Good morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources Investor Day. Note that all lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star then number one on your telephone keypad. If you would like to withdraw from the question queue, please press star then the number two. And I would like to turn it over to Whitecap's President and CEO, Mr. Grant Fagerheim. You may begin the conference. Thanks, Sylvie. Good morning, everyone. We are excited to walk through our asset base, the work our technical and support teams have been doing, and why we're confident into the future with the opportunities we have in front of us. I am joined today by six members of our management team: Thanh Kang, our Senior Vice President and CFO, Joel Armstrong, our Senior Vice President, Production and Operations, Dave Mombourquette, our Senior Vice President, Business Development and Information Technology, Joey Wong, our Vice President, Unconventional Division, and Chris Bullin, our Vice President, Conventional Division, and Travis Tweit, our Vice President, Operations. Before we begin, a quick reminder that today's discussion includes forward-looking information, and all statements are subject to the same forward-looking disclaimer and advisory contained in the Investor Day presentation, which we have posted on our website, so let me start with what we're going to cover today. First, I'll walk through a high-level overview of Whitecap, including how we think about capital allocation, leverage, and an overview of our portfolio. From there, we'll move into the assets and what we're excited about to continue developing and improving both our design and execution across our business. We'll split the asset discussion into two major parts. Joey Wong will lead the unconventional section, Chris Bollen will lead the conventional section, and Travis Wright will highlight our operational achievements across both divisions. In the unconventional section, the focus will be on our inventory depth, duration, and optionality we have across commodities, including illustrative project scenarios that highlight economics and flexibility. In the conventional section, the focus will be on asset stability and longevity and maximizing resource capture across our light oil-weighted portfolio. We've built a proven platform, and we believe these assets can continue delivering strong profitability and value creation for decades to come, and finally, I'll walk through the growth optionality and asset potential we see across our full portfolio over the next several years before wrapping it up and opening the line for questions, both through the webcast and by phone. With that, we'll get into the presentation. At the highest level, our strategy is straightforward. We allocate capital with one purpose: to generate strong, durable returns for shareholders. Today, we want to show you why Whitecap stands out not just compared to other energy companies, but also compared to alternative investments more broadly. Our advantage comes down to four things: high-quality inventory with both depth and commodity optionality, technical excellence and strong execution, capital discipline to protect and compound shareholder value, and a strong balance sheet to manage risk and stay flexible through cycles. First, on inventory. Our depth and optionality gives us confidence in our ability to generate consistent, meaningful returns even through commodity price cycles. But inventory alone is not enough. The profitability of any energy asset depends on how well we drill it, complete it, and operate it. That's why we believe our technical and operations teams provide us with a core competitive advantage, and they continue to find ways to improve well performance and reduce costs across all areas of our business. Finally, capital discipline and balance sheet strength are what allow us to manage risk, protect shareholder value, and stay countercyclical, especially when additional opportunities emerge in the market. Those four pillars, inventory, execution, discipline, and balance sheet, are what drives Whitecap's strategy. With that, we'll now get into the presentation. For those of you who may be newer to the Whitecap story, here's who we are today. We are a $14 billion market cap company with $17 billion of enterprise value. We produce about 372,500 BOE per day, making us the seventh largest Canadian oil and natural gas producer. On the natural gas side, we produce 900 million cubic feet a day, which ranks us the fifth largest gas producer in Canada. In 2026, we plan to invest between $2-$2.1 billion in capital. At $60 WTI and $3 AECO price, that generates approximately $3.3 billion of funds flow. Our balance sheet remains very strong with CAD 3.3 billion of net debt, which is only one times debt to funds flow. We pay a CAD 0.73 per share annual dividend, representing a yield of just over 6-6.5% at today's share price. Why own Whitecap? Our goal is simple: to deliver meaningful shareholder returns through both per share value growth and consistent return of capital. Our annual target is to provide a 10-15% annual total return to shareholders. And on the next slide, we'll walk through how we plan to do that. These returns are powered by the asset base that we've built over the last 16-year period of time. It is long duration, high quality, and offers real commodity optionality across both our conventional and unconventional assets. Today, we have 10,500 drilling locations in inventory and 2.3 billion BOE of 2P reserves. That's our foundation for delivering returns sustainably over the longer term. Equally important is our balance sheet. We operate with investment-grade credit. We target to leverage of one times or under, and we run a fully funded model, which gives us flexibility and resilience through the cycles. And finally, scale matters. We invest roughly C$2 billion per year in capital and C$1.5 billion per year in operating costs. This stability of capital allows us to secure preferred crews, rigs, and pricing. As the seventh largest Canadian producer and the largest landholder in the Alberta Montney Duvernay, our scale creates efficiency, improves execution, strengthens margins, and ultimately improves shareholder returns. Our capital allocation toolkit. Although we began our journey in 2009 as a growth-only entity, Whitecap has been running a dividend-plus growth model since 2013. And what we've learned is that strong shareholder returns aren't driven by one single mechanism. They come from having a discipline toolkit and optimizing it through ever-changing price cycles. Our toolkit is built around four levers: investing in the business when the return is available and there, maintaining balance sheet strength, share repurchases, and our dividend. We've assembled an outstanding asset base, and using the asset base to generate more free cash flow is one of the best ways to create long-term value for shareholders. While the market may not be calling for growth today, our portfolio is positioned to generate high-return growth when price returns, and we will remain disciplined about this. Balance sheet strength has been central to Whitecap's success. Low leverage gives us the ability to weather downturns, but just as importantly, it allows us to take advantage of opportunities that others can't when the time is appropriate. That is how we built much of our Montney and Duvernay position, including funding the XTO acquisition in 2022 with all cash and taking on Veren's higher leverage company in 2025. And since then, we've driven down costs, improved overall execution, and increased profitability, all of which have translated into stronger shareholder returns. On share repurchases, we prioritize using this tool when our share price is below intrinsic value and our after-tax cost of debt is lower than the cost of equity. And we like buybacks because they permanently strengthen the capital structure and improve our payout ratio. Finally, our base dividend is foundation, stable, and meaningful at CAD 0.73 per share annually. Over time, our plan is to grow the dividend as well. But given where our payout ratio is today, we expect incremental return of capital in the near term to be more weighted towards share buybacks. Countercyclical approach. How do we deploy capital across the toolkit? It depends primarily on commodity prices and where we are at in the pricing cycle. This slide shows how our priorities shift through different commodity environments. The key point is our ability to be countercyclical comes from three advantages: low leverage and a strong balance sheet, high-quality, long-duration inventory in both light oil and natural gas, and a low-decline, low-cost structure that generates free cash flow across all points in the cycle. With these attributes, we have the flexibility, which allows us to consistently generate long-term returns. Now, I want to be clear. This slide is illustrative. We are not formulaic. At any given time, the right decision depends on valuation, commodity price direction, operational constraints, and market optionality or opportunity. But the concept is straightforward. In the lower price environments, as we are in now, there's usually no market call for growth. The priority becomes maintaining base production and returning excess funds flow through share repurchases, especially if shares are trading below intrinsic value. As prices rise towards mid-cycle, we reinitiate growth and balance shareholder returns between buybacks, dividend, and balance sheet strength. When prices move above mid-cycle and economics support it, growth moves higher in priority. Still, within our corporate growth range of 3%-5% per share, and excess funds flow is