MEG Energy Corp. (MEG) Earnings Call Transcript & Summary

Good morning. My name is Ludy, and I will be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy Business Update. The conference is being recorded. [Operator Instructions] I will now turn the meeting over to Lyle Yuzdepski to speak, Senior Vice President, Legal and Corporate Development, please go ahead, Mr. Yuzdepski.

Thank you, Ludy. Good morning, everyone, and thank you for joining us. We are excited to share our 2024 business update, delivering value, Canada's leading pure-play oil sands producer. Before we begin, I'd like to remind all participants that today's comments contain forward-looking information and refer you to the advisories located at the end of our presentation, which is posted on our website, megenergy.com. Unless otherwise noted, all numbers presented here today are in Canadian dollars. In addition, certain financial measures referred to in this presentation are not prescribed by Canadian GAAP. For a description of these financial measures, please refer to the advisories. We'll begin our presentation today with a strategic overview and outlook. Our CEO, Darlene Gates, will introduce exactly who we are and how we've succeeded in building the lowest-cost single-asset thermal oil producer in the Canadian industry through disciplined and operational experience. We'll also share how our strategy will continue to build significant and sustainable returns to the future through low-risk, low-cost operations. We'll take an in-depth look at our Christina Lake asset, which will show why we consider it the best resource in the industry. We will then discuss our facility expansion project and lay out exactly how our operational excellence and innovation drives continuous improvement in the field and how this fits into our framework of cost-efficient disciplined growth. In our market access discussion, we'll take some time to demonstrate how MEG is perfectly positioned to leverage our improved market access to serve growing global demand, while mitigating future price constraints. A deep dive into our financial outlook and capital allocation strategy will provide detail to our 2025 budget and guidance, which was announced last night and represented foundation for our multiyear plan to build and enhance value at Christina Lake. Finally, our CEO will provide some closing comments. We will then open the lines for your questions. Our presentation today will be led by our CEO and 4 of our senior executives, whose expertise and leadership will be driving our strategy. Mike Dlugan, Vice President, Development; Tom Gear, Senior Vice President, Oil Sands; Erik Alson, Senior Vice President, Marketing; and Ryan Kubik, our Chief Financial Officer. With that, I'd like to turn the business update over to our CEO, Darlene Gates. Darlene?

