated the assets in the field, brought down operating costs by simplifying the business, simplifying the operations, so that means shutting in the Sour Gas plant and the Sour Field. It means redirecting production to optimize field pressures, and for example, shutting in ethane that was low value and putting that back in the gas space to save costs. We focused on really, we just focused on making things more profitable, and when you roll all that into the full 2024 program, we see a marked improvement on well productivity with pretty much the same or even lower costs, so we did this improvement of 25% on the whole, en masse without spending any extra money per well basis. We've continued to evolve those horizontal lengths and the stimulation intensity.
But we might be at a point where horizontal length is optimized for some of our plays, especially with the current technology and the ways that we like to do it. So we're looking at other ways to make design improvements, like we did recently with the Cardium down in Chambers. We'll talk more about that later. And after all, the focus for us has always been on economic outcomes. We're not chasing the monthly top 20 list for most productive wells. If I can use a baseball analogy, we're happy hitting singles to score our runs than hitting home runs. At the end of the day, this is all that matters. How much money did you make with the capital you were given? We show this is all the results for every well from 2024. It includes the failures because they happened.
Incidentally, we only had two last year, which is pretty good for us. This includes all the capital that we spent. Facilities get allocated back to each well. All the capital that was spent in 2024 is included in these numbers. Like many years, our Notikewin continues to outperform. We still have lots of plans to drill more wells here, particularly in the back half of this year. Another point on this plot is those two Falher wells that really stand out. They're very competitive with the Notikewin. Those were the two wells that we drilled last year in this new channel that we discovered right underneath us in Sundance. This is an area where we've had the land for 25 years, and we're still finding things. This is a good example of that.
We drilled another well there in Q1 here, and it's looking great too. So it's exciting. And so it's not all about Repsol. But obviously, the Repsol wells last year, they're the ones with the stars. They did perform a little bit better. But if you look at the grand scheme of things, even our legacy program performed very well last year. So quite happy with the results. So where are we going? This is our plan for 2025. So despite all the external noise that's out there, it's business as usual for Payto. Gas prices look good, so we're cautiously optimistic. We'll continue with our guidance to spend CAD 450 million-CAD 500 million, similar to 2024. 80% will be allocated towards drilling wells, 70-80 horizontal wells. So 80% of our budget's drilled complete equipment tie-in. Facility costs will make up the rest, another 20%.
And there's projects scheduled for Oldman and two turnarounds. Oldman North and Oldman will have turnarounds in September. We also have an Obed compressor project in Sundance that's going to go in in Q3 and be operational in Q4. And that's sort of to complement a drilling program that we have down in area and protect the low-rate Cardium wells from getting backed out. And those wells will go into the central fuel gas gathering system and down to the Edson gas plant. Should get better liquid recoveries too. So excited about that coming on later in the year. But as always, capital program will be flexible. We'll keep an eye on the price and the business environment.
But if you use the midpoint of our guidance here on both capital and capital efficiency, we should be able to more than offset our estimated 27% annual decline. And that should have us exit close to 145,000 BOEs a day. When I say exit, I mean December of this year. A little bit of the complexion. It's really not that much similar to last year on what we're planning on drilling this year. Some notables, though, I'll bring up. So we talked about the Cardium earlier, Cardium drilling down in Chambers. We did that to test a new design. We did that with a couple of lower working interest wells. We drilled lower in the zone in what's called the bioturbated zone. And no, we're not counting on contribution from that zone. But this was really just to get increased in penetration rates, drilled it all with one run.
So that's important. It kept our costs quite a ways down. And that was the intention of the whole operation. We added more stages, though, so 60 or so. So that may offset the drilling savings. But at the end of the day, this is to improve overall recovery in the end. And that's the goal here, right? Just to improve the outcomes of the Cardium so they can compete with the Spirit River capital that we have with those returns. Because 25% of our 2P reserves reside in the Cardium. That's our undrilled reserves. And so it's important that we wanted to test this concept. In fact, we're out there right now, I think, drilling, following up on these two wells with higher working interest locations. The other thing we're doing this year is following up on a Bluesky success.
Actually, it was a well drilled by Repsol twice that we're following up on. And good result. We completed it once we took over the operation. And it's a great result. So we're following up on that this year. And as well as Viking that we had drilled in 2023, we're following up on that. So that'll be exciting to see. We've already drilled three Dunvegan wells in the first quarter. We might save those follow-ups for better liquid pricing. We started them before the price kind of dropped on us on the oil side. But anyway, the rest of the program really is constituted of our typical Spirit River zones, Notikewin in Falher, Wilrich, right? This is one of my favorite slides as well. It speaks to the margins and the profits. And it's a good way to look at the business.
When you include our total supply costs, you can compare it to a full-cycle netback and look at our margins. We've been able to maintain a greater than 30% margin over the last 25 years and most recently over 40%. And if you look at our goals for 2025, we're expecting to get closer to 50%. So let's go through some of those. Last year, we did an FD&A metric of $1 per MCFE. This year, we have a goal to do that again. I think Riley sandbagged in there, but we'll see. Last year, our cash costs were $1.46. This year, we expect them to be closer to $1.38. So royalties are up because gas prices are up.