directed towards strengthening the balance sheet and building dry powder for future opportunities. Again, we won't be rigid with this strategy, but instead adaptive to the prevailing market conditions. This framework helps investors understand how we think about allocating free funds flow through the commodity price cycle. With this, I'll pass it on to Thanh for a quick discussion on our balance sheet. Thanh? Yeah, thanks, Grant. We entered 2026 with a very strong balance sheet, low cost of funding, and approximately 50% of our net debt at a fixed interest rate. We're comfortable with the current mix, but if rates continue to trend favorably, we could potentially look to add additional fixed-rate debt to further enhance stability. In 2026, we plan to use room on our credit facility to address the private placement notes maturing that year. Beyond that, we have four issuances of investment-grade notes with maturities spread between 2028 and 2034. Our most recent bond issuance was at 3.76%, and our variable cost of debt on the credit facility is around 4%. Overall, our debt costs remain very reasonable and contribute to our low-cost structure. You may see quarterly fluctuations in net debt due to the seasonal nature of our capital program. But given our strong balance sheet and the current commodity environment, our focus is on enhancing shareholder returns, particularly through share repurchases, rather than aggressively paying down debt today. Over time, as prices increase, we expect the focus to shift towards reducing leverage further and building additional dry powder for future inorganic opportunities. And to maintain flexibility, we will continue targeting one times debt to funds flow or less. Slide 10 shows the evolution of the business over time. In the earlier years, we were comfortable running higher leverage while we built the company. But over the last several years, especially through acquisitions like NAL, TORC, XTO, and most recently Veren, we've made a deliberate shift towards maintaining leverage at approximately one times. That discipline is what allowed us to execute the TORC transaction and absorb their higher leverage while still maintaining a strong credit profile. Looking forward, we expect leverage to continue trending down over time as we free funds flow and maintain disciplined capital allocation. And with that, I'll pass it back to Grant to close out on the introductory slides. Thanks, Thanh. Asset overview. All of our assets are located within Western Canadian Sedimentary Basin, with over 99% of our production and inventory in Alberta and Saskatchewan. We have significant inventory depth with decades of drilling inventory at our current pace. We divide the business into two primary groups. First are unconventional assets, Montney and Duvernay. These are high-rate, high-reserve resource-style developments with 4,700 drilling locations in inventory and a significant growth in free cash flow potential. Second are conventional assets across multiple regions and formations, primarily focused light oil. these assets include long life, low-decline, low-decline production, and enhanced oil recovery projects. They generate stable, durable cash flow and provide long-term sustainability for the business. Overall, our commodity mix today is approximately light oil and condensate, 10% liquids, and 40% natural gas. Slide 12, our development progression. Slide 12 shows how we think about development progression across our portfolio of opportunities, along with the maturity of assets within each division. The key point is this: not all inventory is meant to do the same job at the same time. We deliberately segment assets into three categories: appraisal and delineation, number one, number two, growth, and number three, stabilized assets. Each category plays a different role in our team's focus on maximizing value as assets move along the progression. Appraisal is about replenishment and long-term sustainability. Growth assets are where we drive our 3%-5% production per share growth annually, and stabilized assets generate significant free cash flow, supporting dividends, buybacks, and balance sheet strength. The majority of the makeup of our conventional assets fall into the stabilized category, but that does not mean that they're near end of life. These assets are well understood, remain highly profitable, and we have decades of runway with meaningful upside that we'll talk about later in the presentation. Our conventional assets are balanced across three categories, and they contain the asset of the projects that will contribute most to our long-term growth. A great example is Kaybob Duvernay play. It has progressed rapidly through growth stage and is nearing current capacity. Through debottlenecking of our 15-07 complex, we've increased capacity, and we're positioned to transition into a stabilized, strong free cash flow developing asset. We're especially excited about that, given the inventory enhancement we've wine rack development initiatives. across the remaining growth and appraisal categories, we have inventory across the commodity spectrum, and we'll highlight the optionality and future potential throughout the rest of today's prese ntation. I'll now pass it off to Joey Wong to walk through our unconventional division. Joey. Thanks, Grant. Now we'll transition into the unconventional division, where we see some of the strongest long-term growth free funds flow potential in our portfolio. There are three key takeaways from this section. First is inventory depth. This division holds the largest share of our long-term growth runway. Second is technical improvements. We've made meaningful progress in development, planning, and execution, and that progress continues to compound. Third, commodity optionality. We have a portfolio that gives us flexibility light oil and condensate, liquids-rich gas, and lean gas, and we can scale that activity based on market signals. This slide highlights the scale and quality of our unconventional asset base. We hold approximately 1.5 million acres of Alberta's Montney and Duvernay, and that makes us the largest landholder in both places. The division produces roughly 245,000 BOEs per day and delivers approximately $900 million of free funds flow at $60 WTI and $3 AECO. Importantly, the assets are concentrated, which drives efficiency, repeatability, and cost control. That concentration is a key advantage. It improves execution and supports stronger margins. Slide 15 shows our unconventional type curves and the quality of the inventory across the portfolio. We have a high-quality, scalable inventory across the commodity spectrum, and that gives us flexibility and resilience through the cycle. At one end, we have light oil and condensate growth options, where liquid pricing and condensate yields create very strong margins and attractive returns. The oil and condensate window is defined as greater than 250 barrels per million of standard cubic feet of natural gas on an IP90 basis. On the other end, we have lean gas assets, and these are important because they represent a long-dated growth lever. Lean gas becomes very competitive in stronger gas price environments, and we've positioned those assets so that we can scale efficiently when gas prices justify it. The lean gas window is defined as less than 50 barrels per million. And in between, we have liquids-rich gas opportunities. These deliver strong rates, strong economics, and fast payouts. What we want you to take away from this slide is that our unconventional portfolio isn't tied to one commodity outcome. We can allocate capital to the projects with the best returns at the time, and that flexibility is one of the reasons we believe we can deliver durable shareholder returns through the cycle. The other advantage here is that we've been able to improve these type curves through design and execution, which we'll show later in the section. These are not static assets. Our teams are actively improving performance. Moving into more detail, let's start with the Duvernay position at Kaybob. The Duvernay is one of the premier unconventional resource plays in North America, and for Whitecap, it's a major value driver because it combines scale, strong well performance, and a near-term pathway to significant free funds flow. we are the largest landholder and operator in the Duvernay, with approximately 500,000 acres and about 700 identified locations. Roughly half of that inventory is liquids-rich, with another 40% weighted light oil and condensate. With over 500 producing wells, we operate roughly the same number of Duvernay wells as the next two operators combined. That scale delivers real advantage, operating efficiencies in the field, and equally important, one of the strongest proprietary data sets in the play. It drives better development planning, sharper execution, and ultimately superior economics and returns. Geologically, our Kaybob Duvernay position has some of the most favorable characteristics for development. The reservoir is thick, laterally extensive, overpressured, and predominantly liquids-rich or condensate-prone. Porosity is predictable across the area, and while thickness varies across the land base, we adjust our development plans accordingly. Where we see greater thickness, wine rack-style development to improve vertical reservoir coverage and reduce interaction between wells. Where thickness is more limited, we widen interwell spacing and utilize longer frac half lengths to enhance capital efficiency and maximize value per well. We'll speak to these design choices and the resulting performance in more detail in the coming slides. When we first entered the Duvernay in 2022, we were excited about the