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 participant 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. I would like to turn it over to Whitecap's President and CEO, Mr. Grant Fagerheim. Please go ahead, sir. Thank you, Sylvie. Good morning, everyone, and thank you for joining us for our inaugural Investor Day. We are excited to showcase the quality, depth, and long-term growth potential of our asset base, as well as our team's technical expertise to continually enhance and optimize our portfolio. Our technical expertise, combined with an enviable runway of growth opportunities, will provide our shareholders with sustainable returns well into the future. I am joined by six members of our management team on the call today: Thanh Kang, our Senior Vice President and Chief Financial Officer, 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 of the West Division, Chris Bullin, our Vice President of the East Division, and Travis Tweit, our Vice President of Operations. I would also like to recognize our 700+ employees and contractors for their daily contributions to the success of Whitecap and our board of directors for their ongoing guidance and support. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our Investor Day presentation that has recently been made live on our website. For the presentation today, we will start with an overview of Whitecap, including our track record of creating value organically and our ability to enhance those returns through targeted acquisitions over the last 15 years. This will lead to our corporate growth plans over the next five years, where Joey Wong will walk through our Montney and Duvernay assets, and Chris Bullin will walk through our conventional assets. Travis Tweit will also discuss some of the operational improvements we have achieved along with our water management strategy. I will then have Thanh Kang speak about our financial priorities as a company and our financial outlook for Whitecap over the next five years. As well, Thanh Kang will also provide an overview of our crude oil and natural gas marketing strategies. Lastly, I will provide some closing comments before opening it up to Q&A. Questions can be asked both on the webcast, where we will read the question out, read out the question and provide an answer, or via the phone line. Questions submitted on the webcast will be sent directly to us and not made public until we have answered them at the end. With that, we will get into the presentation. We started Whitecap in September of 2009 with a starter kit of 850 BOE per day. Over the last 15 years, we have successfully positioned ourselves in the top plays in North America. During that time, we have grown production to just shy of 170,000 BOE per day through a combination of acquisitions and organic growth. Our enterprise value today is approximately CAD 7.8 billion, with a highly economic portfolio of growth opportunities across Alberta and Saskatchewan. And then we have long-dated development plans for. Our unconventional Montney and Duvernay assets are situated in northwest Alberta, while our conventional lighter-weighted assets run from southeast Saskatchewan all the way up to the Peace River Arch area in northwest Alberta. Our objective is to grow production 3%-8% per year organically, supplemented by purposeful acquisitions that enhance our long-term sustainability. Today, we also pay a stable monthly dividend of slightly over CAD 0.06 per share, which equates to a current yield of approximately 7%, and is fully funded by our cash flows stress-tested down to $50 WTI oil and CAD 2 per GJ AECO gas level. Our core principle is to maintain a strong balance sheet through commodity price cycles. Our balance sheet is in excellent shape with debt of CAD 1.5 billion at the end of the first quarter, which equates to a debt-to-EBITDA ratio of 0.7x. We forecast net debt to be below CAD 1.2 billion by the end of this year. As you will see on slide 5, our focus since inception has been on per-share growth, not just absolute growth alone. This has resulted in 11%-13% annual per-share growth across funds flow, production, and reserves. We've been able to achieve this while managing commodity price volatility. We have the assets, the drilling inventory, and the deep technical expertise to continue to add shareholder value by focusing on per-share results. As you can see on slide six, our historical growth has also been enhanced by our commitment to returning capital to shareholders. As mentioned previously, we started Whitecap in 2009 and initiated paying a dividend in 2013. Since first paying a dividend in 2013, we paid over CAD 5 per share in dividends and over CAD 1 per share in share repurchases. This equates to over CAD 2.5 billion in capital returns to shareholders to date. We are not finished yet. Our dividend is CAD 0.73 per share annually. We are comfortable with the dividend level, having increased it significantly since 2020, and are now focused on share buybacks to enhance per-share growth metrics. Acquisitions are part of our DNA, and that is one of our core competencies. But more importantly, we have the technical expertise to evaluate, capture, integrate, and improve asset-level performance to drive higher quality, higher profitability, and cash flows into the future. The primary purpose of all of our historical and future acquisitions is to scale up our cash flow and free cash flow on a per-share basis. Joey, Chris, and Travis will discuss asset-level performance later in the presentation. But in the next few slides, I want to focus on some of the foundational acquisitions we have completed over the years. A key competitive advantage embedded in our portfolio are assets that are under enhanced oil recovery, which includes water floods, polymer floods, and CO2 floods. They are stabilizing assets to provide significant free cash flow. An exceptionally good example is our CO2 flood in Weyburn, Saskatchewan. Weyburn is one of the largest CO2 sequestration projects in the world, and Whitecap safely sequesters and stores 1.5-2 million tons of CO2 annually. We acquired the asset for CAD 940 million in 2017, our largest acquisition at that time. Since then, we have invested CAD 290 million to maintain net production of approximately 14,000 BOE per day and the assets of cash flowed CAD 1.2 billion. Net of capital investments, we have paid out the purchase price in just over six years. This calculation does not include an additional CAD 190 million of proceeds on the sale of a 3% gross overriding royalty in late 2021. We still have CAD 2 billion of 2P net present value remaining at this time. Chris will provide more details on this asset and where we see opportunities to capture incremental value later in the presentation. Our next example is our NAL acquisition shown on slide 9. NAL was a private company, and the acquisition was negotiated in mid-2020 in the depths of the pandemic and closed in January 2021. As you can see, the company acquired for CAD 150 million and has since cash flowed CAD 800 million net of capital investments. This means we have paid out the purchase price over 5 times in 2.5 years, and there is still CAD 1 billion of asset value remaining. This was an important acquisition for us as it was our first entry into the now prolific Lochend Play, and we subsequently acquired and consolidated a sizable portion of land in the play, making the core area for the core area for our company. Now onto the TORC acquisition. In our countercyclical strategy to increase both production and growth inventory, we also negotiated and closed TORC in 2021 for CAD 900 million. TORC was a very well-run company with assets that overlapped with certain NAL assets and was our entry into the Frobisher Play in southeast Saskatchewan. Although that was a significant transaction for us from an asset and personnel perspective, we were able to seamlessly integrate our two companies to create operational and financial synergies for the benefit of our shareholders. Like previous transactions, the purchase price has been paid out with the assets' cash flows, and there are significant cash flows remaining to be realized. On to slide 11. This brings us to our now largest deal and most significant in terms of depth of inventory and future potential, being the XTO Canada acquisition in mid-2022 for CAD 1.7 billion. We completed the transaction with no equity dilution to our shareholders, and within nine months, reduced net debt by $900 million. The growth potential within the asset is significant. And combined with our organic growth and our 2021 acquisition of Kicking Horse, we are now producing 55,000 BOE per day of Montney and Duvernay production, with the XTO assets generating $500 million of operating cash flow since August 2022. Like our other acquisitions, the goal is to have purchase price paid out in a reasonable period of time and still have significant reserve left for the future. As you can see, acquisitions have been and will continue to be an important part of our strategy. We have a strong systemic process in place for identifying and extracting incremental value from targeted acquisitions to create meaningful value for our shareholders. And now on to our five-year plan. Our five-year plan is consistent with our prior communication and aligns with our strategy to grow our business organically by 3%-8% per year. Our base case has our production going from 170,000 BOE per day to 215,000 BOE per day in the next five years, with upside potential from there. In that time, our liquids mix stays relatively consistent, moving from 64% oil condensate and NGLs currently to 60% at the end of our five-year plan. Using our long-term price deck of $75 WTI oil and $3 per GJ AECO, we generate CAD 10 billion of funds flow and will invest CAD 6 billion, CAD 1.1 billion-CAD 1.2 billion per year towards organic growth opportunities. This results in CAD 4 billion of free funds flow over the next five