All right. Good morning, everyone. Thank you for joining us today. I would like to welcome you to the Tamarack Valley Energy 2025 Investor Day. I'm Christine Ezinga, Vice President of Business Development and Sustainability at Tamarack. Today, I am joined by our full executive team: Brian Schmidt, our President and CEO; Steve Buytels, our Chief Financial Officer; Kevin Screen, our Chief Operating Officer; Rocky Baker, our VP of Marketing; Lynne Chrumka, our Vice President of Exploration; Kevin Johnston, our Vice President of Finance; Scott Shimek, our Vice President of Production and Operations; and Ben Studley, our Vice President of Engineering. Through this presentation, the team will speak to the key aspects of Tamarack's business model in addressing the company's capacity to leverage our top-tier oil assets to drive long-term per-share value creation for our investors.
Our presentation this morning will begin with Brian Schmidt, who will provide an overview of what makes Tamarack a unique opportunity and the compounding success that is being observed through the development of our core Clearwater and Charlie Lake Plays. Steve Buytels will then walk you through the updated five-year plan, outlining notable year-over-year improvements. This will illustrate how our highly economic inventory translates into increasing returns to shareholders on a per-share basis each year throughout the five-year plan. This will lead us into a detailed discussion of our assets, with Scott Shimek speaking to the Charlie Lake Light Oil Play, followed by Lynne Chrumka and Ben Studley, who will present our Clearwater Heavy Oil Play, including the application of water flood and the positive implications of deploying enhanced oil recovery on our assets as part of the development plan.
Rocky Baker will provide her insights and outlook for Canadian heavy oil, along with the success Tamarack has achieved through the execution of our strategic plan, which continues to enhance our price margins. Finally, Kevin Johnston will address Tamarack's return of capital framework and the capital structure outlook. We will then welcome Brian back to the podium for closing remarks. Following the presentation this morning, we will open the floor to questions. Those who are participating online will be able to submit their questions via the webcast link. I would note that within the materials being presented today, we will be making forward-looking statements, and as such, I would direct those participating either in person or online to refer to the disclaimers at the back of our materials.
Also` included in the disclaimers are definitions and explanations with respect to specific financial information, including non-IFRS financial measures, reserves and resource details, and a glossary of abbreviations used throughout the slides. With that, I'll turn it over to Brian.
Good morning and welcome to Investor Day. We are very, very excited about today because over the last year, we've been focused on rate of change, and that was last year's theme of the Investor Conference, what we promised: rate of change. Today, we're able to talk about those changes. We're able to incorporate them in an updated five-year plan that you're going to see today. The most, a lot of questions that we get are dealing with water flood and how to model water flood. We hope to give you some insights on what we're seeing with results and how that can parlay into the future. I'm going to talk today a little bit about the compounding success of our business.
When I talk compounding success, it's what do all the levers that we have and all the arrows in our quiver have to do with increasing yields and returns for shareholders: share buybacks, debt paydown, OpEx reduction, marketing improvements, water flood with multi-year, almost decade paybacks that keep coming at you for your return on capital. How does that all compound into strong yields? We're going to talk a lot about that today. I'm going to just cover a few slides, and then Steve will talk about the major change in this year from last year on the results that we're seeing both in the financials. Of course, we'll move into the technical results. I'm not going to go through this slide in detail. This is common that we have in our corporate slide.
We would have talked last year about transformation of the company into new assets, about 90%. Actually, I did the math this morning. It's about 94% of our production comes from new assets that we've accumulated in the Charlie Lake and the Clearwater and now been running those for the last two years. You get to see not only the transformation complete, but you get to see the results that we're getting from it, which are quite spectacular. The shares that we've purchased since December 2023, we've almost got 10% of our shares bought back. It's pretty significant at a reasonable price and certainly drives all the per-share numbers that you see today. We've got about a 22% debt-adjusted PDP reserve growth, quite substantial. One of the themes today that you're going to see is reserve growth as we invest in some of these projects.
I do not know if Michael Tims, I do not see him in the crowd, but he will be happy to see debt-adjusted production per-share numbers there in the 20% since Q4 2023. Some pretty nice numbers both in production reserves and a little later on debt-adjusted free cash flow per share. In terms of the stock, you will note that management has been buying back stock and pretty much across the board. We are believers in our own business and acquirers, and I think that gives a lot of substantiality to what we are talking about today. Why would you buy Tamarack? The one thing that I was taught as a young engineer is that just get the large OOIP, the large runway, and then you have something to work with. It gets very difficult if you are dealing with two- to three-meter sands.
When you're dealing with up to 25-meter sands, up to 50-60 million barrels of oil per section in place, that's a great runway to start. If you look at our acreage, and this has been growing, last year we would have said we're about 8 billion barrels of oil in place. Now we're probably somewhere in around the 11 billion, greater than 11 billion. That gives the investment community that there's a lot of runway left, a lot of technology will be developed to unlock that further and build on our numbers. I would say now that the Clearwater is a proven concept. There's an industry, I think there's something like 207 injectors now, a lot of water between three main operators being injected in there, and we're seeing some spectacular results, which you're going to see today. These projects have hit payback already.
We just do not know how many times they are going to pay back in the future. That is the unknown, but that is all going to be gravy in from here. And Ben will talk a little about that. You are going to talk about we are going to see low production declines, and it is going to be trending lower. The more we invest in the business, the stronger the business becomes because we are dropping our decline rates. The break-even price when you have low sustaining capital drops as well. This is a chart put together by Peters & Co. Limited, and it has us third in place behind a couple of steam operators. You see our internal numbers are even better. That would move us to number one. The main reason for the internal number being lower than analyst numbers is decline rate, is changing decline rate.
You're going to see all analysts will catch up to an improving business in decline rate, maybe even after you see some of the presentation today. Increasing cash return on capital invested. If you look at the lower left chart, you can see this growing. This is the interesting thing when we put this together, that despite the oil price softening here in 2025, in our estimate, we're still going to be above last year's at a higher CAD 84 price that you see there. You're going to see a pretty good indicator of how that's going to grow in the future with some of the investments we got. Last point here is the capital allocation flexibility. We have a lot of optionality in the business, and we've taken advantage of that optionality. When is the right time to buy back shares?