runway in front of us, supported by our owned and operated 15-07 gas plant, which at the time was only 50%-60% utilized. As development progressed and results continued to improve, it became clear that we were approaching the facility's capacity limit, one that would have been reached in 2025 as our development initiatives continued to bear fruit. To create additional runway and enhance economics, our team increased the productive capability of the 15-07 complex through a combination of facility debottlenecking and the construction of a connection to a third-party processing facility. This work increased the productive capability of the complex to over 50,000 BOEs per day, an increase of over 40% from the original productive capability of approximately 36,000 BOEs per day. This additional capacity not only supports our development plans, but it also drives a structural improvement in netbacks, with operating costs expected to decline more than 30% as we approach capacity. We expect the final stage of these efforts to come online in early 2026. Following further debottlenecking and expansion on the north side of the asset, the Kaybob Duvernay is expected to reach total processing capacity of approximately 120,000 BOEs per day by the third quarter of this year. Once we achieve that capacity, our intent is to hold production in the 115,000-120,000 BOE per day range longer term and transition Kaybob away from the growth phase and into a stabilized at-capacity mode, as Grant mentioned earlier. At that stage, Kaybob is expected to generate approximately CAD 650 million-CAD 850 million per year of asset-level free cash flow while requiring only 50%-55% reinvestment to maintain flat production, providing a significant source of sustainable free cash flow to the corporation. This is exactly how we think about asset development: scale the resource, optimize the infrastructure, debottleneck constraints, and then transition into a free funds flow phase where cash flow can then be returned to shareholders. Next, we'll turn to the Montney, which offers one of the deepest sources of long-dated organic growth in our portfolio, with development opportunities across the full commodity spectrum from light oil and condensate to liquids-rich and again lean gas. Slide 21 provides an overview of our Alberta Montney position, which, as mentioned at the outset, is the largest by land holdings with approximately one million acres. This is a large, high-quality asset base with meaningful existing infrastructure, and it provides several distinct development options with a mix of light oil and condensate, liquids-rich gas, and lean opportunities. This is important because it gives us optionality, but we want to be clear: development will remain disciplined. We will scale activity only when returns justify it and within our broader corporate capital allocation framework, so the Montney is both an opportunity set and a tool. It gives us a way to respond to commodity price signals while maintaining capital discipline. The Montney is a thick, stacked, and highly predictable resource with meaningful commodity diversity, making it increasingly attractive to both investors and operators seeking premium, long-dated inventory. We have strong visibility across multiple benches, supported by extensive 3D seismic coverage and a large data set of industry and operated wells, enabling us to extract significant proprietary insights, mirroring the same advantage we've built in the Duvernay. Targeted horizons are shown in blue, while zones currently being delineated are highlighted in green dashed. Many of these horizons, both blue and green dashed, remain unbooked, emphasizing the material upside potential still embedded across our land base. Over the next few slides, we're going to walk through some development projects that illustrate the optionality and profitability potential we see across our asset base. These projects are at various stages of technical due diligence and appraisal, but to demonstrate the capability of our teams and the quality of the assets, we'll start with a case study of our most recent development at Musreau, a great proof point for how we create value through execution. When we set out to build a 5-9 facility, we took the time to ensure the facility's size and design were properly matched to the inventory. We sanctioned the project with an expected payout of approximately three years. Fast forward to today, the facility has come in under expected cost and ahead of schedule, and our development decisions have driven 10%-20% well outperformance. As a result, realized payout has improved to well under two years. Now that the asset is operating in a stabilized state, Musreau is generating approximately CAD 90 million-CAD 115 million per year of asset-level free cash flow, and similar to what you saw in the Duvernay, we're reinvesting approximately 50%-60% to hold production flat. This slide is important because it demonstrates the repeatable playbook: develop the resource, build the infrastructure, lower costs, improve margins, and transition into free funds flow generation. That's how we position these assets to become durable return engines. Slide 24 is an update on Lator Phase 1, our next material growth project anchored by our Phase One facility at 4-13. Phase One is a 35,000-40,000 BOE per day facility sanctioned in 2024. We were fully permitted ahead of schedule, which enabled us to accelerate our commissioning timeline. Construction is well underway, approximately 50% complete on a spend basis, and we're targeting commissioning in Q4 of 2026. We have approached Lator with a disciplined and methodical development strategy focused on optimizing outcomes while managing key risks. Derisking has been central to our work, and we've executed that in two areas: the facility and the asset. First, the facility. The design leverages two similar facilities we've built and operate today in Kaybob and the one I just mentioned in Musreau, both of which were commissioned successfully and have delivered strong operating performance. Lator incorporates design enhancements informed by that operating history, with a focus on proactive debottlenecking, improved operability, and long-term efficiency. The facility has also been engineered around the expected product stream, which brings me to the second point, which is the asset. After several years of study and delineation, we have a strong understanding of the subsurface, particularly across areas that will support near-term drilling. We benefit from a meaningful legacy data set, including roughly two dozen horizontal wells, plus seven Whitecap horizontal drills and a vertical core. We also hold 3D seismic coverage over nearly 100% of the land and have built robust geological, geomechanical, and reservoir models to forecast reservoir and frac behavior. Our existing wells have met or exceeded expectations, and the majority of our technical work, including the core data, has been confirmatory or to the positive. Despite these positive data points, we have maintained our expectations to ensure we remain disciplined and avoid overstating asset capability ahead of full-scale development. This is a clear example of how we pursue growth. Methodically, rigorously, and with risk-adjusted execution, it will continue to define our approach as we progress through subsequent development phases. Over the next three slides, we're going to walk you through illustrative characteristics for three project types we see as core to long-term organic growth in our unconventional portfolio. Everything shown here assumes no improvement in capital efficiency, so the outcomes reflect today's design and execution baseline, even though we have a strong track record of continuous improvement. Across the three project types, we're outlining over 365,000 BOEs per day of productive capacity supported by identified inventory within the 4,700 unconventional locations discussed earlier. This slide focuses on the liquids-rich portion of the portfolio, and we're using Lator Phase 1 as the example given it's already under construction. The top left is net operating income per unit of capital invested. The 1.0 line would be payout. Under base pricing, which is $60 WTI and $3 AECO, payout occurs in roughly nine to 12 months. The two sensitivity cases, either an increase in AECO of $1 or $10 in WTI, those increase net operating income by roughly 10%, highlighting strong leverage to commodity pricing improvement. On the right, we show the transition from the build phase into stabilized production. We expect Lator to become a cash contributor by 2028, with run rate free cash flow in the range of $170-$200 million and reinvestment ratio of 50%-55%. It takes roughly 50 to 55 wells to reach facility capacity, and once there, we can hold volumes flat with only a couple of pads per year. With 300 to 450 wells identified feeding the area, we have decades of inventory to work with. We've also built in design optionality for a Phase Two expansion to 85,000 BOEs per day should market conditions warrant. Lastly, we note Kakwa also has a 40,000 BOE per day future growth project, which is a very compelling growth asset under the right conditions. It has extensive industry data, a thick reservoir with up to three benches of development, and our performance across those benches has exceeded expectations. Today, it is infrastructure constrained and has sour gas considerations, but with access to centralized sour-capable processing, it would compete for capital at the appropriate time. Next, we'll turn to our light oil and condensate-weighted growth options, starting with Gold Creek. This project would add approximately 25,000 BOEs per day of incremental