years. As shown in the chart on slide 14, our free funds flow continues to grow over the next five years. Of the CAD 4 billion of free funds flow generated, CAD 3 billion is anticipated to be returned to shareholders through dividends and share buybacks. The remaining billion dollars will be used to reduce our absolute level of debt, which results in minimal debt remaining at the end of five years, positioning us well for enhanced shareholder returns. Thanh will provide more color on our financial outlook later in the presentation. Slide 15 contains good visual of the split between Montney and Duvernay and our conventional assets over the next five years. We have a balanced portfolio of both crude oil and liquids-rich natural gas opportunities, which allow us to maintain returns through commodity price cycles. Our conventional assets provide us with stabilized cash flows, and this is complemented by our liquids-rich growth opportunities in Montney and Duvernay. Over the next five years, our Montney and Duvernay production grows from 55,000-100,000 BOE per day, with an option to accelerate growth to 120,000 BOE per day over that time period. The conventional business is currently providing the largest portion of our cash flow, and we expect to maintain production with our large inventory at approximately 115,000 BOE per day while continuing to generate significant free funds flow for our company. Our base decline is currently 24%, and our conventional assets play a key role in decline rate mitigation as we grow total production to 215,000 BOE per day. Annually, we invest CAD 130 million, or in aggregate, close to CAD 600 million in the conventional business on decline rate mitigation projects that result in manageable corporate decline of approximately 26% at the end of 2029. Further, given the high oil nature of the conventional business, oil and liquids weighting remains over 60% at the end of 2029. Over the next five years, capital is allocated almost equally between the unconventional Montney and Duvernay and the conventional assets. I will now pass on to Joey to provide an in-depth discussion of our Montney and Duvernay assets in northwestern Alberta. Joey. Thanks, Grant. My name is Joey Wong, and I am the vice president of our West Division. I'll be walking you through our impressive land base in the Montney and Duvernay, the inventory set associated with it, and the technical rigor that informs our development plans. We've had a great deal of success to date owing to our culture of continuous improvement that follows consolidation, and we're excited to share with you our view of what these assets will do for us into the future. Here on slide 17, you can see the majority of our Montney and Duvernay sits in a really nice tight area where the prolific Kaybob, Duvernay, and unconventional Montney trends meet. Whitecap owns about 700,000 acres of Montney and Duvernay rights, of which just over 600,000 acres are in the Montney, making us the second largest landholder of Alberta Montney in the Western Canadian Sedimentary Basin. In addition to this, we have over 70,000 acres of Duvernay rights, largely in the Kaybob liquids-rich trend, giving us an enviable land base with which to set up predictable, repeatable, and explosive growth trajectory. Our inventory set, which we will speak to in more detail in the balance of this presentation, of just under 2,500 wells, provides more than enough depth to grow these assets at a pace that will support our corporate growth targets for many years to come. It's also important to note that we're very lightly booked on this inventory set. Only 13% is booked in the Montney and 40% in the Duvernay. Combined, that's only 15% booked, which gives us tremendous running room to continue to grow our reserves and net asset value well into the future. As noted, we've got an impressive inventory set in the Montney and Duvernay shown here on slide 18, consisting of just under 2,500 gross locations, of which half pay out in less than 1.5 years. We drill approximately 40 wells per year, and as you can see, over the next 5 years, we consume less than 10% of our inventory. These assets are under continuous review for improvement and optimization, and we'll speak in more detail to how we approach that in the coming slides. It is our expectation that with the passage of time and continued technical work on these lands, we'll see continual upgrades and additions to our inventory. That inventory set gives us the ability to grow the unconventional asset base comfortably and predictably, which underpins our corporate growth targets. Importantly, we have the depth for accelerated growth if warranted. What we're showing on the graph on the left is our base growth case to 100,000 BOEs per day, with an option for accelerated growth for an additional 20,000 BOEs per day. What you'll see on both of the plots is that we're focused in the near term in Kaybob, Kakwa, and Musreau, and that's because we have excess facility capacity in each of these areas. In the 2026 to 2027 timeframe, we'll Latour, where we have a facility build-out plan that I'll speak to in more detail later. To deliver this program, we're running 2 unconventional rigs, which will soon become 3 by the end of 2025, 4 by sometime in 2027, and 5-6 by the time we're in the 2028-2029 timeframe. Here on slide 20, we have a map showing where those four focus areas lie within our core Montney and Duvernay asset base. We'll be providing some highlights on each of these areas in the presentation, but for the time being, I wanted to give some context to their relative positioning. First up, Kakwa Montney. This is a predictable asset base owing to the active drilling campaigns in previous years to the north of us dating back over a decade. There's nearly 1,000 wells drilled so far in the Kakwa area, which has tremendous value to us as it comes with an absolute wealth of publicly available information that has helped to inform our development plans in this area as well as other areas. Next is Musreau, and Musreau is one of our higher liquids developments just to the north of the main Kakwa strike and has the added benefit of a recently constructed Whitecap operated 20,000 BOE per day facility that came on production in Latour is a southeast extension of that same Kakwa trend. With 90,000 acres of land and at least 300 inventory locations, there's a ton of room to run here. It's liquids-rich, overpressured, and thick. Geologically, it's very similar to Kakwa proper in terms of thickness, pressure, and ranges of rock quality. As mentioned, we have a planned infrastructure build-out to be on stream late 2026 to early 2027. Lastly, Kaybob Duvernay. Kaybob Duvernay is in the heart of the Kaybob liquids-rich trend. Favorable reservoir parameters, including some of the thickest and most overpressured rock, result in enhanced resource volumes and deliverability. We have an owned and operated 15 MMcf/d gas plant in this area, which has given us runway for the development to date and will support us in growing this asset in the near to medium term. With respect to economics and how they all stack up, they all screen very well and highly economic in each of the areas. On the left plot on slide 21, we're showing the cumulative operating income from each of the focus area type curves over a 24-month period. As you can see, they all reach payout within a pretty tight band and are all nearly paid out twice at the end of a 24-month period. Looking at the table to the right, you can see there's a good mix across the asset base of characteristics, all pointing towards some very compelling economics for us to build our long-range plans. As you can see, the liquids weighting on an IP90 basis in the Montney is highest in Musreau at 55%-75%, followed by Kakwa at 30%-50%, Latour at 25%-50%. Our Duvernay at Kaybob is also very high in liquids at 35%-55%. The high liquids content across these assets, paired with prolific deliverability and excellent EURs, allow us to generate quick capital payouts between 7-11 months and very strong profit-to-investment ratios between 1.3-1.6 times. Capital costs in the Montney are currently CAD 11.2 million and CAD 12.3 million in the Duvernay, owing to differences in depth, pressure, and our design completions. It is worth noting that while the costs provided here are representative of average development, these will change, of course, with depth, lateral length, time cost assumptions, among other things. Shifting gears a bit, we wanted to touch base or to touch on how we approach development planning on our asset base. Given the quality, scale, and breadth that we are fortunate to have, we need to be deliberate and thoughtful about how we put together a plan. Our approach to development in our unconventional assets has always been to customize the development to the lands rather than trying to seek a one-size-fits-all approach. What allows us to do that is our iterative workflow that I'll spend a bit of time walking through here on slide 22. This workflow, at the simplest level, examines three key influences on an economic decision: the rock, the fluids, and what we do with them. So starting with the rock and the fluids, or what we'll combine as subsurface evaluation, our teams investigate the detailed characteristics in our plays using a blend of detailed 3D geocellular models, seismic, and it's worth noting that all Montney and Duvernay properties under our development are covered by 3D seismic data, reservoir characterization, and modeling. And then we move on to development plans. Once we have utilized those tools to produce a view of the rock and the fluids, we can then evaluate our options for development. Key design inputs that we're looking at will include lateral lengths, well spacing, landing depth or benching, the dimensions of the well bore and casing itself, fracture area optimization, or effectively our completion design, which incorporates both what we pump and