Good morning. Welcome everyone to the Tamarack Valley Energy Ltd. conference call and webcast on Wednesday, February 25, 2026, discussing the recent Q4 2025 results press release. I would like to introduce today's speakers, Steve Buytels, President, Kevin Johnston, CFO, and Ben Stoodley, Vice President, Engineering. If you would like to ask a question, please press Star, then one on your telephone keypad to join the queue. If you would like to withdraw your question, please press Star two. Thank you. Mr. Buytels, you may begin your conference. Thank you, Joanne. Good morning, and welcome everybody to the call to discuss the fourth quarter and full year operating and financial results for 2025, as well as our year-end reserve report. My name is Steve Buytels. I'm the President of Tamarack Valley, and today I'm joined by Kevin Johnston, Chief Financial Officer, and Ben Stoodley, our VP Engineering. This morning, we announced our Q4 and full year 2025 results and our 25 year-end reserves and an operational update. 2025 was a record-setting year for Tamarack, with a focus on continued rate of change in the business to further enhance the overall profitability and maximize shareholder value and per share results. We completed our multi-year transformation into a Clearwater and Charlie Lake oil producer, and our asset portfolio is now exclusively focused on some of the most profitable conventional oil plays in North America, as evidenced by our strong financial and reserve results. The team delivered an exceptional 25 from an operational standpoint, which resulted in two positive guidance revisions through the year, with capital coming in at the low end of our guidance through efficiency gains, while production significantly outperformed, even after adjusting for M&A through the year. On the back of strong drilling results in both the Clearwater and Charlie Lake and strong response across our waterflood program in the Clearwater. Further, corporate costs came in below guidance, highlighted by a 17% year-over-year reduction of net operating expenses as we continue to execute margin enhancement opportunities across the business. The culmination of these efforts drove free cash flow of approximately CAD 390 million in the year. Shareholder returns were a key focus, with the company repurchasing approximately 36 million shares, or 6.9% of the 2024 year-end share count, at an average price of approximately CAD 5 per share. In addition, we increased the dividend by 5%. In total, we returned CAD 262 million to shareholders in 2025 between share buybacks and the base dividend. When we add the buybacks, the base dividend, production growth, and debt repayment together, we delivered a total return for shareholders of approximately 19% in the year. Portfolio optimization and the continued investment in waterflood has had several material benefits to Tamarack. If we compare our 2023 to the midpoint of our 2026 guidance, our corporate base decline rate is 13 percentage points lower. Our sustaining capital to keep production flat is approximately 30% lower, and our net operating expenses on a dollar per BOE basis is approximately 25% lower. Collectively, we estimate this has reduced our U.S. dollar WTI breakeven price by approximately $8 per barrel since 2023, with our 2026 corporate sustaining free funds flow breakeven of less than U.S. $40 a barrel WTI, excluding hedges, or approximately $35 U.S. per barrel WTI, including our hedge program. We have positioned ourselves as the largest public Clearwater producer, with over 12 billion bbl of original oil in place. We continue to expand our land holdings in a play which grew by 25% in 2025 to now over 850 net sections, and they hold over 2,100 primary locations across our land base. This implies greater than 25 years of drilling inventory across the stacked horizons, not accounting for any future success in the Wabasca formation in the Pelican region. In addition, the waterflood provides significant recovery upside in the Clearwater, where we see the application doubling, if not tripling primary recovery. We currently have between 10%-15% of our Clearwater acreage under waterflood, with a significant runway remaining. We believe we have an advantage business model that stands out across commodity cycles, given the unique ability to show top-line production growth, while at the same time reducing our corporate decline through waterflood, which in turn lowers our reinvestment requirements. This allows us to compound and grow free funds flow through the plan, even at low prices. I'll now turn it over to Ben Stoodley, our VP, Engineering, to walk through our 2025 year-end reserves report. Thank you, Steve. I'll begin with a summary of Tamarack's 2025 year-end corporate reserve performance, followed by a discussion of our Clearwater reserves and resources. To start at a corporate level, Tamarack delivered meaningful and capital-efficient reserves growth across all categories in 2025. Proved developed producing or PDP reserves increased by 31% year-over-year. Total proved reserves grew by 26%, while total proved plus probable reserves increased by 18%. When excluding reserves and production associated with acquisitions and divestitures completed during the year, total proof plus probable reserves increased by 30%, resulting in 413% production replacement. This performance was driven