productive capacity in the Gold Creek area. Again, the base case type curve is shown in blue, and on a normalized basis, the returns are highly comparable to the liquids-rich project we just discussed on the last slide, within 2-3%. In other words, capital deployed into these projects is effectively equivalent from a return perspective. The key differentiator is commodity leverage. On the light oil-weighted side, returns demonstrate greater upside sensitivity to oil prices, roughly a 15% improvement in normalized returns compared to just over 5% uplift from higher gas pricing. We expect run rate free cash flow in the range of $190-$230 million per year, which is similar to Lator Phase 1 despite lower BOE volumes driven by stronger netbacks. Importantly, our technical confidence in Gold Creek has materially improved since adding it through the XTO transaction, and we're excited about the development runway ahead. The takeaway here is straightforward. Across our light oil and condensate-weighted growth options, we see multiple pathways to material free cash flow generation with returns that are fully competitive with our liquids-rich gas growth opportunities. Lastly, we'll turn to our lean gas growth options concentrated in Resthaven, a core source of long-dated portfolio optionality. Resthaven is a large, contiguous land position of approximately 350,000 acres with over 1,000 identified drilling locations. To put that in context, Montney development in the Kakwa strike, which has seen significant industry development for many years, spans roughly 200,000 acres. We operate approximately two dozen horizontal wells across this land base, supported by additional industry offsets and targeted 3D seismic. That data set, both proprietary and public, has enabled rapid technical progression similar to the learning curve we have achieved at Lator. Our work indicates a meaningful portion of the asset exhibits high pressure, prolific lean gas behavior, with strong initial gas deliverability and associated condensate. As shown in the type curve, base case payout is approximately 1.3 years at CAD 3 per GJ AECO, and the returns are most sensitive to gas pricing. Importantly, at higher AECO pricing within the range shown on the slide, Resthaven competes directly with our liquids-rich and condensate-weighted growth options on a normalized basis. From a development standpoint, scaling Resthaven will ultimately require material gas processing capacity. However, we're not forcing that decision today. Instead, our focus is on disciplined, appraisal-driven execution. In 2026, we plan to drill two delineation wells to validate the translation of legacy results into modern development designs. With success, we'll expand appraisal across additional portions of the land base before advancing a phased facility concept. An initial development phase would target approximately 40,000 BOEs per day of productive capability, supported by 200-250 million a day of gas handling and associated condensate volumes. At higher gas prices, this phase would generate meaningful free cash flow while preserving significant upside for future expansion, and again, as mentioned at the outset, the core message here is optionality. Resthaven is long-dated, scalable, and supported by identified inventory that could ultimately enable growth toward 200,000 BOEs per day, and we're positioning the asset so it's ready when market conditions warrant. The next few slides focus on how we design and execute our capital programs. We expect to continually improve capital efficiencies across the portfolio, and that's driven by what we call our unconventional development workflow, a collaborative process that has delivered exceptional results across our unconventional plays and will continue to do so going forward. The upside from this workflow is what drives improvement across the metrics shown on the prior slides. Now to walk through the figure. First is subsurface evaluation. We integrate geological, geomechanical, and multi-phase reservoir models to understand the rock, fluids, and expected stimulation and production response. Next is the development plan. That work drives optimized decisions on well placement, spacing, bench selection, and completion design, balancing value and risk. Following that, economic evaluation. We evaluate risk-adjusted returns across commodity scenarios using engineering analyses and in-house machine learning tools to identify patterns and optimization opportunities across large data sets. Lastly, execution and iteration. We execute consistently and efficiently through tight cross-functional coordination, and we iterate quickly as new data is gathered. The key point is that the workflow is continuous. Every new data set feeds back into the system, refining designs, improving performance, and upgrading inventory over time. As you'll see next, the process has already delivered measurable gains, which are embedded in our 2026 capital efficiencies and guidance. As mentioned, the next few slides show how that workflow translates into real measurable improvements. This slide focuses specifically on design optimization, where the architecture of the development plan sets us up for optimal returns before we commence operations on the lands. I'll walk through three examples. First, Montney upspacing at Kakwa. Based on early well results and offset operator data, we saw indications that with modest changes to completion design, we could reduce well density without sacrificing recovery. We tested that hypothesis through two pilot pads, moving from eight wells per spacing unit down to six. The results confirmed our expectations. On an acreage basis, recovery was effectively unchanged, but with materially less capital deployed, a clear improvement in capital efficiency and returns. Next, we're profiling the benefits of benching and drawdown management at Musreau. In this area, we observe similarities to Kakwa and believe that the development plan could be further optimized on our lands by moving to a two-bench development design and, importantly, by controlling drawdown, the pace at which we allow the reservoir to produce into our facilities. With both design features in place, we saw a shallower decline in condensate-to-gas ratio relative to offset. The result is what you see in the middle graph, an improvement in our condensate production profiles. While our wells were below offset wells on initial rates during the first five to six months, the disciplined development plan and controlled drawdown have allowed us to outperform later in life. At this stage, we are comfortable underwriting a 20% improvement in condensate EUR. Importantly, this is fully backstopped by an economic analysis to ensure we are improving returns. In this case, payout was effectively equivalent, as what we gave up early was gained back in the subsequent months. The third example of design optimization is in the Duvernay, where we've applied a similar concept to the Musreau benching design, but more modestly and within the same bench through what we refer wine rack design. with only approximately 50 meters or just under 50 feet of vertical offset, we've achieved better vertical coverage in the reservoir and reduced well-to-well interaction, both between wells on the pad and to offsetting wells. Across pads where we have sufficient production history, we've observed a 10%-20% improvement in well performance and are now evaluating further optimization opportunities, including the potential to downspace within our existing inventory set to better capture acreage value. The key takeaway is that these are not just theoretical gains. They're observed, repeatable, and embedded in our forward plans, as I mentioned. This is important. They reflect our disciplined approach to improving returns without introducing material corporate-level risk. With that, I'll turn it over to Travis Wright, Vice President of Operations, to speak to the execution improvements we've realized across these programs. Thanks, Joey. The next few slides highlight examples of the improvements we've delivered in drilling and completions across the Duvernay and Montney, and importantly, how repeatable these results are when we run consistent programs. We'll also share a recent example of base production optimization and show how the internal workflows Joey discussed translate into best-in-class completion design and execution. Starting with drilling, as you can see, we've made some measurable progress across several core areas. At Musreau, we've had a continuous program since 2023 using the same drilling rig, and our overall rate of penetration has improved by 30% over that time. By leveraging the data available from neighboring wells, we were able to achieve today's ROP after only 20 wells drilled, a level that offset operators required closer to 150 to reach. We're now taking those same learnings from Musreau and applying them directly to Lator as development begins there. The middle chart shows drilling performance at Gold Creek, where we've realized an average 8% improvement in ROP in the back half of 2025. This is an area that has seen steady improvements from legacy operators, which has helped refine our drilling designs and improve execution performance. Gold Creek is a really good example of how strong performance becomes repeatable once an area is in development mode, where recent gains tend to be more incremental: same high-performing rig and services, consistent crews, and continued reductions in flat time driven by our drilling teams. The chart on the right highlights performance in the Kaybob Duvernay, achieved primarily through adopting best practices from both legacy Whitecap and Veren operations. These