When is the right time to invest in primary drilling? When is the right time to invest in water flood? When is the right time to pay down debt? You have a lot of levers that can respond to the business. Those businesses that do not have those levers can get themselves in trouble when you have one thing that you have to focus on. Let's face it, when we did our major acquisition, the only lever we had was to pay down debt. You are going to see today now that that is relaxed, now we have some, we are closer to our debt floor, and that gives us improved optionality. Getting back to the question, why would you invest in Tamarack? There is very little differentiation between the smaller companies in the basin right now.
What I want to leave with you today is a reason why we're different than a lot of our peers. You can see here that the payout periods, and when we've looked at long-term debt-adjusted free cash flow per share, the most common element that we found in your economics is how many times an investment gets paid out. If you're in a high decline environment, which is typical of unconventional wells, you're going to get one and a half, maybe two times payback with the good stuff. You're not going to approach anywhere near the three- to five-times payback that you're going to see in a Clearwater or the 7-10-15 times you're going to see in a water flood project in the Clearwater. It's going to be real interesting.
This is a chart put together by an analyst that compares all the plays in North America, clearly establishes the Clearwater is the best play in North America at two times payback within one year. That's just phenomenal. In my career, I've not seen that kind of play before, at least at this scale. You'll note in the top 10, the top 10 are conventional plays, with the exception of the Permian. If I put a three-year payback instead of a two-year payback on here, you would see all the plays in the top 10 are going to be conventional.
One of the things I'd like you to take away today as you go through the presentation, the guys tell the story, is taking a look at what the differences are between conventional and unconventional and adjusting your thinking, which we've all been trained to think in an unconventional well manner. If that reason isn't good enough to step into this stock, then take the other one. If I get 500,000 barrels on reserves on a primary well, I'm probably going to get about 750,000 on a water flood. The chart on the right shows you the growth that we expect in the waterflood program. At the end of five years, we're probably going to be in around 20,000 barrels per day on that. Ben and we'll talk a little bit about how these patterns are responding and how we built the forecast.
Bottom line on this chart is you have conventional play economics with an unconventional resource scale. The vast runway that we have, huge inventory, secures we're going to be sustainable and predictable in years to come. I'll turn it over to Steve now, and he'll talk about changes from last year to our plan.
All right. Thanks, Brian. Brian did mention last year's theme, a rate of change. This slide here looks at our 2025 look versus our 2024 Investor Day case for the period of 2025 to 2029. This is not our new 2025 updated plan. This is just a year-over-year look that we want to talk about here. I think there are three key outperformance measures here that we probably want to talk about. Number one being the decline or the reduction in sustaining capital that is coming through the plan on the back of the outperformance of the Clearwater water flood that Brian has touched on already this morning, and Ben is going to walk you all through here later in the deck. The second thing would be the margin enhancement that is coming through the business. We have had cost reductions as you pay down. Our debt interest is lower.
We've made some significant improvements on operating costs, transportation costs, etc. So you're seeing the margin in the business go up. Rocky's also going to talk about our wellhead realizations and what we've been able to do there with more of our product on pipe here shortly. The third item is the capital efficiency improvement. When we look at what we're doing on a primary basis in the Clearwater and in the Charlie Lake, we've seen some significant improvement in capital efficiencies. We're able to do a lot more for less. You're seeing that continue to trend this year. When we talked about our guidance range here with our Q1 results, we pointed to Tamarack being at the lower end of the capital range of about CAD 430 million and at the high end of the production range of about 67,000 BOE a day.
Again, all of those things continue to come through. You continue to see them coming through the plan where we now have, on a like-for-like scenario, 4% more growth through the plan. Our annual reinvestment ratios, you can see in the table there, is down about 10% annually. You have incremental free funds flow as an output out of that. When we look at the debt-adjusted production per share, the debt-adjusted free funds flow per share growth, we see about CAD 325 million more free funds flow in this plan year over year, which from a cash-on-cash yield perspective at our current market cap today would be over 13% incremental return to shareholders. Significant amount of incremental free funds flow moving through that. Slide six here looks at now this updated five-year plan.
As Brian talked about, the rate of change was the theme last year. He mentioned compounding success. That is really the theme this year in building on what we continue to do in terms of achieving excellence and driving better and enhanced profitability through our plan. When we look at this, there are a couple of key points that I want to drive home today. Number one, the corporate decline. When you look at our annual corporate-based decline rate, we now have the end of the plan in 2029 and 2030, reaching 20%. Last year, we would have talked about a range of 23%-25%. What does that mean? A lot less sustaining capital going to come through, more free funds flow, more optionality for growth. The second thing here is your organic growth. You now see that through 2030 to approximately 80,000 BOE a day. Okay?
As we think of that, you still have a CAGR of about 3-5% on a fixed capital program of CAD 450 million. Again, we're able to do more with that for less. You're going to see when I talk about the next slide, there's more free funds flow optionality that's going to come through that, just given that lower overall decline and the more higher profitable barrels that we're bringing on. What we'll talk about here shortly is Scott's going to talk about the Charlie Lake. We anchor the Charlie Lake in this plan as just stay flat. Why? It is a highly economic asset. However, the Clearwater barrels have better margin and a more resilient margin in a volatile commodity price environment. Brian talked about the amount of times you get on payout on a primary basis on a Clearwater well.
Even if you invest in that well at a CAD 60 price environment, you're going to get that payback in that year. You're going to get a couple more paybacks, and you're going to probably catch a higher price in there somewhere. You're not getting your one payback at low price, and you're not maximizing, in that case, the value for shareholders. We do like and see from a capital allocation standpoint, more money should go into the Clearwater here. You got the water flood on top of that, obviously, that compounds that. When we look at the growth coming through the plan to 80,000 BOE a day, that growth is all from the Clearwater. Okay?
The third thing, which is going to tie back to a little bit of the whole growth element of the plan, is our debt target with the incremental free cash is accelerated by two years. Last year, we would have talked about hitting that debt target of CAD 500 million, which is predicated at CAD 45 WTI at one times debt- to- EBITDA at the end of the plan. We now see that in 2027 at a price range of CAD 65-CAD 75 WTI. At that lower price point of the range, you're going to be at the end of 2027. At the higher price point of the range, you'll be very early in 2027. What does that mean ultimately? Kevin Johnston's going to talk about our return of capital framework.