Thank you, Lyle. Good morning, everyone. On behalf of the entire executive leadership team, it is my privilege to welcome you to the first ever MEG Business Update. Before I jump into the details, I want to step back for a minute and answer the question, why are we here? We're providing this update now because it's a milestone in our journey. We've been working hard over the past few years to strengthen our balance sheet and to design a strategy that drives the highest value for our shareholders through the commodity cycle. We have completed the technical work to evaluate all of our options, and we've determined that the facility expansion project gives our investors the best returns in all the price environment. The following is a culmination of all our herd work and is intended to provide clarity on our future plans to maximize shareholder returns. Now let's begin with where we're at by the numbers. Through a disciplined approach to capital allocation and operations, we have built an industry leader with an enterprise value of $7.4 billion, total net debt of less than USD 500 billion, daily production of more than 100,000 barrels backed by 1.9 billion barrels of 2P reserves. We've generated $923 million in free cash flow over the last 12 months and initiated the company's first-ever dividend. As impressive as these numbers are, is not the key reason why I personally keep investing in MEG. What excites me the most about the future of our company is that as I look around the energy sector, MEG is unique. The company provides the market with a concentrated top-tier oil sands play that has a proven operational record and is dedicated to returning 100% of free cash flow to our investors. In addition, MEG provides discipline, low-risk organic growth. What I'm most proud of is the 500 MEG employees whose commitment every day is the safety, operational excellence and innovation. It underpins our mission to be the very best in low-cost, high-quality thermal oil production. Now one of the chief benefits of operating a single best-in-class asset is that it allows for a clear vision and a focused strategy, unclouded by complexities that can impact other producers. Our strategic growth plan is driven by 4 pillars: First and most important is a derisked inventory of high-quality resource which positions MEG for multiple decades of highly economic, low-risk organic SEGD growth. We pair this resource with our relentless focus on safe, reliable, predictable and low-cost operations, which we collectively call operational excellence. Next, we maximize the netbacks from our production through global market access utilizing egress capacity and deep marketing expertise to connect our barrels to the markets at home and abroad. As we achieve these first 3 pillars, it creates resource-driven value with significant shareholder returns, which we deliver through share buybacks and a base dividend that is positioned to grow. We're excited to share our capital allocation strategy for the next several years, but I need to pause for a moment to make clear. But this commitment to enhance shareholder returns is not a pivot. It's an evolution built on a solid foundation of value creation. MEG has a track record of creating value, which is demonstrated in these 4 charts. Our growth in production has climbed to records over the past 4 years. Our multiyear deleveraging program has reduced our net debt by USD 1.8 billion. We have delivered a significant reduction in shares outstanding. And our stocks compound annual growth rate is 30% over the past 4 years. When I'm asked about MEG's journey, I describe it in 3 distinct phases. MEG began as an entrepreneurial start-up company with rapid expansion. Our second phase was characterized by strengthening the balance sheet and optimizing operations. And as we enter the third phase, we are focused on return of capital and disciplined growth. 2024 has been a benchmark year. We achieved our net debt target. We transitioned to a 100% free cash flow return of capital and initiated our inaugural base dividend. And now our focus is on 2025 and beyond, with a strategy to drive disciplined growth that supports enhanced free cash flow. All of this work has allowed us to make this important transition in 2024 to a new era of long-term enhanced shareholder value realized on the back of a resilient balance sheet, a multiyear resource delineation program that derisk future investment opportunities, capital-efficient organic growth that adds new sales at lower costs, greater access to Tidewater and the global markets, thanks to TMX, our quarterly dividend is now in place and has room to grow, commitment to returning 100% of free cash flow to shareholders, operating expertise that drives enhanced values and support the robust cash flow that is resilient across a range of price assumptions. This creates the framework, which gives us the confidence and conviction to share with you for the first time an outlook to the end of 2030. Okay. At the risk of stealing a bit of the team's thunder, I want to introduce our multiyear outlook. Our growth plan seizes the opportunities of our outstanding resource base with investment projects that are within our team's wheelhouse and includes the transition to a more efficient turnaround regime, which Tom will describe in more detail soon. This will drive disciplined and moderate growth in production, but even more significantly, it will power a 20% CAGR in our production per share, thanks to our capital allocation program. You can see how our multiyear investment plan, which again sits firmly within our cash flow growth, remains stable over time while supporting growth and enables access to increasingly higher quality resource. We are confident this will generate higher cash flow and an improving sustaining CapEx in future years. For us, the vision and strategy comes down to serving our shareholders. And to do that, our growth needs to drive a sustained improvement in our free cash flow. This plan allows us to return over 65% of our current market cap to shareholders between now and 2030. Most of the cash flow will be directed towards share buybacks that is anticipated to result in a significant reduction in share count over the period. And the net result to our shareholders will be a greater than 20% free cash flow CAGR. We're proud of the work that has gone into this plan, and the results we're driving on behalf of our shareholders. With that, I'll hand the presentation now over to Mike and Tom who will show you why we to consider our Christina Lake resource, a foundation of this plan to be unparalleled in the industry and how our operations drive value for our shareholders. Over to you, Mike.