by the continued successful deployment of secondary recovery in the Clearwater, combined with strong, repeatable results in the Charlie Lake. These operational outcomes were further enhanced by our ongoing share buyback program and continued net debt reduction. On a per share basis, debt-adjusted reserve volumes also showed strong growth, increasing 42% on a PDP basis and 28% on a total proved plus probable basis year-over-year. From a cost perspective, 2025 PDP finding and development costs were CAD $8.09 per BOE. Total proved costs were CAD $8.01 per BOE, and total proved plus probable costs were CAD $7.93 per BOE. With a 2025 field netback of CAD $41.71 per BOE, Tamarack generated corporate recycle ratios exceeding 5 times across all reserve categories. Turning now to the Clearwater. Reserve growth in 2025 was particularly strong. PDP reserves increased by 63%, total proved reserves grew by 64%, and total proved plus probable reserves increased by 56% year-over-year. Finding and development costs across all reserve categories averaged approximately CAD $7 per BOE, enabling the Clearwater assets to generate recycle ratios of approximately 6 times across each category. Reserves replacement was 256% on a PDP basis, 401% on a total proved basis, and 534% on a total proved plus probable basis. Notably, waterflood-related PDP reserve additions achieved finding and development costs of less than CAD $3 per BOE. PDP reserves under waterflood expanded by 300% in 2025, while only 37% of total Clearwater reserves are currently assigned to waterflood development. Collectively, these results underscore the scale, quality, and long-term value of Tamarack's Clearwater asset base. In addition to booked reserves, Tamarack continues to expand its resource inventory. As of December 31, 2025, the company held 115 million bbl of best estimate gross unrisked contingent resources in the Clearwater, representing an 8% increase from year-end 2024. Gross unrisked prospective resources totaled 104 million bbl, a 6% increase year-over-year. As Steve mentioned, Tamarack has identified approximately 2,100 net drilling locations, of which 520 are net booked locations, at our current pace of primary development, this represents more than 25 years of drilling inventory. Operationally, activity in the Clearwater remained robust throughout 2025. During the year, Tamarack drilled 94.3 net horizontal heavy oil wells for primary development in the Clearwater Fairway. In support of waterflood expansion, we also drilled 25 water injection wells, drilled two source water wells, and converted 16 producing wells to water injectors. Waterflood response continues to build, with heavy oil production uplift now estimated at more than 5,000 bbl per day, representing approximately 10% of total Clearwater production. Tamarack exited 2025 with water injection rates exceeding 40,000 bbl per day, nearly three times the rate at the end of 2024. Looking ahead, we plan to increase water injection to approximately 60,000 bbl per day by the end of 2026, with roughly 35% of Clearwater oil production under Waterflood, compared to approximately 24% today. Waterflood capital expenditures in 2026 are forecasted at CAD 100 million, representing a doubling relative to our capital expenditures in 2025. In addition, Tamarack plans to drill two de-risk wells in the Pelican area in 2026, one targeting the Wabasca and one targeting the Clearwater. Finally, turning to the Charlie Lake. In 2025, Tamarack drilled 13.8 net wells and brought 16.8 net wells on stream across the Wembley and Pipestone areas. The Charlie Lake generated approximately $190 million in asset-level operating netback and $70 million in asset-level free net operating income during the year. Tamarack's recently drilled 114 of 9 well in Wembley, has achieved, or in Pipestone, has achieved an IP rate of 1,400 bbl per day of oil and 2,000 bbl of oil equivalent per day. During the fourth quarter, Tamarack successfully redirected production to a new third-party CSV Albright gas plant and the AltaGas Pipestone II gas plant expansion. With access to both owned and third-party processing and egress capacity, Tamarack retains significant capital allocation flexibility to support ongoing operations, sustain production, and enable potential future growth in the Charlie Lake. For 2026, we plan to maintain a flat exit rate production profile of a 1-rig program, drilling approximately 10 wells across Pipestone and Wembley. Kevin Johnston, our CFO and VP Finance, will talk through some of our 2025 operational and financial highlights in more detail. Thank you, Ben. 2025 was a very strong year for Tamarack. Fourth quarter production averaged 68,635 BOE per day. This represents a 4% increase over the fourth quarter of 2024, and a 9% increase if we exclude the impact of 4,000 BOE per day of non-core production that we divested in mid-October. Clearwater production was approximately 50,000 BOE per day in the quarter, a 16% increase compared to the same period in the prior year. Charlie Lake produced 17,600 BOE per day, a 4% increase from the same period in the prior year. Average corporate production for the full year of 2025 was 68,176 BOE per day, which represents growth of 6% from the prior year. This was in line with our revised 2025 guidance of 67,000-69,000 BOE per day of average annual production, and was above our