You're going to have 80% of free funds flow directed back to shareholders through buybacks and our base dividend, which does shrink over time as we buy back more stock from an absolute outlay perspective. The key here is there's more optionality for growth. That 20% that's left over doesn't have to go to debt repayment. It can. That actually is optionality for more growth that isn't in this plan today. How much would that be, that 20% at CAD 75? You're probably in and around that CAD 40 million-CAD 60 million of additional capital you could put in for growth in that plan that doesn't exist here today. When we think about the unique attributes of growing production, a shallowing decline, I talked about the debt-adjusted production per share and debt-adjusted free cash flow per share growth.
We see that at about 100% on a debt-adjusted production per share basis and 175% or a little bit better than that on a debt-adjusted free funds flow per share basis over the five years. Significant growth there at that CAD 75 WTI case that we're running here. What does that mean for shareholders when we look at all of that free cash over the coming five years? One, you're going to have over CAD 400 million in base dividends that get paid out. More importantly, we see the repurchase of greater than 50% of our 2025 year-end outstanding share count, very significant from a buyback perspective. Again, the optionality for additional growth that is not baked in this plan as we hit that debt target on an accelerated basis.
With that, what I'll do here now is I'm going to pass it over to Scott Shimek, our VP Ops. He's going to run through some of the optimization going on in the Charlie Lake and the continued resource advancement that we see and others see going on there. Thank you, Scott.
Thank you, Brian and Steve. Going to move into slide nine here. Yeah, here to provide an overview on our Charlie Lake asset and jump into the details. Through steady growth and reliable performance, we are the largest Charlie Lake oil producer. I'm going to walk you through some of the key metrics associated with this asset. Since acquisition, we've been able to grow production 51% to just shy of 18,000 BOEs a day at Q1 2025.
The asset offers a low sustaining reinvestment ratio, specifically 46% in 2024, which allowed for the generation of approximately CAD 113 million of free net operating income. The top right graph highlights the cumulative free net operating income through year-end 2024 of CAD 360 million. It's also noteworthy this CAD 360 million was generated through that previously mentioned period of growth. Shifting to some of the reserves key metrics, I'll highlight the value and runway of this asset. From year-end 2021 to 2024, TPP reserves are up 77%. In addition, we've achieved greater than 100% reserve replacement on a TPP basis over the last three years, as highlighted in the bottom right chart. Lastly, at year-end 2024, TP and TPP reserve values were more than CAD 450 million and CAD 1 billion, respectively. Going to move to slide. Optimize, we've been able to optimize and build out.
As a result, we can support production levels of approximately 17,000 BOEs a day for more than 10 years. Alternatively, we can pursue growth. This asset provides a luxury of optionality. As Steve mentioned, our plan as currently presented today is to sustain production levels. Since 2021, Tamarack has expanded processing capacity by four times, which has enhanced reliability and afforded this option of growth. In addition, we've acquired 70 net sections, which has strengthened and increased inventory. Specific to the greater than 2.5 MI lateral length subset, we've increased that inventory 135% while running an active drilling program. These are some of the most highly capital efficient in this inventory. Moving over to slide 11. In closing, let's talk about some of the key attributes of this stacked resource and our ongoing innovation.
This is a top-tier reservoir where Tamarack holds a dominant position in the main fairway. Our asset demonstrates light oil ranging from 35-42 API, and in addition, high oil weighting of 50-70%. In addition, we have multiple zones to pursue. I'm going to shift your attention to the map on the right. The upper Charlie Lake in the northeast, highlighted in green. The lower Charlie Lake Brayburn, which extends across the entire land base, highlighted in red. The lower Charlie Lake A member, which has been recently delineated, seen in purple. Finally, several additional targets that will benefit from half-cycle development economics due to existing infrastructure. Today, and as we move forward, optimization and innovation are paramount. Well placement and frac design are being tailored to maximize resource capture efficiently. Open hole multi-lat technology and application is being evaluated, and water flood pilots are being implemented to enhance recovery. With that, I'm going to turn it over to Ben Studley.
All right. Good morning, everyone. Thank you, Scott. I'm Ben Studley, VP Engineering here at Tamarack Valley. Today, I'm going to walk you through a focus section on the Clearwater water flood. The material will summarize the scale of the flood potential, Tamarack's approach to water flooding, what we're observing from a performance perspective, what we can learn from the analogous heavy oil water floods, and what the water flood is providing us economically and within the five-year plan. First off, I want to emphasize the scale of resource we've captured. We estimate approximately 11 billion barrels of original oil in place on Tamarack land, and this resource continues to grow. We have been actively adding to our land base, extending pool boundaries through delineation, and Tamarack and industry have tested multiple additional targets, increasing the prospectivity of our lands.
Tamarack's resource stretches across a broad area from Seal at township 83 in the north to the South Clearwater Trend in township 63 in the south. Many of these areas offer stacked targets in multiple Clearwater zones, enhancing resource concentration and driving capital and operational efficiencies into the business. Moving specifically to water flood, I'll direct your attention to the top right graphic representing the distribution of Tamarack's resource across the fairway. Currently, approximately 72% of the OOIP identified resides in areas where water flood has been effectively trialed and developed. On the map, injection wells are identified in blue, and you can see the concentration of activity has been across the main fairway extending from Martin Hills to West Nipissing, where Tamarack operates approximately a third of total production and has significant remaining inventory.
However, water flood development has not been limited to these areas, and more recently, extended to new areas in Gift Lake, Canal, McMullen, and Uticuma. Water flood has been broadly successful where it has been implemented, and the growing confidence among industry producers has resulted in a continuous ramp of activity. We're projecting 2025 will see approximately double the water flood activity that was seen in 2024, resulting in what will be a considerable step in continuing to make the production base more and more stable, driving down decline rates across the producer group. Tamarack has plans to trial water flood in some of the heavier oil parts of the fairway as well, in Seal and South Clearwater, with the expectation that more and more of the captured OOIP becomes floodable over time, further expanding asset duration and exposure to high-efficiency reserves additions.
All right, next, I'm going to spend some time summarizing Tamarack's approach to water flooding when it comes to injection and well design. Firstly, we're focused heavily on maximizing injection per well and total injection across the assets. We're seeing a clear correlation between water injection rates and production uplift. In the plots on the left, we're showing a demonstration of that for wells that had seen response by the end of Q1 2025. The upper plot shows what we are observing as uplift in light green. Each supported producer is declined out based on primary performance expectations, and the difference between the current production and that predetermined primary production forecast is considered uplift from water flood. In the bottom plot, we've overlaid the uplift with water injection rates, and you can see the water injection provides a leading indicator for the production uplift that follows.