Thank you, Darlene. I'm the Vice President of Development here at MEG. And in the next few slides, I'll provide a bit more detail on our resource, our recent results and why we're excited about our development plan. I'll start with a few comments on our portfolio and in particular, the top-tier asset we have at Christina Lake. As Darlene mentioned, this is a world-class resource, in the heart of the McMurray fairway and in close proximity to some of the other top-performing assets in the basin. We have an operated 100% working interest in our leases and Christina Lake have 80 sections of land with approximately 1.9 billion barrels of remaining 2P reserves. This equates to approximately a 50-year reserve life at current production levels. However, as you know, we will be ramping that up as we go forward. The main point is that we have ample running room here with a significant inventory of high-quality wells to be drilled in the coming years. And since we are a company with a single producing asset, we are fortunate to be able to deploy all our talent, focus and energy on this one outstanding resource. This is factored into our long history of top-tier reservoir performance. And in the next few minutes, I'll take you through how we intend to build upon that going forward. While the focus of this business update and our near-term plan is on Christina Lake, I do want to briefly point out our Surmont lease. As you can see on the slide, Surmont is located to the north end of this map region and immediately adjacent to an existing operating project. We have 32 sections of land there with a reasonable level of delineation. We believe this is one of the highest quality undeveloped assets in the oil sands and provides us an exciting future opportunity. Now I'll get into the Christina Lake asset in a bit more detail, and in particular, the resource quality and development plan. This is the why now for the growth plan. Our delineation program consisting of core hole drilling and high-resolution seismic has identified sufficient volumes of high-quality resource stretching in both the Northwest and Southeast corners of our Christina Lake lease. This delineation program, together with our production history and technical expertise, basically how we select and define the subsurface patterns has effectively derisked the resource and has enabled a more strategic approach to the drilling sequence. It is noteworthy that the entire lease can be accessed from a single central processing facility using standard aboveground flow lines. You can see the CPF noted in the middle of the map. Therefore, no remote or satellite facilities are required. That said, upgrading our steam system will be required to access these further areas, which Tom will explain in more detail. In the middle of this slide is a map of our field showing the existing legacy well pads in gray with the most recent pad shown in dark green, those that have been brought on within the past 3 years. In light green, you can see the new pad targets to be drilled and brought on stream over the next 5 or 6 years. We have high-graded our development plan to really target the best quality areas in the short to medium term, which maximizes the value of the asset. The log and core shown here is an example of the high-quality resource we'll be developing up in the Northwest area. It shows big continuous pay and it is very rich as it has a very high oil saturation. This log in particular, shows approximately 35 meters of clean sand with greater than 85% bitumen saturation. This represents some of the best quality resource yet to be developed in the McMurray. For reference, recent pads we have developed and that have performed very well, and I'll show in the next couple of slides, have contained around 20 meters of pay and 75% oil saturation. This matters because it is these attributes that will drive top-tier production rates and low steam-to-oil ratios, which in turn drives our operating margins and free cash flow generation. This is why we're excited about our upcoming development plan. And a big reason -- a big part of the reason to embark on this multiyear growth plan is that it allows us to bring on these new pads faster than we could otherwise. On the next couple of slides, I will highlight the progression of well performance over time, referencing back to legacy versus recent well pads as shown on this map. First off, I'd like to recognize our technical teams here at May. The slide title, delivering results through technical excellence is a testament to their hard work and continuing push to improve and refine our operating model. We're very proud of this work and recognize it is paramount to our financial success. I'll start with well productivity on this slide. What we are learning about resource quality and our experience operating in the recent path has improved and invalidated our type curves and given us the confidence to embark on the multiyear growth plan. On the left side, I'm showing oil recovery in the first year of operations. The light gray line show the various legacy pads while the dark green on line show the 3 most recent pads we have developed and ramped up over the past 3 years. This shows a significant improvement of approximately 50% in performance compared to the older pads. Many factors are driving that, but I'll highlight 3 of them. Number one is reservoir quality and all the subsurface work that goes into designing the optimal drainage pattern. There are many aspects of reservoir quality, which include oil saturation, permeability and thickness and in situ viscosity to name a few. The second is well designed. To ensure optimal steam placement and drainage efficiency, it's important that the full length of the horizontal is producing. This is a hydraulics challenge, and I'm happy to say MEG is an industry leader in this area. The third is our operational strategies and technical know-how with respect to steam circulation, ramp-up and monitoring, really just overall reservoir management. Simply put, we know how to operate these wells to maximize performance. On the right side, we compare our recent well pad performance against various other peers in the industry. Here, we're looking at a 2-year average oil production per well. As you can see, we stacked up very favorably. Our recent wells have delivered 2-year average oil rates greater than 1,000 barrels per day per well for that period. This is exceptional performance that we look to build upon. Now we'll look again at recent well performance, but now focused on steam-to-oil ratio, a key metric that speaks to efficiency of a thermal project. It's also a key driver of cash flow potential. Again, looking at the recent 3 pads, we see a significant improvement from earlier pad performance. Many factors influence this with one of the major ones being the oil saturation of the reservoir. Starting on the left side, the first chart compares oil saturation of the older pads to the recent ones and then to the pads we plan on developing going forward. As shown, the recent 3 pads contain approximately 4% to 5% higher oil saturation on average. And the result of this change is reflected in the superior SOR results as shown in the middle chart. These recent pads have delivered a 20% lower SOR in the first 2 years of the wells life. And what makes us very excited is that the pads we will be developing in the near term over the next 3 to 5 years will have similar or better oil saturations. Looking at the chart on the right-hand side, we show an industry comparison of overall project SORs, which clearly shows MEG as an industry leader with respect to SOR, and we plan to further improve this going forward. As noted on the bottom right, a key differentiator for MEG is our evolved operating model, which speaks to our relentless focus on optimization and improvement. In addition to targeting high oil saturation and improved well designs, we are an industry leader in the use of non-condensable gas. When implemented later in the life of our wells, NCG injection further contributes to maximizing the thermal efficiency of the process and maintaining an industry-leading SOR. Now let's take a look at how we're driving innovation. It's a key element of the culture here at MEG and significantly contributes to enhancing financial performance for our shareholders. And by innovation, I mean driving continuous and incremental improvements in all aspects of our business and being flexible and agile to incorporate learnings and improvements in real-time. This slide highlights some of the more notable examples, but is certainly not exhaustive. Again, I want to recognize the tremendous efforts and expertise of the MEG teams in these areas. I'll start with subsurface. We have an active reservoir surveillance program using 40 seismic and observation wells that allows us to really go after any areas of the reservoir not being effectively drained with workovers or redevelopment. In addition, improved well start-up techniques have reduced the time from first steam to peak oil. On the drilling and completion side, I've already mentioned improved hydraulic design of the wells. And in addition, our teams have employed many program improvements that are reducing our cost per well, things like drill bit design. And notably, we've recently drilled our longest infill well with a lateral length of over 2,200 meters. On the surface pads, we've modernized our designs. In many cases, we utilize what we call Super Pads to reduce the footprint and land disturbance. We've also standardized the model using a manufacturing mindset to reduce execution time lines from 22 months down to 12 months. Overall, we're looking for 10% cost reductions here as we progress down the learning curve with more of these bills. And lastly, we are focused on getting efficiency gains via digital solutions, how we use data and machine learning to improve the efficiency of our technical analysis and forecasting and well operations. These are just a few examples of how we will continue to drive efficiencies and production improvements going forward, fueled by the deep experience and knowledge of our team. So as I wrap up my portion of the business update, I want to leave you with a few key messages. We have a top 2 resource with an inventory of high-quality wells. We have a history of improved performance with our recent wells amongst industry's best. And we have the talent and technology to deliver this plan. With that, I'll pass this over to Tom Gear, our SVP of Oil Sands. He will provide more insight into what we actually plan to build with our facility expansion and our continued focus on operational excellence. Tom?