improvements include minor adjustments to drilling practices and small changes to BHA design, resulting in improved tool reliability and fewer trips in the lateral. Combined with using fit-for-purpose rigs and maintaining consistent services, these changes have delivered a 13% improvement in ROP, as shown here. While we're pleased with the progress we've made, we're still very much on a path of continuous improvement, focusing on every marginal gain through reducing flat time, leveraging technology, and continuing to refine our processes. I'll now switch to completions. With completions representing nearly 50% of our unconventional spend, we maintain an intense focus on both efficiency and effectiveness, meaning how quickly we execute and how well the fracs perform. I'll speak to effectiveness on the next slide. This slide focuses on efficiency, measured as tons of prop and pump per day. As you can see, performance has improved substantially in the back half of 2025. Starting on the left with Musreau, this has historically been a plug-and-perf area for Whitecap. Over the past two years, we've continued to refine workflows and execution discipline, resulting in a 14% improvement in efficiency to an average of around 3,600 tons per day. The middle chart shows Gold Creek, which has primarily been a single-point entry completion design. Since mid-2025, we've made several minor modifications that have had significant impacts, including using finer mesh sand to improve predictability of sand placement, increasing maximum operating pressure through a simple frac sleeve design change, which enables higher pump rates in the toes, and refining and standardizing dual frac operations. Through these and other optimizations, we've driven an average 12% improvement in sand placement per day. We've also recently broken the prior operator record of 64 stages per day, reaching 81 stages and 3,650 tons in a single day, resulting in a pad average of over 2,500 tons per day. We expect to carry the same performance into 2026. And finally, the chart on the right shows our Duvernay completion performance. This has been a legacy plug-and-perf area across all operators, so the key has been applying our internal workflows to the design, the execution, and real-time frac optimization. These are the same processes we've been refining at Musreau. As a result, we've achieved an average 12% improvement in efficiency relative to 2024. One of the most impactful design changes that we've made is running larger diameter casing in the lateral, which enables higher pump rates at the same operating pressure. And if you look back specifically at the wells where we've implemented this latest design change, we're seeing a 33% increase in completion efficiency compared to the prior design. And we expect those gains will continue into this year. Next slide is commentary on production and frac optimization, where we'll highlight some of the work we've done to ensure we're getting the most out of every dollar of capital we spend, really taking that optimization to the next step. While capital efficiency is critical, completions are way more than just simply pumping as much sand as possible in a day. We also need to drive frac effectiveness, which we define as a percentage of the lateral that is effectively stimulated. That effectiveness is enabled through our execution workflows, supported by a group of technical professionals and 24/7 manned frac rooms, aided by advanced real-time diagnostics, automation, and continuous monitoring. The results are shown in the graph on the left, the graphic on the left. What you're seeing here are two side-by-side pads in the Kaybob Duvernay. Red indicates poorly stimulated zones, and green indicates properly stimulated zones. The pad on the left was completed by a previous operator using a cookie-cutter design with minimal diagnostics and limited optimization. The pad on the right was completed by Whitecap using a tailored design and real-time monitoring to ensure consistent and proper stimulation across the lateral. The result was a 14% improvement in completion effectiveness, which is consistent with what we've observed across many of the other offset pads we've analyzed. Importantly, these same workflows are applied across all Whitecap plug-and-perf operations. The last point I'll make here on this slide relates to our team of Calgary and field-based personnel focused on base production optimization. Nothing fancy, just strong production engineering combined with 24/7 surveillance. Base optimization is critical. In the second half of 2025 alone, we delivered an improvement of approximately 4,000 BOE per day on base wells in the Gold Creek and Karr assets versus their previous established trends. These gains are coming from efforts across several fronts, including predicting and optimizing artificial lift, minimizing downtime, facility debottlenecks, and pipeline pressure reduction projects. The example shown on the right reflects exactly that approach. This is a 10-well pad that began producing in 2022, ahead of extensive drilling campaigns by prior operators. As development progressed and attention shifted to the new wells, this pad was left producing into higher line pressures, which drove higher downtime and lower production. Through a focused initiative to reduce this line pressure, enabled by compression expansion and optimization, we shifted performance to the green line shown here, delivering a meaningful uplift to the compared prior trend. This is really where our rigor, workflow, and culture come together. It's a major contributor to the confidence we have in our forward guidance. And with that, I will now pass it off to Chris Bullin, Vice President of our conventional division, to speak to that asset base. Thanks, Travis. Good morning, everyone. Our conventional assets produce about 140,000 BOE per day with roughly 80% oil and NGLs. That production comes from a diversified footprint stretching from the Peace River Arch in northwestern Alberta through central Alberta and across southwestern and southeastern Saskatchewan. Over the past 16 years, we've grown this business substantially, and that growth hasn't been by chance. It reflects our ability to identify opportunities, execute, and continuously elevate the organization through strategy, technical depth, and operational excellence. When you take a step back and look at the map, it's clear how significant this division has become. We're the second largest light oil producer in Canada and the largest in Saskatchewan. Today, we have more than three million acres across multiple high-return play types, all actively competing for capital within the Whitecap portfolio, and a multi-decade inventory of 5,800 locations supported by 52,000 barrels per day of dedicated low-decline water flood and EOR assets. As we discussed earlier, the majority of our conventional assets sit in the stabilizing category. And in the next slides, we'll expand on the resource potential and longevity of this division, particularly the upside in secondary recovery and EOR. These are not legacy properties. They're strategic to our long-term vision. They provide a stable, predictable, low-decline foundation with strong cash flows, deep inventory, technical understanding, a proven track record, and operational resilience. Because we operate within established infrastructure and facility networks, we capture full-cycle cost advantages and reduce capital risk. Together, our conventional and unconventional divisions form a balanced, high-margin, long-life portfolio, and that balance is a key competitive advantage for Whitecap. We'll now turn to our conventional inventory and highlight two key takeaways. First, we are inventory-rich with approximately 5,800 locations. Now, that represents a multi-decade runway of both premium locations and future upside, especially when you consider our 2026 program is just over 150 wells. Importantly, this inventory doesn't stay static. This year, our team's upgraded roughly 400 premium locations, increasing premium inventory from 2,600 to 2,900 locations, even after accounting for wells drilled. That's a great example of how ongoing technical work continues to extend our runway and improve the quality of our inventory. With only 40% of our conventional inventory currently booked as proved and probable reserves, we retain a long runway to continue enhancing locations and benefit from future technical advancements, while also reflecting a disciplined and conservative booking strategy. The second key takeaway is that our conventional inventory remains highly competitive within the broader Whitecap portfolio. Our conventional assets are benefiting from more balanced and deliberate capital programs across our multiple regions, which has driven better capital efficiency and improved returns on capital. This approach has also strengthened our partnerships with service providers, enabling longer-term commitments and consistent access to top-tier equipment and crews. The takeaway from this slide and the next is simple. Whitecap has a dominant position in large, scalable, long-life conventional assets, and we believe they can generate meaningful investor returns for decades. On this map, you can see the scale of our key conventional resource areas. These are large, high-quality reservoirs where a meaningful portion of the original oil in place has already been converted into long-life, low-decline, stabilizing production. Across our EOR-focused assets alone, our internal estimates indicate approximately 14 billion barrels of gross original oil in place, supported by an aggregate forecast recovery factor of 35% over time. And importantly, there is still significant