This is fairly intuitive as more water in the ground represents better pressure support and faster reservoir sweep. The strong conformance and low water cut trends we're observing has built confidence and driven our aggressive injection approach, which in turn has improved response times and peak rates and ultimately accelerated our cash flow curves. In 2024, we saw a 75% increase in total proved plus probable water flood associated reserves in the Clearwater, while taking injection from 4,000 barrels of water per day at the end of 2023 to about 13,000 barrels of water per day at the end of 2024. In 2025, we're expecting to end the year injecting about 30,000 barrels of water per day, which will mark another significant year-over-year increase. By the end of the five-year plan, we see injection reaching upwards of 150,000 barrels of water per day, depending on breakthrough timing and injectivity.
All right, I'm going to elaborate a little on our approach to well design. Really, the bottom line here is that the reservoir is very forgiving and things are working very well across the board. A number of different designs are being employed by different operators in different areas, and even the earliest designs that you would think are the least evolved are working very effectively. Now we're just changing things to further optimize based on what we have for land-based geometry, different reservoir parameters, and surface locations, and drive additional efficiency into the economics. On this slide, we've summarized a few designs that are typically used across the Martin Hills and Nipissing areas as an example of what might drive the well design decisions for each water flood pattern.
For each of these examples, there is a type log with a cross-sectional schematic below it indicating where the water injection legs in blue and producing legs in green are positioned. The left two logs are type logs from Martin Hills, where there are predominantly two different designs we are using. Both logs have considerable thickness, but because of different log signatures, we would choose to employ different designs here. On the left log, you can see a relatively consistent log signature and no obvious significant barriers vertically. In this situation, we would deploy the stack configuration where a multi-leg injector is drilled below a multi-leg producer and the zone is flooded from the bottom up. On the middle log, you can see quite a bit more vertical variability. This variability could complicate the efficiency of a bottoms-up flood when the injected water encounters potential flow barriers.
In this instance, we would utilize what we call a W pattern, where you develop multiple benches or elevations within each well. Under this configuration, you are not flooding bottoms up, you are flooding laterally from injector to producer. The W design overcomes the vertical variability and also places legs of the injection and producing wells in the highest quality reservoir typically encountered at the top of the zone. In our view, the bottoms-up approach may not effectively flood the best part of the reservoir here. This approach is unique to Tamarack, and we have had our longest dated pattern now injecting for approximately two years. We have seen great response from the offsetting producers, and water cuts remain less than 10%. The right log shows a typical well design in areas where we do not see the reservoir thickness of Martin Hills. Typically, we are not developing these areas in multiple elevations.
We employ a line drive in a single plane, where a single lateral injection well supports multi-lateral producing wells on either side. There are many small variations on these designs depending on the situation, but this summarizes most of what is driving our well design decision making. Overall, the flexibility of multi-lateral drilling allows us to utilize well designs that are fit for purpose across the assets. I'm going to spend the next couple of slides summarizing what we're seeing from the water flood from a performance perspective. On this slide, we're showing how effectively the water flood is stabilizing production. To remove the noise of recent activity, we've selected all producing wells that were drilled prior to year-end 2023 that are now supported by water flood to see how they have performed since primary drilling finished.
As you can see, the producing well count in black has been the same since the end of 2023, and the production trend in green has been very stable with virtually no decline. As we get more production under water flood, this effect will reduce corporate decline in sustaining capital requirements, which in turn will drive low break-evens and provide durable cash flow generation and profitability through commodity price cycles. All right, this is a very key slide for us as a water flood producer, and it will demonstrate how we're seeing the water flood response coming in through our reserves book. At this point, reserves recognition of the water flood is lagging as the data comes through. There are different phases to water flood response as it matures, and with each phase, you gain more insight into the eventual recovery of a pattern.
The early phases are fill-up and production ramp, and these are typically followed by a production plateau period before getting into a terminal water cut and decline trend. The strong performance of the water flood to date has most of our patterns in the early phases of fill-up, production ramp, or plateau, which does not give you a lot of insight into what the terminal decline looks like as a reserve evaluator. What this results in are upward revisions to reserves as the flood outperforms the reserve forecast each year. As more data comes in and confidence builds in the trends, forecasts are revised on not only the development patterns seeing the response, but also informs the reserves estimates on undeveloped patterns, providing a catalyst for larger scale technical revisions over time, which in turn drives low F&D costs and the expansion of our reserve life index.
In this slide, we've got a few examples of how technical revisions have played out on some of our key water flood patterns and on the asset as a whole. On each of the plots on the right, you're seeing oil rate versus cumulative oil plots with dashed lines showing each sequential year's reserves forecast. Across the water flood, we've been observing significant increases each year, and this is what's leading to the technical revisions. In some of the patterns shown, oil rates are approximately double what they were only six months ago when we were finalizing our reserves forecasts. One well of particular interest is the top left of the group, which we've often noted as the top Clearwater producer ever drilled based on cumulative oil production. We were saying that when it had produced about 400,000 barrels and was starting to see some water flood response.
That well is now producing approximately 600 barrels a day and inclining, and it's produced over 600,000 barrels to date. It's our longest dated water flood well and is a great example of the potential of the Clearwater to provide some prolific results. On the left side of the slide, we've drawn a comparison in year-over-year technical revisions as a percentage of total reserves for Tamarack's Clearwater assets and a number of unconventional and oil sands peers. With our Clearwater assets achieving positive technical revisions of 17% in 2024, the asset is outperforming the group considerably. This can be expected from a well-performing water flood asset with the lagging nature of the reserves recognition. We're in the early innings here and are expecting the water flood performance to continue to provide positive pressure on the reserve book.
All right, we're going to shift to the economics of the water flood now. Presented here is our West Martin water flood type curve run for an injector drill at CAD 75 WTI flat pricing. The primary type curve is in dark green with the incremental water flood wedge in lighter green. This scenario is a single drilled single leg injector providing a lateral line drive flood pattern in one plane, which is typical design in Nipissing and West Martin. The assumption here is that you begin injection within a few months of primary production. Oil rates ramp back up to initial rates before beginning to decline at a shallower rate. We've been outperforming early estimates of recovery under water flood of two times primary recovery and have been revising the estimates upward based on empirical and simulation results.