initial 2025 guidance of 65,000-67,000 BOE per day, which we had provided when we released our budget in December 2024. This is notable because Tamarack's collective A&D activity throughout the year resulted in a net disposition of production volumes, and our original capital program was decreased by over 10%. In Q4, Tamarack delivered adjusted fund flow of CAD 172 million, capital expenditures of CAD 99 million, and free fund flow of CAD 71 million. For the full year of 2025, Tamarack generated CAD 390 million of free fund flow, or CAD 0.78 per basic share. Free fund flow per share increased by 10% year-over-year, despite WTI prices averaging 14% lower in 2025. Tamarack returned CAD 262 million to shareholders in 2025 through base dividends and share buybacks. Long-term share buybacks allow us to compound organic free fund flow growth into per share returns. Tamarack invested CAD 400 million in capital expenditures in 2025, at the low end of our revised guidance of CAD 400 million-CAD 420 million, that was an 11% reduction from 2024. This reduction reflects the impact of capital efficiencies from multi-well pad development, improved runtimes, and reduced sustaining capital from strong base and waterflood performance. Net operating expenses declined 17% year-over-year to CAD 7.43 per BOE, reflecting the impact of infrastructure investments, lower water handling costs and waterflood reinjection, higher production volumes, and portfolio optimization from the divestment of higher cost non-core assets over the last two years. Tamarack made 2 positive revisions to guidance for net operating expenses in 2025. Full year expenses of CAD 7.43 was still below our revised guidance of CAD 7.75-CAD 8.00 per BOE. Tamarack is forecasting a run rate net operating expense of CAD 7.00 per BOE in 2026 at midpoint, which represents a 25% decrease compared to 2023. Tamarack achieved its net debt target of 1 times net debt to EBITDA at a USD 50 WTI oil price in Q4 of 2025. Tamarack will focus on allocating additional free fund flow to shareholder returns through share buybacks in 2026. Long-term share buybacks continue to be the preferred mechanism for returning capital to shareholders. We repurchased over 32 million shares in 2025 and reduced our share count by 6.9% from the previous year end. Since beginning the share buyback, NCIB program, Tamarack has repurchased over 12% of its 2023 year-end share count, with over 70 million shares bought back at the end of January 2026. Our President, Steve Buytels, will provide our closing remarks for the call. Thanks, Kev. Tamarack continues to be differentiated by the scale and quality of our assets and our ability to generate growing per share returns, even at modest commodity prices. With a break-even WTI oil price of less than US $40 per barrel WTI, a corporate base decline rate of 22%, a low-cost structure, and low sustaining reinvestment requirements, Tamarack is very well positioned to generate sustainable shareholder returns. As we look to 2026, we remain focused on maximizing shareholder value through a combination of organic growth, further waterflood investment, share buybacks, and continued debt repayment. Our mantra of delivering more for less and a continued focus on driving growth and free fund flow per share through lower reinvestment requirements, organic growth, and the compounding elements of the buyback, positions us in a unique way to drive outsized returns. On behalf of both Brian and myself, I would like to congratulate our team on a truly remarkable year. We would like to thank our board of directors, employees, stakeholders, and shareholders for their continued support. Thank you. I will now turn it back to the moderator for questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touchtone phone. You will hear a prompt that your hand has been raised. If you would like to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. The first question comes from Jeremy McCrea from BMO Capital Markets. Please go ahead. Yeah, thanks, guys. Two questions here. The first one is: when you look at all your waterflood responses so far, how many are coming in above expectations versus or if any are coming in below? I'd be curious, actually, if something comes in below. How does this impact the way we should think about your guidance here, you know, going forward? Yeah, thanks, Jeremy. I would say, of course, there's some outsized responses in the short term here, where we see these very dramatic IP rates coming in. We've held our EURs pretty standard, though, through that period, tying to the simulation results. I think in general, we're really in line on an EUR and reserves basis with where we would expect outside of these really outlier, kind of quick response, high response wells. Okay. Maybe just a bit more of a follow-up question here, just on some of the new land and exploration. Is any of those potential well results in your guidance? I'm just thinking if there's some success with the Wabasca and you decide to go for some quick follow-up wells, is that in potential guidance? Like I'm trying to think of where we could see some upside here related to what you've put out for guidance here for today. Yeah. No, thanks, Jeremy. It's Steve here. I think following on what Ben talked about, we obviously simulate on our flood results. I think we've been pretty consistent with