Thanks, Mike. As Senior Vice President of Oil Sands, my focus is on overseeing projects, engineering and the company's daily operations. Our next step to unlocking highly economic growth is the facility expansion project, which will increase steam generation and processing capacity at Christina Lake. With a forward cost of $440 million over the next 3 years and a top decile capital efficiency of less than $25,000 per flowing barrel, including wells, the project will deliver an attractive rate of return even at lower oil prices, with a capacity increase of 25,000 barrels per day and shown in the middle chart on the slide, you will see a very short capital cycle between 2025 and 2027 and production gains through that period as time comes online in 2026. The expansion will be completed by the second half of 2027 after we finished the last set of tie-ins to the existing facility. Before moving on, let's look at how we reached this expansion decision. Consistent with previous messaging, growth requires adding a third processing train, this allows us to fully leverage the scale of our existing infrastructure. Also previously identified were steam tie-ins to retain optionality. As Mike covered in his presentation, we are sequencing our pad development to reach higher quality resource, meaning we are now going further from the central facility. To enable further reach and growth, our engineering studies confirm the best option is adding a once-through steam generator identical to equipment we have built and operated for many years. Integrating design and execution of the third train and once-through steam generator enables us to optimize the project, ensuring we are highly cost efficient and in service by the end of 2027. I'm really excited to tell you where we're at on this project readiness. Looking at the picture to the right. This is not graphic artistry. This is the engineered 3D model of the expansion, which is then used to build all the construction drawings. I will now highlight the key points to take away from this project. The front-end engineering design phase, which defines the scope and key parameters of the project is complete and confirms how we will integrate it into our existing world-class Christina Lake facility. The project is lower complexity, meaning it's easily integrated with our current operation, including similar equipment, processes and capabilities in which we have demonstrated expertise since 2008, with our first phase, plus we already own major vessels and the once-through steam generator. Additionally, we are on track to order all major long-lead equipment. This upfront work, combined with our proven execution model sets us up to quickly react to market changes. This means we are highly nimble and can easily adjust the pace due to our full control of engineering, procurement and construction throughout all our projects. Later on, our CFO, Ryan Kubik, will talk to you about our financial resilience as we progress this expansion. Now I want to connect to do the work on the expansion project to our 2025 turnaround, with just a foundational component of our value story. Drawing your attention to the chart on the right. We have 2 interconnected phases called Phase 2 in the gray and Phase 2b in the green. Phase 2b is also 2x the size of Phase 2, which is why the green bar is taller. Each phase has separate turnaround every 3 years, which is intentional and efficient, allowing us to avoid a full facility shutdown. Staying on that chart, recall, as part of our 2024 budget plan, we shifted the Phase 2b turnaround to 2025. This enabled our team to thoroughly analyze long-term planning. By adopting a risk-based approach, incorporating our facility expansion plan and consulting industry experts, I'm pleased to confirm we are moving forward to extend intervals to 4 years while continuing to maintain 2 distinct turnarounds. The chart emphasizes how this change works to generate significant value for May, approximately $175 million in net present value. This is achieved by removing some of the events out of this 10-year period, resulting in more aggregate production and less capital spend. This reset is enabled by the upcoming 2025 based 2b turnaround with an annualize impact of 8,000 barrels per day, it is expected to take 35 days and have more scope than usual due to regulatory inspections that are triggered in these facilities every 10 years. During this turnaround, we will also install critical expansion types. A final point on turnarounds. I'm confident our teams will remain focused on planning and executing a safe and efficient turnaround. Innovative examples include use of computer models scaffolding, robotic cleaning and drones for internal inspections. Next, let's turn to operational excellence and our consistent track record of improving results. At MEG, operational excellence means being safe, reliable and predictable. Our safety culture is driven by exceptional safety leadership, galvanized by our first operating priority, caring for ourselves and all others. This, combined with our new operations excellence management system supports our injury rate reduction. This system was put to the test in July this year, when we safely evacuated personnel from our Christina Lake operation due to a nearby wildfire while maintaining stable production with a reduced workforce. Moving to the middle is our reliability. Our approach to turnarounds is only one part of being a reliable operator. We have a highly effective approach to daily value optimization that starts at the well and is integrated through to sales of our products, which has been foundational to reducing unplanned downtime. Finally, as shown on the chart to the right, our intense focus on daily performance has led to year-over-year production increases without major expansions. Overall, this performance is ultimately driven by employee ownership and exceptional alignment from the boardroom to the control room. Being safe, reliable and predictable is how we deliver low-cost operations. Looking at the chart on the top right, you will see we lead the pack on operating costs in this sector. Now moving to the bottom right chart, we will continue to pursue the things we can manage and control, namely nonenergy operating costs. A couple of highlights shown on the left on how we will do this. The facility expansion project is a big part with more production, it simply spreads a stable fixed cost base across more barrels. Our 2 cogeneration units continue to play an important role by providing reliable, low-cost thermal and electrical energy, while surplus electricity sales partially offset fuel costs. Lastly, our teams are constantly looking at ways to improve efficiency and deploy cost-saving technologies such as advanced process control across our pads and wells. Now before turning it over, I'll leave everyone with this key message. We have a highly profitable expansion plan that solidifies our reputation as a safe, reliable and predictable operator. I'll now pass it over to Erik Alson, our Senior Vice President of Marketing, who will talk to you about market access.