We're now using an assumption of two and a half times in this area, which results in a growing number of payouts for these investments. The primary curve alone pays out over five times, but the lower cost injection wedge now pays out nine times at very attractive rates of return. This puts the Clearwater in a rare position where unconventional frac plays provide strong rates of return, but number of payouts are limited to one to two times. Oil sands provides great asset duration at lower rates of return. The Clearwater provides both strong rates of return and asset duration on a large scale. Here's another economic case for the type of water flood development we are undertaking in Martin Hills. It's a little different than the example from the prior slide, as this scenario requires converting a producing well to injection.
You can see on the plot that at approximately the four-month mark, the primary production forecast drops as we take a producing well offline and convert it to injection. As we inject water into the converted well, we begin to increase pressure in the reservoir that was depleted during the production phase before starting to see a production response that ramps to a peak. This fill-up period takes a little more time, but our well design and philosophy of aggressive injection during this phase has accelerated response time and payout period. The incredible part of this is because all of the wells have already been drilled and gathering and injection lines are installed during primary drilling, the capital required to achieve this forecast is very low.
Each conversion costs only CAD 400,000, and shortly after peak rate is reached, the pattern recovers the lost income from the converted producing well as well as the capital invested. Subsequent to that, the pattern generates an additional payout every three to four months. This results in over 10 payouts in the first five years and over 30 payouts over the life of the pattern. This is based on our assumption that recovery under flood is 2.5-3 times primary in the Martin Hills area. You can see on the plot the peak rate for this curve is about 175 barrels a day. We are seeing numerous examples of peak rates exceeding this, which may result in our recovery estimates increasing further over time. Okay, I want to walk you through how we are quantifying the resource we have in the reserve and resource categories.
As we aggregated our assets, it was well understood internally how much of the opportunity was unbooked from a reserve perspective. Part of this is the nature of booking guidelines for conventional assets. On the map on the left, drilled wells can be seen in black, and adjacent to a developed well, you would typically be booked one proved and one probable location on either side of the producing well. Those are represented in green. As you get further away from production, you move into contingent locations and then prospective locations. Also on the map, we have put an illustrative wider radius for what you might expect from unconventional resource play reserves bookings. Unconventional resources often or resource plays often benefit from the ability for probable reserve bookings to extend to 10 years on the back of project-based economics tied to large-scale infrastructure investments.
We do not have the same treatment in conventional assets with minimal upfront infrastructure, and the booking window is typically limited to five years. Hence the smaller booking radius we are illustrating on the map for conventional assets. The large amount of upside sitting outside of the reserve book became the main driver for evaluating our contingent and prospective resources. Although we have resource play-like scale with 11 billion barrels of oil in place, much of which is amenable to secondary recovery, the reserves handling of our Clearwater assets results in less future development capital being recognized and a lower reserve life index than we see with unconventionals. If we employed the expanded booking radius commensurate with 10 years of development on our Clearwater assets, a lot of our contingent resources would fall into that area or that radius.
Given these differences, our task is now to characterize our contingent and prospective resources and demonstrate a track record of promoting these resources into reserves and increase the reserve life index through the addition of long life EOR projects. On the right side is a graphic showing how we successfully did that in 2024 by growing our Clearwater proved plus probable oil reserves by 18%, expanding the water flood portion of those reserves from 12% to 20%, and we grew our contingent resource oil volume by 19%. Okay, now we're going to shift to some heavy oil water flood benchmarking. Multilateral open hole drilling has unlocked the Clearwater resource over the last decade, but as this technological shift was required for commerciality, there aren't a lot of direct analogs for water flooding this reservoir.
That being said, we can learn quite a bit about how the flood is progressing and what we might expect over the long term by looking at other mature heavy oil water floods. A pool that is often discussed in this context is Brintnell or Pelican Lake, where the Wabascas have been developed with a mix of water and polymer flood over the last 25 years or so. Now, there are some differences. The core areas of the Clearwater tend to have lower permeability than Brintnell, thus requiring the reservoir contact provided by multilaterals, but the Clearwater typically has improved viscosity. There are still a number of areas in Brintnell that have been flooded using exclusively water to date, and on this slide, we've highlighted one of the largest continuous water flood areas from that pool. Now, what can we learn from this pool?
What we often see in good water floods is ultimate recovery outperforms the early estimates. When we started talking about the Clearwater water flood potential, most operators used an ultimate recovery estimate of two times the primary estimate. This is a common starting point for water floods in general, often used when there is not a lot of data for the flood. For Brintnell, AER performance reports early in the life of the flood estimated primary recovery at about 5% of the oil in place. Water flood was estimated to add an additional 10% recovery, making ultimate recovery equivalent to three times primary production. Actual production has outpaced these early estimates significantly. This area of the pool has produced approximately 19% of the original oil in place now and continues to have very stable production.
We forecast this area to reach upwards of 25%-30% recovery factor, which is equivalent to five to six times the primary production or twice the early recovery estimates. To put this in context of Tamarack's Clearwater assets, I'd say we're absolutely in the early innings here. We are currently modeling ultimate recoveries in a range of two to three times primary with an average of about two and a half across the assets. Another thing we can note from this analog is how well the Clearwater floods are conforming. The bottom right plot shows water cut versus time for the first 24 months under water flood with the Brintnell water flood area in green and Tamarack's Clearwater assets in beige.
One observation we can make is that the Clearwater floods have yet to see a major inflection point in water cut and are maintaining water cuts well below the Brintnell example during the early phases of the flood. Water cuts will climb over time, but heavy oil water floods tend to recover a lot of oil at high water cut. The Brintnell example has produced over 60% of its oil production to date at water cuts greater than 80%. We are not concerned about high water cuts, but we are encouraged by the time we are taking to get there. The Clearwater water floods are a very gentle process. Although we are maximizing injection rates, we are also injecting into substantially more surface area contacted through the multilateral wells, which may be contributing to the strong conformance of the flood front, and the flood front is moving fairly slowly.
Overall, we've been very pleased with the water flood performance to date, and we think some of this analog information points to very favorable results going forward. All right, in summation, what does all of this mean for the five-year plan? With the water flood performing as well as it has, the Clearwater provides the unique combination of growth while shallowing the decline. We are currently modeling the Clearwater declines to reach approximately 17% within the five-year plan, and as a result of this, sustaining capital requirements are reduced, providing a platform for enhanced production and free funds flow growth.