what we've seen in aggregate. To Ben's point, we are seeing in certain circumstances, more in the Martin Hills area with the stack patterns and even those W patterns with the results that are coming through the public data. Those are probably a little bit ahead in terms of some of that response to IP. I would say that's one place we continue to see some positive momentum. The other place, too, that we didn't talk a lot about today, was even just on the primary well results, and we put it in our presentation, we did see a nice increase in the base outperformance of those primary wells in certain areas as well. You're seeing lower primary declines, or you're just seeing some of these wells with time outperform what our recovery and our reserves estimates would have been. There are those things that I think are still going on, and that's one of the beautiful things about being in the core, in the heart of the play within Martin Hills and West Martin Hills and Nipisi. When you ask about what's not in the plan or some other potential upside, we have the capital in our plan with respect to going to drill at Wabasca well at Pelican, as well as testing the Clearwater there. You saw that we added incremental acreage in Q4. We really like that area, as we build that out to be potentially another core focus for us, where you could drive. I'm gonna use a wide range here, depending on how things go, That could be 5, 6, 7 to 10,000 barrel a day development plan, potentially with success over time. We'll drill these wells in the second half of the year, and then there's a lot of competitor activity also going on that will help de-risk some of those lands and provide some more color on those lands in terms of what that upside could be. I just wanna make sure we're clear that we don't bake any of that upside into our current plan here today. That would all be- Okay. That would all be on top of it. Okay. Yeah, no, that's what I was trying to get at here. No, that's. Thanks, Steve. You bet. Thank you. Ladies and gentlemen, as a reminder, if you have any questions, please press star one now. We have no further questions on the phone. I will turn the call back over to Tamarack for online questions. Thank you. Our first question online is for Mr. Steve Buytels. Congrats on a great year and exciting upcoming activity. For the Pelican area, are the two de-risking wells in 2026 going to be drilled in the newly acquired lands or legacy lands? Yeah, that's a good question. We will drill one well on our legacy lands, and then we will drill one well, or our plan is to drill one well on our newly acquired lands. Again, what I would preface that with is there is a lot of competitor activity, both in the Wabasca and in the Clearwater, that is around us there. We'll look to build off some of that and see some of that data through the first half of the year, that'll help inform exactly what we're gonna do here in the second half and which locations we choose to go after. Thank you. Our next question is for Mr. Stoodley. Tamarack quotes 12 billion bbl of oil in place in the Clearwater, with potential reserves and resources at approximately 400 million BOE, implying a roughly 3% recovery factor. What could see this recovery factor increase, and what has analog heavy oil resources typically recovered? Yeah, I think our, like, purpose of showing the reserves and resource report and is to show how we've been successful in growing that, both those or all three of those categories. Doing that through inventory additions as well as delineation of our inventory on the waterflood and promoting it through those, through those categories. It is a relatively low number there as far as recovery goes on that. That will continue to grow as we delineate. When speaking about other heavy oil resources, especially under waterflood, we see about 70% of our OOIP sitting in areas that are currently proven for waterflood. When I look to other pools and other examples, they typically have a tremendously long life. There's many examples that, you know, started, you know, in the 50s and 60s, that are still producing today. Recovery factors there get, you know, 25% - 40% in a lot of cases, in the successful cases. We see the Clearwaters being a very successful case at this time, but we're in the early innings of actually being able to predict where this goes in the long term. We see it as there's quite a bit of upside on that recovery factor as we go forward. Thanks, Ben. One thing I would add here, just Steve, I talked about it in my opening remarks. We talked about OOIP there, and the recovery factors associated with that in terms of the waterflood. I think the other thing that we should talk about, too, and make sure we're clear on, is when we think of our total land base that's amenable to flood that we know works today, and this doesn't include the areas of the South Clearwater or Pelican or things like that would all be incremental to this. We only have between 10%-15% of our lands under flood. When you think about the runway, Ben talked about recovery factors, but we're still so early just in terms of building out the runway and the duration of really where we're gonna take this flood through the core areas of Nipisi, West Martin Hills, and Martin Hills. That's another thing to think about, too, when we look at this, aside from the recovery factors, just in