Thank you, Tom. As Senior Vice President, Marketing, I have the pleasure of leading a talented team that's dedicated to maximizing the realized price for our crude oil. Prior to joining MEG, the majority of my 30-plus years in the oil and gas industry was in refining, with a focus on crude supply and optimization. This prior experience has provided me with a deep understanding of how our customers use and value our product. What drew me to this role nearly 5 years ago was MEG's unique story and position in the market, which I'm excited to share with you today. Our marketing strategies differentiate us by leveraging our strengths, our product, our foresight and our ability to access global markets, all of which enable our continued growth. The global energy landscape continues to evolve, but what remains constant is the strong demand for Access Western Blend our flagship product. Before diving into the details of our market access, I'd like to provide some color on heavy crude demand and global interest in our crude specifically. Our crude Access Western Blend, known globally as AWB is a premium heavy sour high-TAN crude and its consistent quality makes it highly desirable for some of the world's largest and most complex refineries. We see strong international demand for AWB, particularly in expansive markets like the U.S., China and India where our product is a key input for producing chemical feedstocks and transportation fuels. Beyond current consumers, the incremental demand created by new refining capacity is dominated by consumption of medium and heavy sour crudes, aligning perfectly with MEG's production. AWB's appeal comes down to its usefulness as a baseload feedstock making it a staple in global markets. What sets MEG apart is how we bring our product to market. 80% of our current production can access global markets and benefit from global pricing via committed pipeline egress capacity. For context, many of our peers achieve only a fraction of that total secured global market access. With some relying on less efficient transportation and more costly methods like rail to support their future production. Our extensive infrastructure means that MEG is not constrained by regional pricing, which has been a historic issue for the sector in Western Canada. This distinction is the result of strategic infrastructure investment and reflects the foresight and confidence in our long-term strategy. Now let me walk you through how our logistics infrastructure supports and enables our diverse market access and profitability. We have the capacity to transport 100,000 barrels per day to the U.S. Gulf Coast via the Flanagan South Seaway pipeline system. And another 20,000 barrels per day to the West Coast via the Trans Mountain expansion pipeline. Our storage assets, 1 million barrels each in Canada and the Gulf Coast play a critical role. They allow us to manage export volumes efficiently and meet global commitments even in dynamic market conditions. As we look ahead, MEG's extensive logistics infrastructure is well positioned to support our planned production growth. This will help mitigate potential for future pricing constraints due to land locked conditions. The strong demand that I highlighted earlier is evident in the tighter differentials seen since the Trans Mountain Expansion commenced operations. TMX being in service has removed pipeline egress constraints and enhanced global market access. With that, differentials have narrowed significantly and volatility is reduced. As a recent data point, the combined WCS and AWB differential in 4Q of this year has narrowed $10 a barrel versus the same period last year. The excess egress capacity provided by the TMX pipeline provides the headroom for production growth and a supportive margin environment. Several proposed pipeline expansions can further extend the runway of unconstrained egress and the supportive margin environment. For perspective on the positive impact associated with diverse market access, MEG's adjusted funds flow increases $46 million for every USD 1 per barrel improvement in differentials. In summary, our ability to access global markets and avoid historic pricing constraints in Western Canada, is a key part of our value proposition. Looking forward, our planned production growth is well supported by our considerable storage and transportation assets. With strong demand for AWB, robust infrastructure and strategic foresight, MEG is well positioned to continue delivering value both today and in the future. With that, I'll turn it over to Ryan Kubik, our Chief Financial Officer.