Also, at the end of the current five-year plan, only 40% of Clearwater oil production is supported by water flood, and only 1.3% of estimated oil in place will have been produced, leaving a long runway ahead of the asset and the option for additional growth in water flood once the debt target is reached. I'm now going to welcome Lynne Chrumka to share details on some of Tamarack's emerging areas in the Clearwater fairway.
Thanks, Ben. As Ben mentioned, I'm going to walk you through two areas of future growth for Tamarack, and the first one is Seal, and it's shown here on slide 24. It's important to highlight that this opportunity is not currently in our five-year development plan, but it holds a position at Seal where we hold 30 contiguous sections providing a long runway for multiple development and scalability.
On the right-hand side, a type log shows the four key zones that have been de-risked through a combination of Tamarack-operated activity and offsetting operator success. These include three Flair sands and a Blue Sky. Importantly, the Flair formation has now tested oil both north and south of our acreage. Headwater reported an average of 339 barrels per day oil rate out of a recent well in the Flair B, and Obsidian tested over 170 barrels per day combined from two Flair zones to the north. These results materially de-risk the Flair potential across our lands and further validate the reservoir. With these stacked zones, the average oil in place is 70 million barrels per section. In total, the land base contains 2.1 billion barrels of oil in place, providing substantial long-term resource potential. Initial development assumes a 4% recovery factor yielding meaningful volumes.
Furthermore, there's potential to double recovery through secondary recovery techniques, including water flooding. Just east of our acreage, Baytex has successfully implemented a Blue Sky water flood targeting heavy oil. Results show strong response and commercial performance. This provides a compelling analog for Tamarack's future secondary development strategy in the Blue Sky. Tamarack will continue to delineate and de-risk the remaining zones across the land bas`e. These activities will unlock further value and enhance development optionality, creating a multi-year repeatable growth engine. Upon success, this area could reach a peak production of over 6,000 barrels a day. The second area of future growth potential for Tamarack is at Pelican. Like Seal, this opportunity is currently not included in our five-year development plan, but recent offset activity has helped significantly delineate the resource potential.
Tamarack holds 11 sections at Pelican under oil sands leases, giving us the flexibility to advance this asset over the long term. This area is strategically located with increasing activity by nearby operators, helping us define the opportunity without committing near-term capital. The lower Wabascas and the Clearwater D1 both extend across our acreage. Combined, these two zones represent an estimated 230 million barrels of original oil in place on Tamarack lands. These intervals are shown on the log on the right side of the slide. The lower Wabascas tends to be thicker and of higher quality on the eastern side of our acreage. The Clearwater D is thicker and better developed centrally and to the west, although it has not yet been tested. Canadian Natural Resources Limited has tested the lower Wabascas to the southeast of our lands. It came on production in April 2024 and peaked at 541 barrels per day.
It's still producing 286 barrels per day as of April 2025 and has a cumulative production of 150,000 barrels to date. They are now preparing a polymer flood pilot from the same pad, and success here will be a strong indicator of secondary recovery potential within the lower Wabascas. Headwater has also tested the lower Wabascas to the northeast, reporting initial rates of 370 barrels per day. Tamarack has plans to de-risk this land base through direct activity. Upon success, the Pelican area could add over 4,000 barrels a day of oil production. Furthermore, with polymer flood or other secondary techniques, there is potential to increase recovery from this asset. In summary, while not yet in our formal development plan, Pelican represents a sizable delineated heavy oil opportunity with clear analog success and line of sight to commercialization.
As activity around us continues and we begin to test the resource, this asset could emerge as a meaningful contributor to future growth. I will now pass the presentation over to our VP Marketing, Rocky Baker.
Thanks, Lynne. Good morning. I'm quite excited about the outlook for Tamarack in the marketing side of our business. We have spent the past few years developing our Clearwater in anticipation of TMX and incremental demand for heavy. We believe the pricing strength that we're seeing right now with WCS is here to stay. I'll bring your attention—sorry. There we go. I'll bring your attention to the graph on the right, which outlines the export capacity as well as the Western Canadian crude production. As you can see, that production is going to surpass egress. Now, I'm not worried about this. I have heard about several developments on pipelines.
Both Trans Mountain and Enbridge have done open seasons for additional egress. They both plan on using DRA, a very cost-effective and efficient way to increase capacity. Trans Mountain also plans to use dredging, which will allow the Aframaxes to fill to full capacity, which again will increase egress. There is also additional dialogue about the utilization of the Canadian portion of Keystone XL, as well as a new pipeline in northern Alberta over to the west coast. We feel that this could bring on an additional 900,000 barrels a day of capacity. You can see the industry is working hard to ensure egress stays ahead of development, and that will support WCS pricing. In tandem with downstream egress, Tamarack has significantly improved our wellhead and transportation deductions through pipe connections on long-term agreements, butane blending, as well as selling our premium-grade Clearwater heavy.
You can see the charts on the left showing the various step changes over the last couple of years. Our regional egress has been coordinated with our development plans to ensure we are producing consistent, repetitive, strong netbacks now and also in years to come. Now, Kevin's going to talk about our return to capital framework.
Thanks, Rocky. All right, returns, our favorite thing. This is our return to capital framework, no changes from what you've seen before. And really, it shows how we think about allocating our free funds flow. So right now, with our CAD 770 million in net debt, we're in the middle column there. So 60% of our free funds flow is going back to shareholders. That is about 20% in our base dividend. The other 40% is going to share buybacks.
You heard Steve talk about our new five-year plan, production per share growth, free funds flow per share growth. That is coming from buying back shares. We are growing the top line, but we are also shrinking the denominator through our buybacks. We are in the middle of our framework. We have been there for a year. We have set a debt target, CAD 500 million, which is one times net debt to EBITDA at a really low commodity price, $45 U.S. We have had this framework in place. It has been working. Let us look back and see how has it gone the last year and a half. Since our debt peaked in 2022, we have paid back CAD 650 million in net debt. We have gone from over CAD 1.3 billion to that CAD 700 million. In the last year and a half, we have bought back over 10% of our shares.