how we pump it with the goal of ensuring predictable, uniform, and of course, optimal geometry. We'll also consider how the wells should be produced. How the wells are drawn down can affect the longer-term production profiles of the wells, and we're going to be deliberate about that. Economic evaluation. As we're evaluating all of our options for development, the team is constantly keeping an eye on our single most important goal, which is economics. Optimizing the economic return profiles of our overall development is of utmost importance and steers every decision we make. That's not just limited to unconventional development, of course. That brings me to the final part of the diagram, and that's the execution and subsequent iteration as we progress development throughout our lands. We will optimize our operations in real time with a view to any variations to our expected or modeled behavior. In addition, we observe third-party activity adjacent to or sometimes at great distance from our land base to see what's working and what is not. Importantly, we incorporate results from our own wells, which will come with a wealth of information that is only available to the operator. All of this is compared to what we anticipated, continually seeking improvements, and the cycle starts all over again. I will now pass it to Travis to talk about some of our efficiency gains in the Montney as well as our water management strategy. Thanks, Joey. Good morning. I'm Travis Tweit, Vice President of Operations, and I'll speak for the next couple of slides about some of the things that we're proud of on the execution side of these plays. While it's obvious that we need to have an optimized development plan, none of it matters if we can't predictably and efficiently execute our programs. At Whitecap, we take pride in our track record of creating value on acquired assets by improving capital efficiencies. The Montney case study is shown on slide 23, illustrating two key metrics that reflect our current operational performance in the unconventional assets. The first plot is our Montney drilling performance in Kakwa and Musreau since 2021, as measured by total well ROP, or rate of penetration in meters per day. You can see we've made some steady progress here with 2024 year-to-date average of just over 260 meters per day from the 2021 level of 175. This is an overall improvement of about 49%, resulting in a 15% cost savings per well. As we evolve these plays, our drill complete and equip costs will continue to be optimized, which will, of course, improve our capital efficiencies even further. The second plot shows Montney completion efficiency as measured by average proppant pumped per day. It's a similar story here, with increasing from under 2,000 tons per day in 2021 to over 3,100 tons per day in 2024 year-to-date for an overall improvement of about 66%. On an instantaneous basis, we've achieved as high as 5,300 tons of proppant pumped over a 24-hour period, very close to the Canadian record. We expect to see some more improvement over time as our understanding of how to optimize these programs continues to evolve. Another important topic is the sourcing and use of water for our completion operations. Currently, we hold 1.3 million cubic meters of freshwater storage across three pits, which are strategically located in our Montney and Duvernay lands at Musreau and Kaybob. We have a combination of term and temporary licenses giving us confidence that our current development can be executed. As we move into the future, we're planning further build-outs of water sourcing and storage so that we can continue to deliver results year after year. But reliability is only half of the equation. We're also striving to use less water on our completions, and this is to save money, reduce risk, and of course, limit the environmental impact of our operations. We're very proud to show the numbers on this chart, which demonstrate a 22% and a 42% reduction in water use versus pre-2021 levels on our Duvernay and Montney lands, respectively. Although our primary focus has been on conventional water sources to date, we're also looking at strategic alternatives such as source water wells, blending with produced, recycling of frac flowback, wastewater effluent from municipalities, and so on. I'll now pass it back to Joey to talk in more detail about our unconventional plays. Thanks, Travis. Moving on to the geological characteristics of our focus areas and some performance measures. First, we'll stop and note a cross-section that steps through the Montney areas of Kakwa, Musreau, Latour. Things to take away from this are that these lands all contain stack porosity and predictable thickness in net pay. This, combined with the overpressured nature of this rock, which we see as high as 1.3-1.4 times, provides a substantial opportunity to tailor the development, as we had discussed in our workflow section. These multiple zones may provide us the ability to stack or bench our development in certain areas, allowing us to optimize our recoveries on the acreage. Kakwa, as noted, is a familiar asset base to many, and here you can see some of that activity that has been underway for years leading up to this. We first entered the play in 2021, and by the end of this year, we will have drilled 28 wells, which have provided valuable technical information along the way. As we've mentioned previously, it was in Kakwa that we moved to a 250-meter interwell spacing, or 6 wells per section, from 200 meters previous, or 8 wells per section, and the results have exceeded our expectations to date. It is our estimation that we will recover the same resource with 6 wells where previously 8 would have been drilled, and so far, all the rate and pressure data are supportive of that model. Our 2024 activity in Kakwa, highlighted with the red wells on the map, will pursue a triple bench concept in the northwest area of our land base. We will be drilling 3 laterals, one each in the D3, the D2, which has been the primary target to date for us, and the Lower Middle Montney, respectively. The thickness and quality of the sands lends itself to that approach here, and we look forward to providing updates on this initiative in the future. Like other initiatives, while this approach may not have universal applicability, where it works, it will meaningfully improve the economic return profiles of the area. The results of our 2023 wells are shown here, and they are the strongest of the data set across all products and are nearly 54% above the average of previous years and are nearly three-quarters paid out. It is a good example of us utilizing the workflow we've discussed on slide 22, applying it here, and realizing some impressive efficiency gains. Moving on to Musreau, where we have wells that will provide upwards of 75% liquids, we are pleased with the results to date. As mentioned, we're in a well-defined area with a variety of competitor activity that has helped to shape our development plans for this area. As mentioned in our last conference call, the 5-9 multi-well battery was brought on production, ahead of schedule, and under budget. Our planned development in this area will largely be dual bench in the D2 and D3, but will be assessed on a case-by-case basis. Here's a production graph showing throughput at our 5-9 battery back to its commissioning date in mid-March of this year. In the early days, we limited the facility to 10,000 BOEs per day while we brought the facility into its expected steady-state operating condition, and in that time, brought on two four-well pads, which were spud in the second half of 2023, along with one legacy horizontal well. We began staging up volumes in early May and are now producing in the range of 14,000 BOEs a day from the nine wells at the facility. As shown on the graph, we still have another two four-well pads to bring online this year and project to be producing at facility capacity with those. This battery execution is an example of the rigorous planning that goes into all of our plays. That process was on display for this facility build, where we took the time to understand the technical characteristics of the asset, get the facility design right for those characteristics and our intended development, and work closely with our commercial partners and service providers to ensure smooth delivery. This is the exact approach we're taking with Latour infrastructure project, and we expect to be just as successful in delivering a high-quality, well-thought-out, fit-for-purpose facility to support our development in that area for the years to come. Speaking Latour, it's shown here on slide 20, slide 30, and you can see it's a nice consolidated land base that is just primed for development. Geologically speaking, it's an analog to Kakwa in terms of thickness, net pay, and pressure. Something of this scale, with its contiguous nature, has the potential to really drive strong and improving efficiencies over time. Across the 90,000 acres, we've identified between 300 and 450 locations, and as we work through our technical evaluation before the 2026-2027 facility startup, we'll be leveraging the experience gained in our unconventional development and our other operated areas. Our activity to date has been targeted due to infrastructure constraints, and we have prioritized land retention and technical delineation wells with the two drills planned for 2024. These wells will be particularly useful for gathering down-hole information that will help to inform our eventual full development in this area. While targeted, the operated results to date are strong. Compared to the type curve shown at the start of this section, we're seeing a beat of 46% on BOEs. The wells have both made over 100,000 barrels of condensate, and they are already 76% paid out. Suffice to say, this has us excited for what's to come. What's to come is shown here. Planning Latour development has been underway for some time