Thanks, Erik, and good morning, everybody. 2025 is going to be very active at MEG, but I'm confident we're positioned to meet our commitments from both an operational and financial perspective. I'm going to focus my discussion today in 3 key areas. First, how we positioned MEG for our next phase of growth. Second, our plans reflect MEG's capital allocation priorities. And third, how the plan delivered significant low-risk shareholder value. Debt reduction has been a key strategic focus at MEG since 2016, and we can now move confidently forward with a resilient balance sheet. Since the beginning of 2022, we've reduced our debt by USD 1.6 billion, and our debt target has now been achieved. With debt representing 0.5x EBITDA today or 1x EBITDA at a $50 WTI, financial risk in our business is now controlled. We have a long runway out to 2029 before our next debt maturity and will benefit from the low 5.875% interest on that debt. We also have a $600 million credit facility that's entirely undrawn, providing further financial flexibility as required. This strength was achieved through discipline over many years, and we intend to keep it. Our plans going forward can and will be fully funded without increasing debt. And MEG's low-cost business generates substantial adjusted funds flow to achieve that objective. With debt reduction complete, we're now focused on our remaining capital allocation priorities. Our capital allocation framework balances investment and shareholder capital returns. Priority #1 is sustaining our business. We're committed to safe, reliable, efficient operations, which can be achieved at a very low $45 WTI oil price. Priority #2 is a sustainable, growing base dividend. It's the foundation of our return of capital commitment and as a permanent component of our value proposition. Priority #3 is disciplined investment in capacity and production increases. Our resource life support significant growth, but it must be delivered with strong economics and flexible plans that reflect market realities. Priority #4 is share buybacks, delivering 100% of free cash flow to shareholders and driving growth in free cash flow per share. You may note that diversification outside our high-quality assets is not currently on the table. MEG's strength is our high-quality resource, and that remains our focus. These priorities are reflected in our plan out to 2030. Well, let's focus on 2025 before looking at the long-term forecast. In 2025, we expect production to be in the 95,000 to 105,000 per barrel per day range, which includes the second quarter turnaround that Tom mentioned earlier. At $70 WTI, that production will generate adjusted funds flow of about $1.25 billion, which will fully fund capital expenditures and significant share buybacks. Total CapEx is $635 million and includes $130 million for our facility expansion project, $70 million for the turnaround and $420 million for wells and infrastructure. After funding that capital, $615 million is available for the base dividend and share buybacks, and MEG will be buying about 7% of its outstanding shares under this scenario. Our budget balances investment and return of capital, and that ratio improves even further over the forecast period. You can see here that 2025 capital represents about 50% of estimated adjusted funds flow. That's very competitive relative to peers, and it means the other 50% is available for our base dividend and share buybacks. You can also see that returns to shareholders rise to 70% over the forecast period, as capital expenditures decline and production rises. Once again, this reflects $70 WTI, but with 100% exposure, adjusted funds flow is very sensitive to oil prices. Our plans must, therefore, consider oil price changes, both up and down. MEG's long-term plan generates robust free cash flow, even below our $70 price assumption. Every $10 WTI change impacts annual free cash flow by about $320 million. And as I mentioned earlier, our business will be self-funded without increasing debt. Our total CapEx and base dividend could be fully funded at $53 WTI, as we execute our facility expansion project -- our total CapEx -- that reduces to $47 as project spending declines and production rises. Should long-term WTI approach $50 per barrel, capital spending must be reduced, and we've built off-ramping to the plan to facilitate those potential reductions. Our base case generates cumulative free cash flow of about 65% of today's market cap over the forecast period. That's impressive and it's clear that shareholders only make today for our exposure to even higher oil prices. In addition to the increased free cash flow, the forecast plan raises production and improves business durability. Low operating and capital costs already delivered a sustaining breakeven around $45 per barrel WTI. But a significant portion of those costs are fixed, which means cost per barrel fall as production rises. As a result, we estimate sustaining breakeven will decline towards $40 WTI. This improvement reflects sustaining capital, which is forecast to average of $450 million annually after our facility expansion. CapEx will decline towards $10 -- declined below $10 per barrel under this scenario, driving a sustaining breakeven improvement. The compounding impact of economic investments and shareholder capital returns maximizes per share growth metrics. Organic production growth, combined with share buybacks drives a 20% annual production per share growth rate. And once again, at $70 WTI, we forecast cumulative free cash flow of about 65% of MEG's market cap. Combined with share buybacks, we deliver a 22% free cash flow per share CAGR, through 2030. That CAGR has the potential to rise even further with MEG's leverage to increase crude prices. Growing free cash flow per share is our North Star at MEG. It guides our business strategy, and we're committed to delivering it to shareholders. Thanks. And with that, I'm going to hand it back to Darlene for closing remarks.