terms of the amount of runway that we still have in front of us and have to get after. Thank you. Our next question is for Mr. Steve Buytels. On your waterflood projects in the Clearwater, have you seen any areas or patterns that have demonstrated water breakthrough thus far? When would you expect it to occur, and might it mean for oil rates in the play? One thing I wanna be clear on, breakthrough should not be a surprise when it comes to heavy oil waterfloods, and Ben can add here when I get done, but it's going to happen. This is factored into our simulation and our decline estimates that we've put out for everybody. I wanna make sure that that's clear. There is no surprise there. The other thing, most heavy floods, when we think of the analog floods that we would use here, 60% of the recovery happens at high water cuts or post-breakthrough. We gotta remember that. We're still. Ben talked about being in the early innings. You're gonna see water cut increases and all of those things. It's more about are you set up and able to handle that. When you think about it, over the last couple of years, we've put a lot of investment into infrastructure. Kevin talked about what that's done for our OpEx, but it's also about being ready to handle incremental water volumes and water cuts at our facilities. This year, in Q3, we're expanding and putting in a bigger water plant at our 15-15 facility in West Martin Hills. We've expanded and continue to do work at our 15-22 facility in Nipisi to handle the growth of the waterflood there in terms of we're gonna be putting in a bigger free water knockout, treaters, et cetera. Last year, in the third quarter, we went through and expanded our water handling facilities and our water plant at our Martin Hills 11-4 facility. We are ready to handle, when they come, bigger cuts. Again, this should not be panic, and this should not be any surprise to anybody. The other element of it is when you do see incremental water cuts, what do you do and how do you handle it? We have a lot of experience with heavy floods within our technical team here, you're gonna look at upsizing pumps and managing fluid rates. There are good examples of where we've seen higher water cut, patterns in the Clearwater, where then you're upsizing pumps, you might be reducing injection for a point in time to get your oil rate back up. We do not see it as an issue, and there's lots of cases and experience here through the other heavy floods where you continue to be able to produce at a good rate and a very low decline for a long, long time. You just are dealing with higher water cuts. The last thing that I'd maybe have Ben talk on is, we are designing our patterns for waterflood. When we think about spacing and we think about managing the different viscosities and so forth, in the play, we are setting up our patterns and our well designs to maximize the recovery and obviously deal with the injection and what we see there ultimately in terms of how we're gonna handle that. Ben, maybe, I don't know if you wanna touch on anything further there, but- I think the only thing, couple of things I would add is when you do start to see more water show up, you see incremental total fluid show up as well, the actual oil production is, you know, really sustains a plateau or a very shallow decline through a long stretch. Some of the analog heavy oil stuff that I spoke about, especially the longer-dated stuff, they would have seen breakthrough back in, like, the early 1960s and have declined, you know, 5% to 7% for a long stretch following that. That's, I think, what you can expect following the breakthrough. As it comes through the field, there's just sustained shallow decline production there, as we start to process more fluid. Thank you. Our next question is for Mr. Kevin Johnston. With your 2026 budget press release in December, Tamarack mentioned it was going to allocate additional free funds flow to share buybacks now that Tamarack had reached its debt target. Under the previous framework, Tamarack was allocating 60% of free funds flow to shareholders. Going forward, approximately what percent of free funds flow should we expect to be allocated to shareholder returns? Yeah. Our guiding principles are to maximize per share value and total shareholder returns across the commodity cycle. You know, these principles give us greater flexibility to allocate capital, depending on the environment, especially now that we've hit our debt target of 1 times debt to EBITDA at a $50 WTI oil price. You know, in the current environment, we're modeling kind of, you know, greater than 60%, so 70%-90% this year. We are gonna be flexible depending on the environment we're in. Thank you. We have no more questions online, and I'll pass it back to Steve Buytels to end the call. Thanks. I would again just like to reiterate our true appreciation to our team here internally for what a year they had. It really truly was an outstanding year here for us, both from a financial and operating standpoint. That really was culminated through what the reserve report was able to demonstrate in terms of the overall profitability of the business. With that, again, we'd like to thank everybody. We appreciate everybody's time and support, and I will pass it back to the moderator to close off the call. Thank you. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.