now. As mentioned, we take the time to get things right, and we're at the place where we're confident that we're going to do just that. We have scoped out a location for a multi-well battery similar to our Musreau battery in scope, but roughly double in size. We're finalizing our plans for eventual tie-in of the facility and hope to share that with you in the months ahead. At a high level, we see development commencing in 2026 with some startup wells and a meaningful production ramp to 30,000-40,000 BOEs per day by late 2029. At that point, we'll be at the capacity of our first planned phase, and we'll have an option to expand or to develop at a more modest pace, holding that peak production. We estimate we have over 25 years of inventory to hold this facility flat. Should we choose to accelerate growth, the facility will be designed to allow for a seamless expansion of the overall throughput, peaking at over 85,000 BOEs per day, again with plenty of inventory to work through and realize efficiencies gained through the expansion of an existing facility. We expect this area will provide meaningful free cash flow for the company in the later stages and significantly beyond our five-year plan. Just to the south Latour, we also wanted to highlight our sizable Resthaven land base on slide 33. Covering around 300,000 acres, the 1,000 identified inventory locations hold over 1.2 billion BOEs of recoverable volumes. For scale, our year-end 2023 total proven and probable reserve volume corporately was 1.2 billion BOEs. This enormous and prolific land base is continuing to be evaluated, and we'll look to our current operations to see what sort of efficiencies we can drive in this area to enhance the economic returns of the asset. Moving on to Kaybob, our Kaybob Duvernay is in the heart of the Kaybob liquids-rich gas trend. As we've highlighted here, with upwards of 60-70 meters of net pay and 1.9x overpressured, our lands contain some of the most favorable conditions leading to some prolific results to date and yet to come. We're pursuing enhancement of our inventory by taking advantage of this thick, overpressured reservoir through benching our wells. In this instance, it's not that we're targeting different packages, as is often the case in the Montney, but what we're attempting to do, as shown by the landing depth of our laterals on the type log, is offset the well bores vertically by 15 meters or so in an attempt to maximize the vertical coverage of our completions while simultaneously limiting direct interaction between the wells. Whether it be through improved per-well recoveries or the addition of more inventory, we estimate this initiative could increase our overall accessible volumes by 20%-30%. As shown on the map, is our 2024 program, where we expect to spud 13 wells this year. Another solid set of production results to share with you here as well. A similar story this time, 27% above our type curve with wells 86% paid out to date. The last slide we'll speak on about the Montney and Duvernay before handing it off to Chris and the conventional assets is just how much processing capacity we currently have and are planning for in the years to come. With our Kakwa 15-7 gas plant and recently commissioned Musreau 5-9 facility, along with capacity at third-party facilities in Kakwa, we have focused our development in these areas in the near term and will be expanding meaningfully in the years to come. As we start on the larger development Latour, we want to ensure that we have the infrastructure built out in front of us. We will continue to develop strong partnerships with our commercial partners to advance these strategic projects with the ultimate goal of retaining control through operatorship and freeing up capital to focus on developing our deep set of drilling opportunities. With that, I'll pass it on to Chris Bullin. Thanks, Joey. Morning, everyone. I'm Chris Bullin, the Vice President of our East Division, and I'll be walking you through this next section of our presentation showcasing our conventional portfolio and to highlight our strengths, progression, and results to reaffirm the importance of these assets within the Whitecap portfolio. We think of our conventional assets as the foundation for Whitecap sustainability and profitability as we move forward with our five-year plan. Our conventional division generates over 70% of funds flow in our five-year plan, which is significant in the framework of sustainability, providing the company with stabilized funds flow to support our dividend even in a $50 WTI price environment. This stable free cash flow engine is underpinned by both secondary and tertiary recovery, which drives our base decline rate to below 20%, reducing future maintenance capital requirements. This is a competitive advantage for Whitecap. Our conventional foundation produces over 115,000 BOE per day of 80% liquids, which is predominantly light oil. As a result, these are high net back volumes coming from our Saskatchewan regions with focus on the Frobisher, Viking, Shaunavon, and Weyburn assets, and our Alberta regions that focus on the Glauconite, Cardium, and Charlie Lake plays. These top-tier resources boast a track record of successful operational performance, high confidence inventory with short cycle times, and strong market access. This is built on our ability to identify opportunities for enhancements or optimizations being technically opportunistic so we can consolidate assets at a reasonable price and then enhance them, which in turn drives value and accretion for our development programs. Now, none of this would be possible without our exceptional team. In the coming slides, I'll walk you through our conventional inventory and briefly highlight four focus areas being the Frobisher, Viking, Glauconite, and our world-class Weyburn CO2 flood to highlight our best-in-class results. Now moving to our inventory. Our conventional inventory is robust, highly profitable, and frames nearly a decade of tier one and tier two opportunities in our core high confidence areas. This strong inventory base is the result of years of advanced technical understanding of our assets, allowing us to refine internal benchmarking and optimize project selection. This, in turn, enhances budget accuracy and drives confidence. This high level of inventory confidence also provides Whitecap with the option to tailor our budget programs to adapt to changing price environments and our business needs. With short cycle times and superior market access, we can very quickly call in audible to reallocate or expand capital throughout our extensive conventional areas, a competitive advantage for Whitecap. The remaining tier three opportunities provide a breadth of future upside as our teams continue to advance technology and cost improvements. We have a long history of validating enhancements, as we'll talk about on the slides to come. We allocate a small amount of strategic spending towards our tier three opportunities yearly, such as the Weyburn Frobisher pilot, to validate and upgrade this part of our portfolio. Now on to our highlighted focus plays on slide 40. Widely regarded as one of North America's top tier type curves from a P&L perspective, our Eastern Saskatchewan Frobisher asset remains a focus for us with its impressive economics. As we typically drill around 50 wells per year, we have continued to expand our core land base in the Frobisher with a variety of business development initiatives that have solidified Whitecap's expansive position, as shown on the map, which represents over 70,000 net acres of land. The Frobisher is characterized as our premier conventional, open-hole multilateral, quickest payout, quick cycle time, and strongest IRR asset. Additional benefits come from strong Aquifer support within our reservoir, which can drive recovery factors above 30%. Since the TORC acquisition in 2021, which was our entry point into this area, our technical team has done a fantastic job to quickly pinpoint opportunities for enhancements by adding additional legs and extending lateral lengths. This results in a 2.2 times increase in total lateral length and subsequently a 45% bump to our IP90 rates when comparing progression from 2021 to 2024 versus our expectations. Capital efficiency improvements to our type curves are 26% on an IP365 basis, justifying the additional costs associated with increased lengths and additional legs, which is around 20%. Our operations teams were also quick to identify enhancements and optimizations that further bolstered our volumes and net backs. As shown on the top right of the slide here, the progression of our focus type curves is solid, and the results from our Q1 program are looking great, with an estimated payout occurring at 5 months, which is ahead of our forecast, and over a three-year period will pay out 3 times, which is exceptional. Stress testing down to $50 WTI still has a one-year payout and 100% IRR. Based on the high-quality nature of the Frobisher, it's no surprise the TORC acquisition has already paid out. Now we'll look at how our results compare to industry since 2021, our entry point into the Frobisher. You can see on the cumulative oil versus time plot that we are indeed best in class. Going forward, our team will continue to focus on adding additional legs, reliable, and value added to ensure we're maximizing the recently announced Saskatchewan government royalty incentive, along with our continual pursuit of accretive tuck-in acquisitions to further provide opportunities to enhance our inventory with size and scale, along with operational synergies. Now moving to the western side of Saskatchewan lies another focus play for Whitecap, our Viking assets. Our roots in the Viking run deep as we've drilled nearly 1,000 wells since stepping into this play, characterized as our highest net back, quick payout, fastest cycle time, and strong IRR asset. Since entering the Viking, we have amassed over 