Thanks, Ryan. As you've seen, our strategy to drive measured intentional growth that return significant capital to MEG shareholders and stays within our cash flow stands on a solid foundation that has been carefully built. That foundation starts with one of the best long-life top-tier resource in the industry with a 50-year reserve life index. Our operational excellence anchored by an uncompromising commitment to safety, not only delivers reliability and consistent execution, but does so at the lowest cost in the business. Our facility expansion project demonstrates this in practice with a 50% internal rate of return. We moved early and confidently to lock in the pipeline and the storage assets we need to get our product to global markets today and into the future. Demand is growing for Access Western Blend and MEG is meeting that demand at home and abroad with a strategy that enhances long-term profitability and reduces price constraints. This approach also gives 80% of our product access to international pricing. Critically, our plan has been stress tested across a range of price backgrounds and reduces our sustaining breakeven to a remarkable $40 per barrel. And all of this is in service of driving a projected 22% compound annual growth rate and free cash flow per share to 2030. This gives our shareholders a cumulative free cash flow payout that equals to 65% of our market cap in that time. We have not arrived at this place in MEG's journey by accident. We forged this path with a clear vision, a detailed strategy, disciplined execution and frankly, the best team in the business. As I said earlier in the presentation, this commitment to returning significant capital and value to our shareholders is not a pivot. It's part of our ongoing evolution. And if you want to gauge your commitment to the future, you need only to look at how we arrived here today. I want to thank everyone for their time and attention, and I would like to especially thank the MEG team for everything they do and those who worked on this presentation, simply outstanding. And with that, I'd like to pass it back to Ludy to open the lines for questions to begin the Q&A.

[Operator Instructions] And your first question comes from the line of Dennis Fong with CIBC World Markets.

My first question is maybe just a little bit of context -- alongside Q3 results, you highlighted some engineering work and a multitude of options that were being evaluated. Do you mind walking us through some of the factors maybe both from a technical and financial perspective that was balanced to arrive at the expansion to 135,000 barrels a day or the 25,000 barrels a day of expanded capacity, i.e., what are some of the -- what were some of the limiting considerations? Is it oil processing, steam gen, utilities, total capital spend, et cetera, et cetera?

Thanks, Menno. I'm going to have Tom -- sorry Dennis, sorry, thank you, everyone. I'm going to ask Tom step in and just walk us through some of the perspective from the operations. And then we'll have Mike join, add some other color to that conversation.

Yes. Dennis, it's Tom. Yes, I just want to, again, go back to what we talked about. Mike will explain about the growth and the reach out to further locations. But when we -- consistent with our previous messaging, we looked at our options around accessing the further resource for us, and really for us, that was the way to go when we looked at all of our options for steam capacity out towards those pads that Mike showed on the map. So when you integrate the steam with the third processing treatment and you look at it overall at an integrated project, we look at that as our most efficient approach to be able to get towards that 25,000 barrels per day addition. And so that is basically when we looked at the engineering options and the optimization combined with that, that was our best possible expansion approach. So I'll pass it over to Mike, who can explain a bit on the resource itself.

Yes. Thanks, Tom. From a resource perspective, perhaps I mentioned a couple of other considerations, certainly from a field development planning perspective, the additional infrastructure requirements of getting further out to these pads was certainly a consideration as was overall capital requirements and balancing capital requirements and our growth rates played a role in reaching this. And has been mentioned, the integration of our steam system into the larger facility as well was a factor in arriving at what we feel is the most optimal value solution.

Maybe Dennis, I'll throw in a couple of more things that the team has mentioned. When you step back and understand to bring in the tie-in and the integration of the full opportunity, you're trying to also lead that into the sequencing of your turnaround. And Tom has mentioned, he's got 2 turnarounds, one next year and then one in 2027. That is part of also the integration and the capital efficiency that you don't have to bring the plant down at a different time that has a significant impact to the operations. And so when you weigh that out, you look at the different options, you optimize those, the sequencing of the pads from a financial perspective, it drives the highest value for the shareholders and also from a safety and integrity perspective of just bringing in the team that can deliver it at the same time it's integrated. And so it's really the efficiency of that process that the team went after.

Great. I appreciate that context -- incremental context there, Darlene. Maybe just drawing off of your comment there, how should we think about the expansion integration into the existing facility? I know you talked a lot about or just frankly, talked about the timing of turnaround. But does the integration of the expansion change as well the downtime impact after it's brought online associated with turnarounds? And how does that all interact together with the rest of the facility?