The framework is working wonderfully. Debt's going down, buying back shares. The biggest change since last time we met on Investor Day is that new five-year plan and how quickly we're going to hit our debt target. That bottom left graph is showing how our net debt's going to move over the next two to three years at various commodity prices. At $75, which is our base price, we will be there at the end of 2026, early 2027. If we stay at current prices, $65 flat, we'll be there at the end of 2027. What happens when we hit our debt target? That 60% to shareholders becomes 80%. That other 20%, it may go to net debt or it may go to other growth or other optionality. You heard Scott talk about Clearwater optionality.
You heard Ben talk about the great Clearwater water flood. We have lots of other places we can put that free funds flow. Once we hit our debt target, we can allocate that way. We are thrilled with the framework. It is working. Debt is going down, returns are going up, and it really helps our per share returns. With that, I will pass it back to Brian to wrap it up. What a story you have heard this morning. Just to summarize a few key points here, you have heard about our ability to lower declines and grow production. You have heard about compounding change. The one thing I think you can take away is with our long inventory, large OOIP, water flood response, we are going to be sustainable, predictable for a long time here to come with our free funds flow.
In terms of risk management, when you buy a company's stock, you always wonder, is there something around the corner that I do not see? Major acquisitions or issuing of stock? I think that we have demonstrated in the last couple of years since we bought DeltaStream that we are consistent and predictable, and we have gotten to where we want to be. We talked today about compounding returns to shareholders, that lower sustaining capital. That is a very unique position. Typically, operators drill their best wells first. The declines get steeper as weaker wells get in. The returns get lower as you need more land and more infrastructure to add inventory. That is not the case with a conventional play like we have here at Tamarack with Clearwater and Charlie Lake. You are going to see both of those plays with lower sustaining capital. Production growth, most of the growth will come out of Clearwater.
The debt reduction, that lowers interest costs. That means more free cash flow, again. You are seeing long-term buybacks and us be opportunistic and flexible with how we deal with our buybacks. When you add it all up, you have to take a look at every one of those elements and add it in to get your yield, but you are going to get outsized per share returns. I think, hopefully, we have convinced you today that that is just going to get better over time. The flexible capital allocation, we have a lot of options for capital that I described at the start of it. You have heard how some of those methods can improve the business here going forward.
I think the unique thing you take away from this is that when you have multiple paybacks, not just one or two, but five to, in the case of water flood, many almost decades of paybacks, that payback, it just keeps coming back at you year after year after year, and that is without more capital. That is why you are seeing the business get stronger here. That is why you are seeing debt-adjusted free cash flow per share grow exponentially, as Steve outlined in his plan. One thing that we did not mention in detail here, I want to just give you a quick update on the Wabascans Indigenous Partnership. That is working very well in the field. Our relationship with Indigenous partners is very strong. I am very pleased at the outcome and the large intangible benefits that we are seeing out of that agreement.
This is all underlain by a top-tier OOIP investment and opportunities that we have in our portfolio. I do want to say something about the staff. They'll hear me say our goal really is to become the most profitable company. We don't have aspirations to become a 200,000 or 300,000 barrels a day, but we do have aspirations to become the most profitable. I think we're well on our way to that. I used to say, you know what? There's a lot of terms here. There's a lot of information. It's really a pretty simple business. Production up, cost down. I think we've parlayed that and dissected that for you today. I'll add a third one. Production up, cost down, injection up. That's going to be the mantra for this company.
For all of you in the audience today that did not have a speaking opportunity but employees of Tamarack, I want to thank you. You guys have done a phenomenal job. There is a lot of work that goes behind this stuff and a lot of credit to the staff here that are here today in making this happen. They are very motivated. It is a learning organization. Water flood expertise is really important, and I think we have done a good job in bringing that in and training here going forward. I also want to thank the board for their support here in these endeavors. Could not have been done without them. The other thing I want to say is that there is a couple of folks in the back here, Maria and with some charts there and Mr. Hendricks, and they would gladly go through some technical aspects of the reservoir that we're dealing with and why it's unique. I direct you over there for further questions. With that, I think the next phase is opening up for questions. Is it not, Christine?
Thanks, Ryan. All right. We'll open the floor to questions. For those who are online, if you do have questions you'd like to submit, I encourage you now to put those into the chat portion. We do have a mic that will go around the room. If you have a question that you'd like to bring up, please raise your hand. We'll send a mic over so that the folks who are listening online are able to hear that question.
Thanks. I'm just wondering on the return of capital framework, when you inflect from 60% returns to 80%, will you revisit the base dividend as a proportion of that 80%? And how should we think about the other 20% allocation? Is it possible that that entirely goes towards growth and water flood, or will you continue to prioritize the balance sheet to a degree?
Thanks, Dan. Let's start with that return of capital framework question. We move from the 60% to 80% as we move through that. The 20%, and that's going to go to shareholders. The 20%, really, once you get to your debt target, is pure option. I think what we'd want you to take away from here is we have a lot that isn't in the plan that Lynne talked about, Ellicott and Seal. We have a lot that we're not getting to.
Even we run an eight-year plan internally. You see the five-year plan here today. We would like to accelerate more of that value and bring that value forward. We would see that likely going to more growth. I kind of outlined what that 20% could mean from that free cash at CAD 75 WTI. You could probably add CAD 50 million plus of growth a year coming through without taking anything incremental away from returns to shareholders. The dividend element, the nice thing about buying back stock is that absolute dividend value or payout goes down. We see the dividend as always being a smaller piece. We talked about where our break-even is.
If you increase your dividend, we are in a cyclical business, it is going to drive that break-even higher. We like the fact that through buyback, that can continue to come down. Maybe like we did last year, you see small increases along the way on a yield basis. At the same time, I do not think we will ever see that dividend march materially higher. We will actually see that absolute outlay of the dividend move down through that plan. Does that make sense?
Thanks for taking my question. I was just wondering, your plans run at CAD 75 WTI. How does capital change when we are sitting in a CAD 60 or CAD 65 world? Is CAD 450 million the right number at CAD 60 WTI? The second question I had was you had mentioned some direct drilling at Pelican. I was wondering what the timeline of that is.
Maybe we will start with the capital question here, and then we can move to Ben or Lynne on the timing of drilling at Pelican. At the end of the day, Conrad, sorry, your first question. What was your first question again? Oh, yeah, yeah. Sorry, on the price. The nice thing with the break-even in the low CAD 40, call it even sub- CAD 40 environment, our capital probably does not change that much from that CAD 450 million. You can see even this year, things are running ahead for us from a lower capital, higher production standpoint that we feel pretty comfortable there. Ultimately, at the end of the day, it is ensuring that we are driving the most accretion and maximizing the value of our barrels. We will look to probably prioritize things like the Clearwater where you get those multiple payouts, and you are not just getting that one payout at low price. You are probably doing more Clearwater. The water flood, the nice thing is, you are putting dollars in the ground today that you are not necessarily seeing for a year or so.