300,000 net acres of land and enhanced our portfolio significantly, primarily from extending our lateral lengths using ERH wells or extended reach horizontals. The progression in the Viking has moved from half-mile wells to one-mile wells or even 1.5-mile wells. This has resulted in a 2.2 times lateral length increase when comparing the progression of our type curves from 2015 to 2024, subsequently bolstering IP90 rates by over 40% and reserves by 1.5 times currently. We expect to validate additional incremental reserves over time to further support the additional reservoir contact with ERHs. Our 2023 and 2024 results are on track with type curve expectations, and our Q1 2024 program is estimated to have an average well payout occur at eight months. Our activity levels in the Viking target around 100 wells per year. Although the volumes are not as impactful compared to others in our portfolio, with spud to on-stream timing within weeks and multi-rig programs set up for operational efficiencies, we can add these highest net back volumes faster here than anywhere else in our portfolio. Our performance compared to our peers since 2015 is shown here on slide 43, showcasing again our best-in-class results in the Saskatchewan Viking. There continues to be future opportunities to implement more 1.5-mile ERHs to further reduce our footprint and maximize efficiency. We recently bolstered a Viking inventory at the end of last year with a synergistic acquisition in the Elrose area. What was previously an area with two dominant players is now consolidated into a Whitecap dominated area. Accretive tuck-ins provide us with opportunities to further enhance our inventory as a larger contiguous land base improves our ability to control infrastructure, development pace, and increase our ERH 1.5-mile counts. As a refresher, this acquisition increased our Viking tier one and two portfolio by over 400 locations with purchase price metrics of 1.7x operating income, which equates to 64% of total proven value. Now switching provinces over to Alberta, I'll now talk about our Glauconite play, which became a focus area for us as part of the NAL acquisition and subsequent TimberRock acquisition, which fortified our position in the central Alberta Glauconite with over 85,000 net acres as shown on the map. The Glauconite is our most meaningful conventional focus area type curve as it drives robust volumes with our IP90 expectations at 750 BOE per day and sizable reserves approaching 1 million BOE per well. Although a lower liquid weighting at around two-thirds when compared to our Frobisher or Viking plays, you can see on the type curve metrics that the Glauconite can hold its own with payouts at less than a year at $75 WTI. A notable mention here is that we benefit from an expansive interconnected infrastructure that is predominantly Whitecap owned and operated. This provides us with flow optionality to ensure we have adequate takeaway capacity to get our product to market. Post-acquisition, our team was quick to assess enhancement opportunities with longer laterals and increased awareness of geohazards, which improved our target zone placement. The resulting type curve progression from 2021 to 2024 yielded 1.75 times longer laterals, which has increased our IP90s by 40% and improved capital efficiencies by almost 20%. As previously mentioned during our Q1 conference call, our recent results continue to exceed our expectations as shown on the cumulative production versus time plot, with the program payout estimated to occur at nine months. The Glauconite continues to be a key focus for us in Central Alberta with its highest allocation of capital spending for this region as we target around 15 wells per year. And now how we stack up against our peers. In this example from 2021 to 2024, we are best in class yet again, further highlighting Whitecap's strength in our conventional assets. Similar to the Frobisher and Viking, future enhancement opportunities reside in maximizing efficiencies through ERHs to improve our full-cycle development returns, particularly with our two-mile laterals being our benchmark. A key focus for us going forward in Central Alberta will be our expansive land base that has a breadth of multi-zone potential within the Cretaceous section, in which Whitecap owns over 200 sections. These lands include formations such as the Nisku, Blairmore, Wilrich, and Ellerslie. We have already identified some areas of interest that would yield tier one or tier two opportunities with improved natural gas pricing. We're also looking to synergize these opportunities with our existing Glauconite and Cardium inventory to optimize the overall development economics. Other approaches to maximize or accelerate value on these lands are also being assessed. Our last asset today is our Weyburn property. It's the largest anthropogenic carbon capture, utilization, and storage project in the world, which has safely injected over 40 million tons of CO2 since injection began in 2000. As mentioned by Grant, this world-class CO2 flood was acquired in 2017, and Whitecap is the operator and majority interest holder. A key takeaway for the Weyburn asset would be the ultra-low base decline. At a 2% annual decline rate, this is our most sustainable and predictable asset within our portfolio. The map here highlights the Weyburn unit boundaries. The darker green shading within the unit showing areas that are under CO2 injection already, and the lighter green area showing future unit development where CO2 injection is planned, along with future upside, sorry, along with future expansion lands outside of the unit. We'll reference this in the next slide as upside. Now, slide 47 really drives home just how world-class the Weyburn CO2 flood is. With approximately 1.5 billion barrels of oil in place based on internal estimates and over 500 million barrels recovered to date, this frames the future value of this asset. As shown in the oil production progression plot, which starts in 1955 and goes to 2060, by the way, fairly non-typical to show nearly a century timeframe, you can see the impacts of the three key development stages, the first being the primary plus water flood development, followed by the next round of development before CO2 injection, and then finally once CO2 injection started in 2000. These three phases of development have resulted in a recovery factor to date of approximately 37%, with an estimated ultimate recovery factor of 44%. Not included in the recovery factor estimates would be the final stage of development or the upside wedge, which is meaningful. The upside wedge in Weyburn is split into three key components, the first being expansion of the CO2 flood within the current unit boundaries and represents our highest confidence, normal development activity over the next 10 years or so, as previously highlighted on the map on the prior slide. The second component is CO2 development opportunities identified on acreage outside of the unit, with the third component being the Frobisher zone, which is underlying the Weyburn unit, which we've recently piloted CO2 on and we're continuing to gather information. Also to note on the plot is the 18-year timeframe from 2006 to 2024 during CO2 injection, which represents a year-over-year decline of only 1.7%, impressive to say the least, and highlights the proven track record of sustainability unique to Weyburn. We are excited for all future opportunities this best-in-class CO2 flood has to offer, and this is a prime example of how enhanced oil recovery projects can drive exceptional economic returns while achieving the objective of reducing CO2 emissions in Canada. This concludes our conventional section. We hope that we've left you with an increased confidence as to why these assets make Whitecap stronger, as shown by our exemplary track record of enhancement opportunities that has led to best-in-class results. With that, I'll now pass this off to Thanh to cover our financial priorities. Thanks, Chris, Joey, and Travis. We're excited about our base outlook and confident we can execute our plans over the next 5 years and see tremendous opportunities to enhance the base model. You can see on the chart to the left that at $75 WTI, we'll return CAD 2.2 billion in dividends to shareholders based on the annual dividend at CAD 0.73 per share. We'll allocate CAD 825 million to share buybacks, which will reduce our shares outstanding by 10%-15% and still have CAD 1 billion to put against our balance sheet. With the $10 increase to WTI, we'll double the number of shares we can repurchase to CAD 1.7 billion. With the $10 decrease to WTI, we'll still be able to grow the business by 5% per year and generate CAD 2.2 billion of free funds flow to both fund our dividend and strengthen our balance sheet. The balance sheet is in excellent shape with forecasted year-end net debt of CAD 1.2 billion on CAD 2.9 billion of total credit capacity, resulting in a debt-to-EBITDA ratio of 0.6x. Over the next five years, with significant free cash flow generation, net debt is forecast to be nominal at the end of the five years. Our objective is to maintain leverage at or below 1x debt-to-EBITDA through commodity price cycles. Under our stress test price deck of $50 WTI and $2 AECO, net debt is targeted to be CAD 1.3 billion longer term. This means that over the five-year period, we have the potential to reallocate CAD 1.1 billion towards incremental shareholder returns through share buybacks and/or continued consolidation in our core operating areas. Even at $65 WTI, we could still allocate over CAD 500 million to share buybacks and keep our debt at CAD 1.3 billion. We feel confident in our ability to execute on the base five-year plan. Both Chris, Joey, and Travis have identified opportunities we are implementing, whether well or completion design changes, interwell spacing adjustments, lateral length increases, or additional legs that are expected to increase our