Thanks, Dennis. It's Tom here again. For what we're looking at for that, I would say it actually improves our approach to this. When we add this train and the steam to our -- predominantly our Phase 2b area, really when we look at our downtime performance, we don't see any impact on that. In fact, what this does is it provides a bit of capacity relief for the operation and really continues to help us deliver top decile downtime and operating costs.

And your next question comes from the line of Menno Hulshof, with TD Cowen.

I'll start with a question on growth CapEx. How much of the $440 million is locked in? How much contingency is captured in that figure? And more generally, where do you see the most execution risk -- I would so look again, it seems fairly low, but your thoughts there would be helpful.

Menno, it's Ryan here. I would say in terms of what's locked in, in that spend profile is very little. I would say we've kind of started to order some long lead items, but a good majority of the spend on this project is around construction in the field and labor costs. I'm not sure, I caught the second part of your question, Menno, but I see Tom is going to add some commentary here.

Yes, Menno, it's Tom. Really, when you consider locked in, as we explained earlier on in our execution model and our approach to full control, of engineering, procurement and construction, really, at the same time, too, we own a lot of the big pieces of equipment, including the ones through steam generator, as I previously mentioned. So when you talk about locked in, that's what gives us this flexibility to continue to react if things change differently. So it's really -- it's not a case that you're locked in and it's set and go. We have control through this whole process like for all of our projects.

And just on the contingency piece, presumably it's in the 10% range?

Yes. Our contingency is, as we've proceeded or announced with final investment decision. And so yes, we'd be in that level of quality of contingency throughout the whole project.

Okay. Perfect. And then just more near term. There's a lot of moving parts on 2024 and 2025 production guidance. You've got the fairly significant 8,000 barrels per day impact from the turnaround in 2025. And then 2024, there was bits and pieces on wildfires and weather. So I guess my question is, can you normalize '24 and 2025, for all the one-timers? I'm just trying to get a better sense of what year-over-year growth would have looked like on a fully normalized basis, especially with the well performance improvements that you described earlier in the presentation.

It's Mike. Maybe I'll just touch on the last point you raised there. I think from what we would call a stream day of just reflecting reservoir performance, looking into next year, we are -- if you take up the turnaround, we are definitely planning for a very strong year. I think it's in the range of 5% improvement from a reservoir deliverability perspective as we continue to bring on and ramp up some of our new high-quality pads.

Then maybe what I'll throw in there is if you look at some of the charts that are in the deck, it's faint, but there's a dashed line that the team has provided on the chart that kind of normalizes the impact of the turnaround. I believe it's on the financial section when Ryan went through, he highlighted the quarter-by-quarter for 2025 that you'll see that the growth production with that pad that was delayed in 2024, moves into 2025, the start-up of it. And most of the production over the quarters, you'll see the growth in the production quarter-by-quarter, and it's really Q2 that has the impact of the turnaround. There's a dashed line that sort of shows you without the turnaround of the 8 kbd, this is where production would be. Maybe that will help you normalize the production and see the impact in the performance of the pads for 2025.

Your next question comes from the line of Greg Pardy with RBC Capital Markets.

As it relates to GHG emissions, are there any steps in the growth plan? Like when you look at your emissions pre and post maybe on a per barrel basis, is there anything there that will mitigate emissions? Just curious.

I'll take this one, Greg. For the emissions right now with C-59, we have to be very careful. So I appreciate that you recognize that -- we haven't been able to put any of the highlights we would like to put in our decks. Right now, our multiyear plan does not incorporate any economic benefits from a pathways or any of those types of opportunities. But what you'll see, what we can point you to is the value proposition of what the team walked us through with the steam-to-oil ratio improvement and the resource quality. Those are the indicators that help us perform as we look ahead.

Yes. No, that's a good answer. And then just kind of related, but I didn't -- I'm just curious as to what natural gas co-injection, I mean, you've used that in the past, does that figure into your thinking here to liberate steam in this process? Or just curious if that plays any role.

Yes. Greg, it's Mike. I'll take that one. Yes, absolutely, NCG injection continues to play a big role in our recovery process and it has for quite some time, as you know. It's a later life strategy. And absolutely, that is factored into how we plan the timing of when steam becomes available, that drives the timing of when we drill and bring on new pads to be available. So yes, absolutely, it's part of our process.

And I'm showing no further questions at this time. I would like to turn it back to Darlene Gates for closing remarks.

Well, first, again, I would like to thank everyone for their valuable time today and taking the time to walk through the MED story. Team, thank you for everything and all the hard work. We look forward to continuing the conversations as we get the opportunity to meet with every one of you. I want to thank you again for coming.

Thank you. And this concludes today's conference call. Thank you all for participating. You may now disconnect.