resource left to capture, even when we focus only on projects already utilizing secondary and tertiary recovery. Those projects carry a 2P NPV of approximately 8 billion at year-end 2024. Another advantage is that many of these projects already have sunk infrastructure and capital in place, which improves the economics and reduces the risk of future expansions. Ultimately, recoveries to date prove the resources there. The development model works, and our team has a proven track record of extracting value from these assets. For us, large OOIP means these assets are nowhere near being tapped out. In fact, we've just scratched the surface on some. Every incremental improvement in expanding already established and proven water floods or tertiary floods translates into step changes in recovery factors because the underlying asset base is so substantial. That's the advantage of size, scale, and experience in large OOIP reservoirs as small gains in recovery factors become millions of barrels of additional reserves and decades of optionality. For context, 52,000 barrels per day of EOR production is only 19 million barrels per year. So while the risked recovery remaining of 700 million barrels may seem small relative to the others in that table, it represents over 35 years of recoveries at 52,000 barrels per day. Now, this isn't blue sky potential, as these opportunities are grounded in what we've already delivered from the projects that are already utilizing secondary and tertiary recovery, and the repeatability of results across a very large and predictable set of resources is substantial. To highlight these future upside opportunities, we'll start at the top and we'll work our way down the list. First, Alberta Conventional. The future potential here comes from a variety of projects. The Cardium has demonstrated improved recovery and lower declines already in established water floods, giving confidence that further expansion can extend field life. Secondly, EOR upside has been identified in Boundary Lake, which is a very mature water flood with large OOIP and infrastructure in place. It would provide for increased recoveries through polymer implementation. Lastly, gas injection is being assessed on a variety of horizons, including Boundary Lake, Cardium, and also in the Glauconite. Southwest Saskatchewan is the area with the most production from water flood assets at 19,000 barrels per day and the most recoveries at 900 million barrels to date. We already have active polymer floods, and further upside would be seen with water flood expansion, additional polymer implementation, and lastly, gas flooding is also currently being scoped by the teams. Eastern Saskatchewan, where we are focused on the Bakken, provides a clear example. Today, only one-third of our active development is under water flood, and only about 25% of our forecasted OOIP has been recovered to date. Our team has aligned a site to a significant water flood expansion over time into areas that are currently on primary recovery only, and further technological advancements have the potential to unlock significant value in our large Bakken land base. Accordingly, our teams are also advancing scoping-level assessments across a range of gas scenarios, including CO2 and ethane, to evaluate technical feasibility and capital requirements, and last but not least, Weyburn, where we recently began CO2 injection into the Frobisher zone, which lies beneath the existing Weyburn-Midale Unit. CO2 injection commenced in late 2023, and we continue to evaluate the results from our initial pilot, with focus on understanding commerciality, scalability, and how this opportunity may fit within our longer-term EOR development plans. Importantly, this pilot leverages existing CO2 infrastructure, making it a strong brownfield example that allowed us to move efficiently while gathering valuable technical and economic data. That combination of high confidence today, plus multi-decade recovery upside for tomorrow, is exactly what differentiates these assets and anchors long-term shareholder value. One of the best examples of how we continue to optimize large OOIP assets and a global benchmark for secondary and tertiary recovery is the Weyburn CO2 EOR project. Weyburn has over 70 years of continuous production, and it represents one of the longest and most data-rich CO2 EOR track records in the world. To date, the field has produced approximately 600 million barrels of oil, and since CO2 injection began in 2000, it has also safely stored over 41 million tons of third-party CO2. As you can see on the production profile, this operating history gives us exceptional confidence in recovery factors, decline behavior, and capital durability. Weyburn has proven and has clearly demonstrated that tertiary recovery can reliably convert large volumes of OOIP into long-life, predictable production. Importantly, Weyburn also provides decades of learnings around pattern design, CO2 utilization, sweep efficiency, and conformance control, which helps us to materially de-risk the application of EOR across other suitable reservoirs in our portfolio. That gives Whitecap a real technical advantage. We can deploy capital to EOR projects selectively and prudently, rather than committing risk capital to unproven recovery concepts. And our understanding of this asset continues to evolve. Recent geomodeling and internal reservoir simulations increased our estimated gross OOIP by approximately 20% to about 1.8 billion barrels. We've also expanded our projected recoveries into adjacent lands outside the unit and the underlying Frobisher zone, bringing total gross OOIP to approximately 2.5 billion barrels. So the key takeaway here is confidence and asset duration. Weyburn is the benchmark that proves low-risk recovery upside remains, and it reinforces the multi-decade EOR potential across our broader portfolio. Lastly, on the EOR theme, we wanted to highlight the economics of EOR using a typical Weyburn rollout as an example. A full rollout, typically consisting of horizontal producer and injector pairs, can take over a year to fully deploy. Now, because these projects are longer cycle, they don't optimize for the fastest payout the way short-cycle drilling does. Instead, they optimize for value, enhancing net present value and profit-to-investment ratios. And because they deliver low-decline, high-net-back barrels, they provide long-term, predictable production profiles that help stabilize the business through commodity cycles. You can see in the cumulative production curve, EOR projects start more gradually, but they build momentum over time, with production often peaking more than five years after the initial investment. To put that in perspective, a typical Weyburn rollout generates roughly seven times its invested capital over its lifecycle, shifting the conversation from speed of payout to magnitude of payout. On the final two slides on the conventional division, we'll highlight how improvements in well design and execution across our portfolio are driving better capital efficiencies and higher profitability. Starting in the Bakken, this slide shows the evolution of our open hole multilateral development, moving from a one-mile design to two-mile multilaterals and now to three-mile multilaterals. The key takeaway is that we've systematically increased reservoir contact through longer laterals. The results are clear. Compared to our 2022 program, which includes three wells averaging one-mile laterals, our 2025 program to date includes six wells averaging just over two miles. We're maximizing reservoir contact and productive capability without sacrificing capital efficiency. We're still in the early stages of open hole multilateral development in the Bakken, and we're excited about the runway to continue advancing performance. Moving to the Cardium. Recent success has been driven by an optimized completion design using workflows and learnings from our unconventional assets. Following a detailed review of our 2025 program of 11 wells, we identified an opportunity to improve performance through tighter cluster spacing and higher proppant intensity. Compared to the years' prior legacy design, this year's program delivered a 30% improvement on an IP 180 basis and improved capital efficiency by 11% and in the Frobisher, our continued focus is on maximizing reservoir contact through both longer laterals and additional lateral legs. Relative to 2022, our average leg count per well has increased from roughly 2 to 2.6 in 2025. That's a 30% increase in reservoir contact. That design evolution has driven a 30% improvement in six-month cumulative oil recoveries, translating into a 30% uplift in NPV. These are just a few examples of how we continue to improve asset duration and returns across the conventional portfolio. With that, I'll pass it to Travis to walk through the conventional drilling performance. Thanks, Chris. On this slide, I'll quickly highlight some of the gains we've made in drilling efficiency across some of our more active conventional assets. Drilling in these areas isn't overly complex. It's just consistent application of good drilling practices and a hyper focus on reducing downtime and eliminating non-productive time. The slide on the left shows ROP in our Frobisher play, where we have recently seen an 8% improvement. The key here is to maximize ROP while staying in zone, a balancing act that our geology and drilling teams handle very well. We have also continued to focus on reducing side track times and increasing on-bottom drilling ROP through various advancements to bit design. The middle chart shows our Bakken open hole multilats, where we have achieved a 14% improvement to overall ROP. This has