capital efficiencies and reduce cost over time. Small improvements to our base plan can result in meaningful increases in free funds flow. A 10% improvement to our capital efficiencies and a 5% reduction in operating costs would result in over CAD 800 million in incremental free funds flow. It's important to note this is incremental to our accelerated growth option, which adds 20,000 BOEs per day. This combined with the potential for capital reallocation for the balance sheet provides us with significant optionality over the next five years. Lastly, on slides 52 and 53, I'll touch on our crude oil and natural gas marketing. On crude oil, the key takeaway here is that we have an expansive and advantageous network of pipeline access across western Canada that facilitates our high-net-back crude volumes, currently comprised of 72% light oil, 16% condensate, and 12% medium gravity oil. Our condensate delivers into the Edmonton-Fort Saskatchewan complex. Our light oil delivers to Edmonton, Hardisty, and Cromer, and our medium oil, which receives a premium to WCS, delivers to Regina. Access to markets is further enhanced by our firm service agreements and reliable pipeline egress. With the Trans Mountain expansion now fully operational as of Q2 2024, we benefit from the additional pipeline egress this project has created, along with improved differentials on all grades of crude. In Q1 2024, light oil differentials were minus $10 per barrel and have now narrowed to approximately minus $3. Medium oil differentials went from minus $17 per barrel to minus $11 currently. We anticipate current differentials to continue to be narrow moving forward with ample export egress out of Canada. As Whitecap's growth over the next five years comes primarily from the Montney and Duvernay, we'll expand our condensate volumes by nearly double from approximately 15,000 barrels per day currently to almost 30,000 barrels per day in 2029. Given the anticipated growth of heavy oil sands production and fully utilized diluent pipelines, we are bullish on condensate demand. Condensate differentials have less price sensitivity to pipeline egress and will remain strong. As we saw in Q1 2024, condensate differentials were minus $4.18, improving marginally to $3.60 per barrel currently. On the natural gas side, we have secured long-term transportation agreements to support our growth plans. Currently, our gas commands a premium price compared to the AECO benchmark, to which 70% of our 2024 production is exposed. As we move into 2025, Whitecap has increased our AECO fixed price hedges from 16% to 30%, and we'll continue to target that 25%-35% level beyond 2025. We're continuously exploring opportunities to diversify our natural gas pricing exposure, both physically and financially, expanding our presence into other North American and global markets. With our involvement in the Rockies LNG partnership and the Ksi Lisims LNG project, we have committed 100 million cubic feet per day, or approximately 20% of our future natural gas production. We'll look to expose a further 10% of our future production away from floating AECO and into other North American markets, such as the US West, Henry Hub, Eastern Canada, or to add to our current US Midwest exposure. That said, if specific opportunities are accretive to our strategy and net back, we would go beyond that 10% level. Another critical aspect of our production development and growth strategy is the alignment of processing, transportation, and fractionation firm service commitments. As we look to the future, we are confident in our NGL transportation and fractionation capabilities, especially as capacity is limited in the short to medium term. With that, I'll turn it back over to Grant for closing remarks. Thanks very much, Thanh. I would like to conclude by saying that our historical results and future performance are the product of our current areas of operations, our large growth inventory, and our best-in-class people at Whitecap. As we take pride in fostering a culture of continuous improvement and making thoughtful decisions with rigorous technical analysis behind it, to continue to strengthen the business on behalf of our shareholders. Our strategy and our focus remain the same, which is to continually increase our profitability by using debt prudently, which in turn improves our long-term sustainability and ultimately the higher share price. Our team is extremely excited about the future of Whitecap, and we look forward not only to executing on our five-year plan, but also to look forward to the opportunities to enhance this base model by increasing our cash flow and free cash flow per share. With that, I'll now turn the call over to the operator, Sylvie, for any questions. Thank you, sir. Ladies and gentlemen, as stated, if you do wish to ask a question, please press star followed by one on your touch-tone phone. You will then hear a three-tone prompt acknowledging your request. If you would like to withdraw from the question queue, 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 do have any questions. Your first question will be from Travis Wood at National Bank Financial. Please go ahead. Yeah, good morning, guys. Thanks for the rundown. Found it interesting, and it looks like you've provided a bit more detail both around opportunities and inventory at Resthaven Latour. Do you see any development issues as you look to grow that part of the portfolio out, both from an infrastructure or pipeline or egress issues? Are there any concerns as you map out that five-year growth plan? Hey, Travis, it's Joey Wong here. Yeah, the short answer is no. When we're looking to build out our facility plans there, we'll make sure we're backstopped with both, of course, our infield infrastructure, the associated processing, and then everything, of course, downstream of that. So not going to be a concern for us at the levels we're planning. From an environmental side, are there any issues in terms of permitting and working with stakeholders in the area to get the facilities up and running as well? Yeah, for sure. I can take that one as well, Travis. So referring to probably to some of the access restrictions in the area, I presume? Exactly. Yeah. So, I mean, to kind of take that one head-on, with respect to the Caribou access Latour, the short answer is no. We're not concerned about that. The majority of our development in both the near and the medium term Latour is outside of the Caribou boundary in this area. As we step into full development of the area in the coming years, we're going to be pretty thoughtful on pacing out a portion of that inventory in those areas to make sure we have a balance both inside and outside of those boundaries. And, I mean, those regulations, they're pretty well known. They allow us to be in the year for seven months or in the area for seven months out of the year. And, of course, there's exceptions to that with respect to all-season roads and things like that. When you look at our activity set with four focus areas, we don't think we're going to need to be in there full year anyways to develop it appropriately, irrespective of any kind of restrictions. We have plenty of places to send our rigs to balance activity and still develop it at a pace that we're going to be comfortable with. Okay. Fantastic. And then just last question, just around funding that growth funding facility expansions, kind of two parts to this. Are there opportunities as you look at infrastructure and kind of excess incremental egress facilities that are within the basin that are more modular that you can, rather than build new facilities? Are there any opportunities to leverage off existing facilities that are effectively for sale right now? That's Joel here. I think primarily we're always focused on the front-end part of our infrastructure, the gathering, compression, battery side of it. And there's a pretty robust amount of processing available. So trying to marry those two up, it would be our primary focus. And to also mention, there's a large amount of infrastructure capital that is required on our unconventional assets here in Alberta, not just Latour. And we expect that midstream asset managers will play an important role in how we build out all that infrastructure. Okay. That's all for me. Thanks for taking that. I'll turn it back. Thank you. As a reminder, ladies and gentlemen, if you have any questions on the phone, please press star followed by one. Next is Christian Comeau at Peters and Co. Please go ahead. Hi, good morning. Thank you for taking my questions. Maybe just a follow-up quickly on Travis's questions. I was just wondering, in terms of that upside growth wedge of 20,000 barrels a day on the conventional side of the business, what would be kind of the biggest drivers around that? Is it a type group specific thing? You want to further prove out the potential productivity there Latour, or is it a commodity price dictated? Just trying to think about, yeah, that potential upside and whether or not we'll see it translate in the five-year plan. Yeah. Hey, Christian, Joey Wong here. So yeah, that 20,000 BOE per day by 2029 wedge, that's on the unconventional side. That involves advancing the pace of our planned inventory. Subsequent to that, of course, as we get to the capacity Latour phase one, we'll probably look to advance then infrastructure build-out to get in front of what's after that. So it's not necessarily that we're budgeting in a type curve beat or a capital efficiency beat or anything like that. We're taking our existing plans and advancing them to the extent that we feel is operationally feasible. Really sticking back to what we had said at the outset there that our goal is to be predictable, to be repeatable, to be able to do what we say we can. You look at an inventory set like this and you can start to dream a little bit, but we make sure that even the high side is very realistic. That's what that is. For