But that's offset by lower interest costs because lower interest payments because the interest rates have come down and we have as we pay down debt. And the other thing is op costs. We expect op costs to continue to come down throughout the year. Todd's assured me of that. So when we look at total supply costs at CAD 2.38, that hunts well with a CAD 4.63 on the current strip and all of our hedging. So that yields us about a 50% margin. So it's a good piece of business. Looking forward beyond 2025, there's no reason why we can't repeat the capital efficiency that we've demonstrated over the last year. We have plenty of quality inventory to choose from, 1,600 locations on the books. So this notional three-year plan has us growing to 155-160 by the end of 2027.
I don't think this has materially changed since we first announced it in the acquisition in Repsol in 2023, except we did pull back last year due to prices. So it's been delayed a little bit. This should drive enough funds from operations to more than cover the capital program and the dividend and allow us to decrease our net debt along the way here. Regarding that debt, we're still targeting a soft target of one times debt to trailing 12-month EBITDA. We expect we can get there sometime in 2026 based on current commodity prices. Okay. This is a pretty important few slides. I want to talk a bit about our marketing program. Mike probably wanted me to open with this one because of how important it is. But I've saved the best for last, Mike, to talk a bit about how we do our marketing.
And so let's talk a bit about the hedge position that we have. Obviously, maybe we'll start by why we hedge. We do it, I've said earlier, to get predictable revenues to support our drilling program and to ensure we can provide you, the shareholder, with returns and smooth out volatility, right? Our mechanistic approach avoids speculation. So it's like dollar cost averaging. And over the years, it's been very profitable. You look at cumulative financial hedging gains here of CAD 562 million. And that includes the losses in 2022, which was a very good year for gas prices. So it's not that we expect that to happen, but this is what happened with the way we run the business. So in fact, when you combine that with our diversification program, we've beaten AECO for the last, what, 13 of 18 years using this approach. So it's working well.
We talked earlier about price volatility or the potential for price volatility and increasing. So we are not going to change the way we handle this program. This is going to continue for us. We'll take good prices off the table as we always have. But I wanted to highlight something here that's important. It's the components of our realized gas price. And it's a new slide we added to the MD&A this last quarter. And it breaks down all the different pieces of our realized price. So we start with basically where an unhedged AECO price would have been. So if we were to sell all of our gas at AECO, this is what we would have got. So in Q1 of 2025, it'd have been CAD 2.21. And then it shows all the two other components.
The important components would be the blue wedge, which is our synthetic or, sorry, our diversification program. And it's really starting to contribute, as you can see that wedge increase over the last few quarters. And its value is actually net of transportation costs. So that's either synthetic, so basic stuff, or physical, where we actually have pulled the physical transport. And it's net of that to get to those markets. So that's an important distinction here on this plot. And I think it's important for you to, when you're comparing companies, you should, there's one thing to get there, but how much did it cost you to get there, right? So you've got to net that off. So we've done it here for you. But if you're looking at someone else, you might want to look at the realized price and then subtract their transport costs.
In our case, our transport costs really are just our AECO and NGTL costs, which everybody pays. Anyway, we embarked upon this several years ago. I guess it was early 2018 when we put this program together. It's taken us about five years to really build it up, but it's really starting to bear fruit. And I wanted to point that out. So expect to see this slide as we continue quarter to quarter. And in closing here, I just want to talk about the hedge position that we have currently. We're excited, obviously, about LNG Canada coming on. Everybody is. But it might be a little messy this summer, right? So we have close to 500 million cubic feet a day for the remainder of 2025 and another 400 million cubic feet a day for next year.
It's fixed at $4 an MCF versus AECO right now, which over that same period averages about 250 MCF. We're in pretty good shape here. What's left is floating, what we call floating or exposed to several demand markets such that we don't rely on one market. That's probably not a good business strategy to have just one customer. We have these pointed at different markets. A good example of why that's important, look at Cascade here this past, our Cascade deal this past quarter, power prices were quite low. We essentially just got AECO pricing for that. It's a good example of why diversification is important to have gas pointed at different. In the future, we expect power prices to be much higher.
That particular contract might be quite lucrative, whereas it's a 15-year deal, remember, whereas maybe Dawn is not trading any different than transport costs. This is the point of having diversification. It's a risk mitigation tool in itself. If you think about what Peyto does, it's maybe a little different. Maybe we don't have as much torque to the upside in the short term, but we're running a very predictable, stable business for you, the shareholders, so you can have predictable, sustainable returns. Bill says that's enough out of you, JP, get back to work. I'm going to end it here. Thanks for coming. Thanks for your support. I'd also like to thank the employees that came down. Many of them are here. Their hard work and dedication is important. These are your shareholders, and this is who you're working for.
Thank you very much.