been done through eliminating non-productive drilling practices as well as improved directional profiles to reduce torque and drag, leading to less slide time. Importantly, we have also worked diligently with our directional provider to reduce failures and to push our BHA life to over 250 hours, whereas area norm would be closer to 100 hours. Lastly, the chart on the right shows our legacy central Alberta Glauconite drilling, where we continue to implement our monobore design that previously reduced costs by 10%. Of note, in Q4 2025, we drilled a Pacer 2L pad with average ROP of around 355 meters per day compared to the area average of less than 250 meters per day, and as we move into 2026, we will continue to apply the same philosophy of continuous improvement to seek out further drilling and completion efficiency gains across our entire asset base. With that, I'll now pass it back to Grant to finish off the presentation. Thanks, Travis, Chris, Joey, and Thanh for walking us through the business components and the work that our teams are doing across our portfolio. To close out, I'll spend the next few slides bringing together everything we've covered in the balance of the presentation and what it means for Whitecap going forward. To wrap up, we've outlined the multiple pathways we have in front of us to continue advancing the business and delivering increased shareholder returns for decades to come. Our starting point in 2026 guidance of 370-375,000 BOE per day delivered across a diversified set of play types and commodities that includes light oil, liquids-rich natural gas, and high deliverability natural gas inventory. In the near term, we also have approximately 90,000 BOE per day of available infrastructure capacity that can be utilized for quick production additions if required. That capacity comes from debottlenecking and further utilization of existing infrastructure, as well as our Lator Phase 1, which is approximately 50% complete as of today. Beyond that, we've also outlined a series of project-level growth wedges that in aggregate represent approximately 325,000 BOE per day of organic growth potential. These include Lator Phase 2, Gold Creek and Karr expansions, Resthaven lean gas development, and Kakwa expansion. And finally, we've highlighted why our conventional portfolio is a key differentiator for Whitecap. We continue to advance new and improving technologies in open hole multilaterals, as well as drilling longer laterals with monobores, providing cost down while improving recoveries and asset profitability. In many respects, we're still in the early innings of unlocking its full potential. The fact that an asset like Weyburn, with more than 70 years of production history, continues to offer meaningful runway and reinforces the durability and long-life value embedded across our portfolio. The takeaway is simple. Our asset base is large in both order of magnitude and long-term profitability, and our focus remains maximizing returns and profitability in any commodity price environment. Our diversified, long-dated inventory provides significant strategic flexibility, but also means there are multiple pathways we can take to advance the business. On this slide on growth optionality, we provide illustrative outcomes aligned with our corporate strategy of 3%-5% production per share growth annually while including a state flat scenario that we employ in a low commodity price environment. These outcomes reflect our capital allocation strategy. In our moderate commodity price environment, we would introduce growth while still prioritizing the balance sheet and share repurchases. As commodity prices move higher, we would allocate more capital towards organic growth, where returns are invested capital, improving both near-term results and the free cash flow generated as prices normalize and growth moderates again. In these scenarios, annual capital would range from approximately CAD 2 billion-CAD 2.8 billion, fluctuating based on the pace of growth and which projects are deployed under different commodity price environments. Ultimately, we hope the takeaway from this slide and from the presentation as a whole is that we have the ability to adjust both pace and asset mix across our broad range of outcomes, not only over the next five years, but for a significant period of time beyond that. To close on slide 45, build to provide durable returns. We'll circle back to the advantages that underpinned our strategy and our ability to deliver long-term shareholder value through commodity price cycles. Our strategy is built on four core pillars: high-quality inventory with significant depth, technical excellence, and top-tier operating performance, capital discipline, and a strong balance sheet. Our intention is to leverage the strength of all four pillars to free funds flow and deliver superior shareholder returns now and for decades to come. Before we conclude, I would like to recognize our staff, both in the field and in the office, for their dedication and continuous pursuit of improving profitability of this company. I also want to thank our board of directors for their guidance and their support. With that, I will now turn the call back to the operator, Sylvie, for any questions. Thanks very much. Thank you, sir. Ladies and gentlemen, as stated, if you do have a question, please press star followed by one on your touch-tone phone. You will hear a prompt that your hand has been raised, and should you wish to withdraw your question, simply press star followed by two. We do ask that if you're using a speakerphone, to please lift the handset before pressing any keys. Please go ahead and press star one now if you have any questions. First, we will hear from Dennis Fong at CIBC World Markets. Please go ahead, Dennis. Hi, good morning. Thanks for the overview and for taking my question. My first one is focused on just aggregate strategy. You mentioned very briefly in it in terms of how you think about your current depth of inventory. You obviously have a lot between both the conventional and unconventional. Obviously, in a volatile commodity price environment with the strength of your balance sheet, how do you think about being opportunistic in this specific situation? Obviously, understanding that internally your portfolio is quite robust. Yeah, so thanks, Dennis. Just on the acquisition side, I mean, I think that's what you're leaning towards. I mean, what we look at firstly, as we've tried to imply through the presentation, is that we'll continue to, with each one of our teams and our business development team, we'll look at opportunities into the future. The key component for us is when we talk about contracyclicality, is making sure that we have the strong balance sheet in order to do that, so at this particular time, relative to acquisitions, that isn't our primary driver because we have enough inventory to go organically at this particular time, and we'll always have that, but if we can supplement that through acquisitions into the future, when our balance sheet, we feel that's appropriate with our balance sheet strength, we'll have to do it, but at this particular time, our primary focus is going to be on organic growth as we advance forward or organic spending as we advance forward. No, I appreciate that context and that background there. When we think about my next one kind of shifts towards the organic growth portfolio. So when we think about that 325,000 BOEs a day of incremental growth project beyond Lator Phase 1, what stages of engineering are some of those projects in currently? And then what kind of either commodity price environment or key kind of technical milestones are you guys looking forward for to feel more comfortable about sanctioning or moving forward with those projects? Thanks. Yeah, hey, Dennis, Joey Wong here. Thanks for the question there on the projects. And maybe I'll talk about the projects and the underlying inventory kind of in conjunction because they kind of relate. So the projects themselves, they're in various stages of either understanding of the facility that's going to be needed for it or of understanding what we intend to do in order to fill it in the first place. So to give an example of that, something that would be a little bit further progressed would be the one we spoke to in Gold Creek. That's an expansion of an existing facility. So the 25,000 barrel a day add that we have there is actually a bolt-on. So that would be relatively far down the line. There's actually even to the point where there's space on the lease for it. So that one's relatively far progressed. And then on the other end of the spectrum would be, like we had mentioned there, Resthaven, where, like I say, we do have a very, very solid understanding of the asset in terms of what it would be without things like the two dozen wells that we have and all of the work that we've done from a subsurface point of view, but it isn't to the point that we have the understanding on something like Gold Creek. So it all exists on a spectrum, Dennis. Our intent as we go through our capital programs, though, is to introduce sleeves of activity that would be strategic in nature to progress some of those things. And like I mentioned there in the prepared remarks, the two wells that we have in Resthaven, we'll start to further that. We'll take the legacy data that we have, make sure it matches up with the translation to modern results, and then we start to build from that. To come to your question there on how we would progress a sanctioning of a project, these are big things when we start to look at these larger legs of growth, and we would do those with a view to the long-term pricing that we see and ensuring