sure. And then, yeah, maybe a higher-level question as it relates to the inventory in the Montney and Duvernay, roughly 15%, as you identified, is booked here in 2P. So there's certainly a lot of unbooked upside on this asset base. So can you maybe just help us understand what the potential upside looks here? Do you see these assets as ultimately supporting a much higher plateau than that 100,000 or 120,000 barrel a day level by 2029? And yeah, yeah, what's the longer-term upside? Yeah, absolutely, Christian. Again, Joey here one more time. You're right. With that 15% booked conventional inventory, yeah, it's light for sure. Our unbooked inventory, or sorry, our booked inventory, we have a value at year-end of $5.3 billion. That was at year-end 2023. And internally, we have our estimates of our unbooked inventory in and around $10.4 billion of unbooked value at $75 WTI and $3 AECO, which equates to, if we look at this on a per-share basis, that's $17.39 per share. And for context, our year-end NAV after deducting net debt was $21.60 per share. So yeah, there's a tremendous amount of upside there that we have the ability to unlock. Okay. And maybe, yeah, switching gears just to the conventional side of the business, also on the inventory side, could you kind of walk us through the quality of the remaining inventory that you assign as tier three? You obviously presented what you kind of plan to drill within the tier one and tier two buckets, but do you see opportunities in certain areas as you increase lateral length on the conventional side of the business, or you get potential royalty uplift in Saskatchewan that could really improve the ranking of some of this inventory and it would fall within the five-year plan? Hey, Christian, it's Chris here. Thanks for that question. So from an inventory perspective on a tier three basis, really the objective for us here is to move that inventory into tier two or tier two into tier one with either technology or operational optimizations. That's going to increase longevity in these plays through our business development initiatives as well. Kind of like what we did in the Elrose Viking acquisition in Q4, where we added 400 locations there, top quality locations, that is, primarily tier one. So of course, we have a history of doing this consistently, and that's a key driver for our technical team. And year-over-year, we've framed those enhancement initiatives, notably leveraging the ERHs, which have steadily upgraded our inventory. For instance, in the Viking play, again, our transition from drilling 2 half-mile wells to a single 1-mile well has resulted in 25% improvements in capital efficiency. So similar advancements can also be observed, we'd say, in the Glauconite and the Cardium plays too. So definitely a lot of applicability on that going forward, where we extended from 1-mile to 2-mile wells with reference to the Glauconite and the Cardium plays. Another upgrade consideration, I guess, from a tier three perspective would be that we do have a lot of locations, I'll say about 350 locations in the tier three category that are just outside of the tier two cutoff. And those are going to be directed towards our highlighted focus plays that we talked about there today. And with minor adjustments to cost improvements or pricing, we'd see those move up into that tier two category. Additionally, I guess we allocate a portion of strategic capital to less developed areas with those lower confidence levels. Our aim there really is to validate and lock that potential. So again, we'll look to leverage our robust land-based holdings and infrastructure across all of our core areas, where generally we're uniquely positioned, right, to capture value from these upside opportunities. At the end of the day, our inventory is our feedstock, and it's constantly being reworked and updated. And our teams are always looking for ways to further enhance that. I guess from a shifting gears over to the component about the multilateral open-hole royalty as it relates to Saskatchewan, for us, it's definitely something that our teams are looking at as it relates to the Frobisher, where that royalty incentive kicks in, where you have more than three legs. Generally, we're targeting 2-3 legs, and these are vertically stacked flow units in the Frobisher. So rarely there's a fourth leg. So it's a per well evaluation, and there has to be a value-add basis there. And it's done on a case-by-case basis, but it's definitely something that we're looking at going forward. I'd say about 10% of our inventory right now is classified as triple-leg wells. So yeah, it's definitely a value-add component for us that the teams are actively looking at. Great. Well, that's all I had. Thanks again for taking my questions. Thank you. At this time, gentlemen, we have no further questions registered on the phone. Please proceed. Okay. Joey Wong here. I see a couple of the written-in questions, so I'll read the first one here. First in line here looks like Dennis Fong. I'll read the question out loud first, then we can reply. The question says, "As well productivity has outperformed type curve, how should we think about the potential to upwardly revise your five-year plans as execution continues on development? Secondarily, if you're able to generate better-than-expected capital efficiencies, would you prefer to grow more or generate more free cash flow?" So the first part of that answer is a pretty easy one, and the answer is, yeah, we're pretty hopeful that the beats will continue. And quite frankly, that's how we view our roles here, is to continue to get better, build on our results, build on successes, whether that is from a development point of view. We touched on things like benching and spacing and technical excellence, but then importantly, on all the things that Travis touched on, making sure we are deliberate and efficient with every bit of prop that we place, every moment we're on a well drilling, and everything we do after the well is drilled and completed. So the short answer is yes, we hope to be able to outbeat our type curves. For the second portion there, maybe I'll pass it off to Thanh. Yeah. Thanks for that question there, Dennis. Look, I think we're comfortable with the base five-year plan. We have not incorporated any adjustments to our type curves at this time here. If we continue to outperform with some of the optimizations that we're looking at here, there's certainly potential to uplift our five-year plan. It can be meaningful to our shareholders here. As I've talked about there, it's just shy of CAD 600 million with just a 10% improvement to our capital efficiency. In terms of our preference for generating more cash flow or growth, I think when we look at our targeted growth rate at that 3%-8%, it's important to note that at the end of the 2029 period, what we're looking to manage towards is a 26% decline rate. The higher the growth, obviously, that'll impact our decline rate at the end of the five-year period there. I would say that anything above that targeted level of growth, 3%-8%, our priority is to prioritize free cash flow versus excessive growth. One more question there from Dennis. Sorry, Dennis, it looks like I got your questions out of order there. This was your first one. But anyway, the question says, "When looking at developing multiple benches, how do you think about balancing capitalization of the play versus inventory depth?" Yeah, thanks, Dennis, for that one. Honestly, Dennis, on that one, it's a pretty easy answer for us. The answer is economics. When you look at drilling with multiple benches, of course, like we talked about, you get to contact more rock vertically and also limit the interaction between the wells. So at the end of the day, when you're looking at an asset base like this, our primary goal is singular. Again, that's to maximize the economic benefit, period. In terms of cost of going to different benches, that's something we're keeping an eye on. We recognize that you get to balance the efficiencies of drilling multiple benches at the same time once you're there. An example of that is in Kakwa. When we look to go in there, we're expecting to be able to drill, like we suggested there, our three benches. And based on our offset analysis, all three benches should treat pretty similarly. And that is something we do look at, though, is how the wells will drill, how the wells will treat, and then ultimately, like I say, pivot that into an economic decision. Okay. The next question I'll read aloud here, Thomas Matthews from Peters. "Can you quantify what proportion of the recent well results being at the high end of your type curves are the result of well design or spacing changes versus rock quality? Can you walk through what it would take to feel comfortable in the repeatability of beating type curves in your unconventional assets? How will the drilling completions, water use, and cost change with drilling the lower zones, and when will you start to drill the lower zones?" So I can touch maybe on the first part of that, and maybe Travis can open it up here as well. So in terms of the beats of the type curves, the answer on that one is it's a bit of both. So in Kakwa, when you look at that, that is directly a result of a development choice. Like we said there, if you had gone with kind of a copy and paste or a rinse and repeat of what's adjacent, you would have drilled 8 wells, and we would have gotten on an acreage basis, by our estimation, the same amount of recoverable as we're going to get with the 6. So that's a result of our choice. Of course, you can't do that without good rock, but a choice in good rock. The result in Kaybob that we're showing the beats there, that's going to be more heavily weighted towards the rock if we're looking at the results to date. Our tonnage, our well design is relatively consistent with development that we've had in the area to date. But again, as we look to change with respect