Again, you can play that into the cycles. As the sustaining capital moves down, that capital could flex down and still achieve similar levels of growth. I do not see that moving a lot. If you were sub-CAD 60 for a while, we talk about that quite a bit where we would probably then look to flex capital and maybe take advantage then of more buybacks or certain things like that. It is the same thing at high prices. If your share price is higher, you may slow down on buybacks, and you might be paying more debt down quicker there or maybe potentially adding some capital into a play like the Charlie Lake where you do get that one really quick payback and you are maximizing that value there. Ben or Lynne, I would pass it to you for the Pelican question.
Sure. Yeah, with Pelican, there's two different tests we'd like to do there. The first one, the Clearwater, that I think would be something we'd be getting into the next 12 months or so. With the Wabascas, we're going to learn a lot here. There's a couple of things going on. We've got a polymer pilot happening there on a single lateral injection case. We probably don't want to drive too quickly in there until we can maximize our learnings there and make sure we do it the right way. We will probably be more flexible on when that timing is depending on how the play advances from the other industry players.
I just wanted to ask if there is a defensive buyback plan in place that can allow Tamarack to take advantage of periods of high volatility, aggressive drawdowns, something that we've experienced in April, for example.
Yeah, thanks, Wahib. I think rather than using the word defensive, we would use the word opportunistic. Again, our job is to allocate our funds flow and maximize value. For example, we went through a period there in late March and through April with the tariffs, significant sell-off in Canadian energy. We got a lot more active there. Again, we'll be opportunistic with it. You can call that being defensive if you'd like. I do not think at this time we'd use things like an SIB. We have a plan here where we're still reducing debt in conjunction with buybacks, but we have other assets that are non-core that could look to come out. What do you do with those proceeds? That is where certain things like that could come into play for sure. Again, we're going to be opportunistic.
We do not want to be as rigid as what that return of capital framework says at all times. You might get ahead of yourselves at some points in the period of low price and then lay off the gas as your stock improves. Again, we want to leave you with our job is to allocate that funds flow and that capital accordingly. We will be opportunistic with it, specifically with the buybacks.
Thank you. Obviously, you guys have shown some really great water flood success here, good technical presentation today. Maybe on the risk side, what are your signposts here in terms of breakthrough and what are sort of the contingencies or mitigating plans in that case?
Yeah, that one is probably for me. Again, like a lot of these heavier water floods, whether or not it's Brintnell or the Bakken or Sparky plays, often a lot of this recovery is going to happen at high water cuts or high water cuts. We're ready for that. We continue to put our foot on the gas. A lot of this is going to be governed by just throughput at that point. Every day that goes by that we're at these low water cuts is a bonus versus what we're forecasting. We're still managing it conservatively, I'd say, through the plan until we get into these terminal periods of the plan. We're still in what we'd call the pre-breakthrough phase. A lot of that final recovery is dictated after your water cuts are quite high.
Just I'll add to that. I had someone explain to me the difference between risk and uncertainty. I would say the risk is off on these water floods. We've gotten to a point where we've hit some paybacks already. Even if water hit us, you're going to get multiple paybacks off these things quite easily. I think the uncertainty is how many do you get. When you get water breakthrough, how does that affect the number of paybacks? It does affect that. What we're able to do is delay capital on when water comes in, push off some major facility de-bottlenecking, that kind of thing, until we see some indication and get some idea of a forecast of a mulching that we're more comfortable with in sizing the facilities.
There are some reservoir experts that look at this and say, "We're probably not going to see the big shock and ramp up and breakthrough that we're all kind of expecting." I think we've been attuned to people who have tried water flood in unconventional reservoirs. When you get water breakthrough there, it's pretty much done. We're not seeing that in this particular case. Some believe that this reservoir is actually, and core studies indicate that it is oil wet, meaning it wants to grab the water that is near and pull it in and slowly release the oil as opposed to water wet where water flows through and the oil doesn't come that easily. You got to keep cycling. We think that this reservoir has some unique characteristics, and that's why we haven't seen that kind of thing so far.
Yeah, I might add to that as well. What we're seeing from the Clearwater that's making it exceptional, I would say, is how slow the process is. The pressure front is well ahead of the water flood front. A lot of that has to do with the surface area exposed. It's orders of magnitude higher than a vertical well or even a single lateral horizontal well, how much surface area is there. It's almost like you're sweating the water in, and the flood front's moving very slowly. That is partly due to the surface area. It also has a very low relative permeability to water. Those are the two reasons that kind of make this unique. We expect this flood front to progress slowly based on the reservoir simulation we're doing. We're not expecting breakthrough to happen quickly here.
We do have a question online. I'll direct this one to Ben. You mentioned an 11 billion barrel OIP on your lands. What's your best estimate of primary and secondary recovery on this resource? What is currently showing in the engineering report?
The recovery factors on an area basis on a primary sense vary from probably 4-7% recovery. On secondary, again, we're talking about 2-3 times that number for total. We'd be getting into that 15-20% kind of range.
Okay. It looks like that would wrap up our participation for the day. Brian, I'm not sure if you wanted to make any closing comments. I would open the floor to you, and then we'll say thanks to everyone.
Thanks for coming today. Follow-up questions, you're going to have some. We're going to be ready to receive those questions. Also, I realized, and probably the biggest question that Steve and I get when we're on the road is, how do you model water flood? How do you think about these things? We've given some tools today to model that. If you have questions on that particular topic, I think it's pretty important that we be able to answer those questions for you to go through. Next year, what's the theme going to be? We'll see. Maybe it's how if we're going to hit some numbers in 2027 where cash is going to be more available, maybe we'll talk about some opportunities with that. With that, I'll close today. Thank you very much for coming out.
If you have any suggestions or comments on how we could make this day more successful next year, please feed those comments in. We will be kicking around here and walking around. If you want to meet some of the staff, please take the opportunity to do that, especially those young guys in the back there that are our future. Thank you.
Yeah, one more quick one on the reserves. It is about 1% so far on the 2P reserves.