that what we are left with in the overall portfolio gives us the same optionality that we enjoy today, so one of the key de-risking mechanisms that we have in our corporate growth profile is, like we outlined at fair detail here, the flexibility that we have or the optionality that we have to allocate capital throughout different price cycles. We want to make sure we retain that. So if we find ourselves at a place where, let's just use a theoretical case, where we fill up the majority of our liquids-rich gassy capacity, but we're long on the condensate side, well, we would probably look to supplement the liquids-rich side so we maintain that flexibility as long as the long-term commodity prices are supportive of that. So again, it's a lot of words there to describe the fact that we like what we have today and we want to continue to build that out to maintain that optionality in the future. Great. Appreciate that context, Joey. I'll turn it back. Yeah, I'm just going to read out the next question here that we have from Aaron Bilkoski with TD Cowen. With oil stripped below $60 and reasonably strong North American gas prices, at the margin, do you see Whitecap allocating some capital to more gassier windows of the Montney than you would have if oil was $65 plus? Our comment to that really is when you look at the oil price today at $58 and where the Canadian dollar is currently trading at about 72 cents, you're still seeing Canadian WTI prices in excess of $80 compared to AECO pricing for the balance of the year in 2026, somewhere in that $2.80 there. So when we look at the economic profile of oil and condensate opportunities as well as liquids-rich opportunities, they still provide better returns than the more gassier opportunities. So we think the development program that we've outlined for 2026 is very balanced and really optimizes the return profile at this time. Okay, the next question is, where are your light oil barrels destined and is there sufficient capacity in pipelines? And so from our perspective, a lot of our light oil is centered in Saskatchewan, which is closer to the border between the U.S. and Canada. And so we've been able to move our product very easily on the light oil side there. So we haven't had any issues being able to produce and sell our product there. In terms of the condensate there, it's obviously being used as a diluent in the oil sands there. So there's a natural ability for us to sell that domestically. The light oil goes to Edmonton PADD 2 and to Eastern Canada there. So no issues from an egress perspective. Thank you. A reminder for those on the phone to please press star one should you have any questions. Next, you will hear from Phillips Johnston at Capital One Securities. Please go ahead. Hi, thanks for the time. Wanted to ask about what your next 12-month corporate PDP decline rate looks like today. And maybe within that company-wide average, what does the decline rate look like for both your conventional production as well as your unconventional production? Thanks. Yeah, thanks very much for your question. From an overall corporate perspective, our decline rate is between 28%-29% at this particular time. Broken down, we're 19%-20% on our conventional assets today. And our unconventional assets are declining anywhere between 32%-33% at this particular time. Okay, great. Thank you. And then your capital budget this year, CAD 2-CAD 2.1 billion, that is expected to generate some production growth. Within that figure, what would you estimate is your maintenance CapEx that would be required to just keep current production volumes flat? Yeah, so the maintenance CapEx there would be somewhere between 1.9 to 2 billion to keep production flat. Perfect. Thanks, guys. Thank you. And at this time, we have no other questions registered on the phone. Please proceed. So the next question we have from Darren Steffens, what is the AECO natural gas price today and what gas price do you see reasonable for 2026 and 2027 forecast? Well, the price today is natural gas prices on the Canadian side. AECO prices are about CAD 2.80 per GJ. And for the average for 2026, the prices are approximately CAD 2.60 at this particular time. So we're forecasting CAD 3 as an average for the year at this particular time. We'll make adjustments if we see necessary. For 2027, we think that ultimately the gas prices do come back once we have incremental takeaway capacity or we fulfill the obligations to LNG Canada one and two into 2027. We feel longer-term gas prices will stabilize somewhere in that neighborhood of between CAD 2.75 per GJ to anywhere between up to CAD 3.75 per AECO in 2027. Maybe up over CAD 4. At this particular time, we're using an average price of CAD 3. Why it's particularly important is the takeaway capacity out of Canada is going to be very important as we advance forward. We'll watch that very closely moving forward. The next question is, what would it take to drive all of Whitecap's free cash flow to the buyback given current valuation and soak up the full 10% of our NCIB there? And so when we look at the oil pricing environment today and we're using $60 WTI, we generate CAD 1.2 billion of free cash flow and CAD 900 million of that is allocated towards our dividend and CAD 300 million towards our share buyback program there, which is about 3% of our float. So I think given where our intrinsic value is and where the share price is, any excess above that will certainly go towards buying back our shares. So that would be our objective at this time here. I can read out the next one here from Christian at Peters & Co. So the question says, on the operational improvements you highlighted related to unconventional and conventional business units, how much is factored into formal 2026 guidance? Could you also touch on some of the improvement initiatives you're targeting in 2026 to further the operational momentum realized over the past two years? So yeah, Christian, where we have confidence and we're comfortable underwriting those efficiency gains, we've incorporated those into the program. So maybe I'll take a step back and give an example last year of things that wouldn't have been incorporated when we started things wine rack design, took a bit of time to make sure that that was going to be repeatable before we bake it into the program. But with that said, like I say, the ones that we've seen there, whether that's the outperformance on the production in places like Musreau, Kaybob, the outperformance in the drilling and completions, we've started to build all of those things in where it's reasonable recognizing that we are well on our way up the curve there. On the conventional side, any further comments there, Chris? Yeah, to add to that, Joey, I would say a continued focus really on open hole multilaterals in the Bakken in Eastern Saskatchewan. I mean, the teams have definitely done a great job there to advance those initiatives as we've shown on the design optimization slide. And not just in some of the areas where we're starting to push play edges, but also from the conversion of more of the historical multi-stage frac technology, looking to convert to open hole multilaterals where we can. So the teams are stepping through that process very methodically right now to better understand that upside potential. And another key focus area for additional optimization potential for us, again, it remains to be the Frobisher. And once again, the teams have done a great job there showing that progression over time, focusing on additional lateral lengths where we can. And really just at the end of the day, just trying to maximize our total development costs at the end of the day. So we want to be as efficient as possible. Another thing to note too is that we're in such a strong position that we don't need to take any unnecessary risks within our portfolio too. Everything's a very measured approach. We go through that very systematically from a kind of decision analysis perspective. Definitely a competitive advantage for us in that regard too. The next question is, do you have access to natural gas markets that aren't constrained by AECO pricing? Currently, our mix there is we've got 78% exposed to AECO, of which 29% of that production has been hedged for 2026 at C$3.76 per GJ. 22% exposed to other markets, including Dawn, the U.S. Midwest, and Henry Hub. We've seen the importance of price diversification. If you look at our Q3 report, where we realized almost double the price of AECO as a result of that. So longer term, there's certainly a target to continue to move some of that exposure away from AECO because we do think that it's important in terms of that pricing mix. Just really quickly on a number of questions we have. What do you expect Whitecap's production mix, crude oil, natural gas, and GLs to be in 2026? As we talked about in the presentation, we expect this year to be 60% oil and liquids and 40% natural gas. At this time, there are no questions on the phone. Okay. Thank you, Sylvie. Once again, we appreciate you taking the time and interest to listen today. We are excited to continue down the path and generate significant value for shareholders now and for many years to come. Lastly, I would again like to emphasize it's with the appreciation of the hard work of our staff, both in the office and field, that we're able to pull all of this, not only its information together, but the operational excellence that we've been able to demonstrate. I want to thank you for your performance and look forward to an exciting 2026. Thanks very much, everyone. Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending, and at this time, we do ask that you please disconnect your lines. Enjoy the rest of your day.