to benching there, if we see an improvement from there, we can point to that as the win there. As we talk about, yeah, the differences in treating the different benches, maybe I'll pass it off to Travis to speak a little bit about that. Yeah. Sounds good. The benching that we've done so far in Musreau has actually been very well executed by our teams. And we found that on the drilling side, the D3s are taking a bit longer to drill, a few more bit trips, so an extra 2 days per well. But on the completion side, to our surprise, they treated very well and very comparable to the D2. So our overall water usage was really not that much different. Yeah. Okay. So the next question we've got here is, "Please explain what is the next trigger for the next dividend increase." And the second part is, "The expected percentage increase in the dividend correlates to the cash flow or production percentage increase." So I think when we think about the dividend, we're comfortable with the current rate, as I've talked about in that CAD 0.73 there, as it provides strong capital returns back to shareholders currently yielding that 7%. So we're really not in a hurry to increase our dividend at this time. Longer term, though, we do want to grow the dividend commencement with our growth rate at that 3%-8% annually. But at this time, given where our share price is currently valued at, our focus will be on share buybacks. But as I talked about, longer term, we want to grow in tandem with our growth rate in that 3%-8%. Okay. Next question from Aaron at TD. "You gave your anticipated aggregated decline rate at the end of the five-year plan. Are you able to get a little bit more granular? At the end of your five-year plan, where do you anticipate your decline rate to be for each of the areas? Want any Duvernay assets and conventional assets? What is the role of your carbon capture initiatives within the five-year plan between now and 2030? Do you see Weyburn as a production growth area?" So I can probably take the first one in terms of a bit more granularity on the decline there. So at the end of that period in the Montney Duvernay, we see our decline rate in the 30% range there. Pretty manageable when you look at the growth that we're planning and the capital efficiencies associated with it. We're feeling like we're in a pretty good spot with those numbers. Hey, it's Chris here. Related to declines on the conventional assets, it's around 20% that five-year profile. A lot of that's underpinned by our efforts to support EOR initiatives, which helps to drive that down and the funding therein, so. The last part, Mombourquette. Yeah. Thanks, Aaron, on your question on the role of carbon capture and our initiatives within the five-year plan. Although we're very pleased with our progress we've made on our carbon capture initiatives to date, the movement towards FID is not as quick as we would like, and it's further constrained by a lack of clarity and changes around regulations. With success, we could create additional cash flow upside, but that capital and cash flow is not reflected in our five-year base case at this time. We certainly have the technical expertise to safely manage captured CO2 and are currently working to lever off that expertise through our four carbon hubs, one we have in Saskatchewan and three in Alberta. They're in various stages of execution at this time, but between the four projects, we have the potential to capture 7-15 million tons of CO2 annually. Also keep in mind that we currently sequester 1.5-2 million tons of CO2 at Weyburn annually. Okay. Next question from Noor at BMO. "How many benches do you see across your Montney acreage, and how does this impact your inventory versus how you consider developing it?" The second question, "You've been historically quite acquisitive. As you've detailed in this presentation, how do you see the M&A landscape going forward for Whitecap?" So the first question, I can take that one. Sorry, Noor, this is Joey Wong again. So in terms of benching, if I take a quick step back, as we touched in the presentation, we believe that our strength is that we don't seek a blanket approach across our land base or even within a focus area, but we instead look to the specifics of each area and then optimize around it. And benching is one of those decisions along with well spacing. These really have the ability to move our well performance up the curve. So to give a bit of an idea of what this targeted approach looks like, in Kakwa, where we have the three zones present that we talked about in varying quantities and qualities, we've identified areas that are either single bench, double bench, or triple bench within Kakwa. The single and double benches, even then, aren't the same either. For example, in the double benches, sometimes we're doing the middle and the upper. In some parts of the acreage, it looks like it's the middle and the lower that's got the optimal development there. So it really depends on the local characteristics. Again, like I touched on earlier there, at the end of the day, we're making an economic decision. Obviously, to talk about some end members here, and these become pretty obvious, but if we think we can access 90%-95% of vertical stack with a single set of wells, well, the answer is going to be obvious. If we think there's going to be benefit to benching and getting those fracs to grow vertically into places that they might not have from a single bench, we're going to start to look at that approach. And once you've done that, then you can look at tightening up spacing up to account for those staggered laterals or determine if you want to adjust your fract geometry and see if horizontal depletion can make up for some of that. So that's kind of a technical answer around it. But across our land base, if you look at the impact of benching and potential spacing changes, yeah, you can easily see yourself in an area adding 25%, a third of incremental recoverable volumes with some of these initiatives, whether that's through more wells or better recoveries from the currently identified locations. Hopefully, that makes sense. I'll take the second part of that question. You've historically been quite acquisitive, as you've detailed in your presentation. How do you see the M&A landscape going forward for Whitecap? Acquisitions have been and will continue to be a part of us getting to our 170,000 BOE per day and our current long runway of growth opportunities. We will continue to look for ways, as Thanh had mentioned, to enhance our five-year business model on both existing assets and through consolidation in our existing core areas. We usually get rumored with the acquisitions of the day, and perhaps we should, as our BD team keeps a pulse on all potential acquisitions. We don't want to get larger for the sake of getting larger, but instead to look to make our business stronger by giving us more scale to cash flow, free cash flow from our high net back production and highly economic inventory. We'll continue to remain disciplined on this. Again, acquisitions are certainly not prescriptive, but we do want to be creative around how we look at acquisitions for the benefit of our shareholders going forward. Okay. So the next question, "When you're looking at your balance sheet, what would be your drivers for lowering debt below the 1x at mid-cycle levels?" And the second part is, "Is there a level you'd feel comfortable increasing the proportion of free cash flow being allocated to shareholder return?" So when we look at our capital allocation strategy from a free cash flow perspective, there's always going to be a portion that we're putting against the balance sheet. So naturally, leverage is going to be below 1x. I mean, at the end of the first quarter, we were CAD 1.5 billion of net debt, which was 0.7x debt to EBITDA. By the end of the year here, we'll be less than CAD 1.2 billion, which is 0.6x. So really low leverage. As I mentioned in the five-year plan there, it's really nominal debt at the end of 2029 at CAD 200 million there. With respect to when we'd be comfortable increasing that percentage of free funds flow back to shareholders here, I think when you look at our history, I think growth is important both through share buybacks on a per-share basis, but also consolidating within our core areas here. So we think there'll be opportunities over the next five-year period of time here to enhance that return profile for our shareholders. So we're continuing to be in growth mode. So we're not in that camp where we're going to be returning 100% of free funds flow back to shareholders. I think 75% is a good number for us going forward here. Joel here. Next question is Chris at Desjardins. With respect to slide 38 on strategic infrastructure investments, how open are you to bringing in third-party capital or a midstream partner to fund and/or Latour phase one and two? I guess in short, on balance, when we're looking to form a partnership with some of these infrastructure and associated processing and liquids capture projects, we'll balance a good portion of OPEX or fees on new build infrastructure with synergies on processing and downstream services, which would allow us to use our scale and future growth potential to create win-win partnerships. So I guess in short, the answer is we're certainly not opposed to forming a relationship in strategic areas. Any further questions? None on the phone, sir. Okay. Well, thank you, Sylvie. Once again, we appreciate you for everyone on the call today taking the time and interest to listen to our inaugural Investor Day presentation. We are excited to continue down our path and generate significant free funds flow and value for our shareholders now and for many years to come. Wishing you each a fantastic summer ahead. Thanks very much for signing in. Bye for now. Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. At this time, we do ask that you please disconnect your lines.