TransAlta Corporation ($TA)

Good morning, everyone, and welcome to TransAlta's 2026 Investor Day. My name is Stephanie Paris, and I'm the Vice President of Investor Relations and Corporate Strategy. We're very pleased to have you all here with us in Toronto and joining us virtually as well. Today's presentation is being recorded, and a replay of the event and transcript will be posted on our website. As we begin our session, please note that this presentation includes forward-looking statements which are subject to risks and uncertainties, many of which are set forth on this slide. I encourage you to read the statements at your own convenience. This presentation also contains references to non-IFRS measures, including adjusted EBITDA and free cash flow. Such measures may not be comparable to those presented by other companies. Please refer to our MD&A for more information. All amounts referenced during this presentation are in Canadian dollars, unless noted otherwise. With us here today is a subset of the broader leadership team of TransAlta, including John Kousinioris, President and Chief Executive Officer; Joel Hunter, Executive Vice President, Finance and Chief Financial Officer; Chris Fralick, Executive Vice President, Generation; and Nancy Brennan, Executive Vice President, Legal and External Affairs. We're excited to discuss our strategic plan, the role of our assets in Alberta and key priorities across our business. Following the presentation, we'll commence a question-and-answer session. And now I'd like to welcome John Kousinioris, President and Chief Executive Officer, to the stage. He will begin our presentation today with an overview of TransAlta. Welcome, John.

Thank you, Stephanie, and welcome, everyone, and thank you for being with us today. I'd like to begin our presentation today by outlining for all of you, our 7 key takeaways. First, TransAlta is uniquely a proven operator across diverse technologies. And that operating track record matters in a world where reliability is increasingly scarce and increasingly valued and customers seek customized hybrid solutions to meet their needs. Second, the outlook for power has never been stronger. And we believe that both existing and new generation will play a critical role in meeting future load requirements. Demand is rising, and companies like ours have tremendous opportunity in meeting that demand while balancing affordability, reliability, sustainability and speed to power. Third, we're focused on the right geographies for growth, markets where we see supportive fundamentals and where our capabilities translate directly into competitive advantage. Fourth, we believe we're best positioned to capture expected load growth in Alberta. We have the right assets, the right optionality, the right market expertise to benefit as fundamentals tighten later in the decade. Fifth, Centralia is essential for reliability in Washington State. It is a critical asset that supports the region and underpins stable value creation for TransAlta. Sixth, we have a demonstrated track record of disciplined, accretive M&A. We've executed value-creating transactions that have strengthened our platform and improved our long-term cash flow profile. And finally, we're entering this exciting period for our industry and our company from a position of strength. Our strong financial position and disciplined capital allocation give us the flexibility to drive attractive long-term growth. These points underpin everything you'll hear today: a resilient base business, embedded upside and a company that's purpose-built for the power markets we're operating in now and the ones we see ahead. I'd like to now shift to a brief overview of TransAlta and its accomplishments. We're proud of our company and all that it has accomplished since it was founded 115 years ago. While TransAlta has evolved and grown, we have consistently generated the electricity required to power and empower our communities and economy. It is a time of great opportunity for our company, and we are well positioned to capture it. We have 4 key competitive advantages that drive our success, enable us to meet the unique needs of our customers and create value for our shareholders. They also differentiate us from other power producers across the regions in which we operate. Our advantages include exceptional safety performance and operational excellence, with extensive experience across diverse fuel types, including wind, hydro, solar, storage and natural gas. We operate one of Canada's largest wind fleets, Alberta's largest hydro fleet and one of Canada's largest gas fleets. We have leading optimization, energy marketing and trading expertise that provides extensive in-house market intelligence and forecasting capabilities, especially in our core market of Alberta. There is significant and growing value in our legacy thermal sites, which our team is actively working to repurpose to meet the growing need for affordable and reliable generation in the jurisdictions in which we operate. And we have a solid financial foundation and the financial flexibility to pursue our growth strategy and generate value for our shareholders. In each of our core jurisdictions, we see unique and growing power needs where customers are looking to partner with someone with in-depth experience in the realities of the energy evolution. They know that we can help them achieve their goals as a proven and trusted partner. Half of our generating fleet is contracted with a weighted average contract life of 9 years, and over 85% of our associated customers are backed by an investment-grade credit rating, highlighting the quality of our cash flow profile. Our contractedness has been enhanced by our recently acquired Ontario and Heartland facilities, which increased our contracted generation in Alberta to the point where it now exceeds our merchant production. Our contracted assets span regions and fuel types and provide us with stability, diversification and clear visibility to earnings and cash flow. And we're focused on increasing our contractedness over time to further enhance the size and stability of our cash flows and enable disciplined growth for the benefit of our shareholders. Our contracted portfolio is not just diversified across technologies, but also across industries and customers. Since 1911, we've been supplying contracted power in Alberta and have diversified our customers across multiple regions. In Alberta, we provide behind-the-fence power and steam to large E&Ps and integrated supermajors. In British Columbia, Washington State, Ontario, Quebec, New Brunswick, North Carolina and Western Australia, we provide contracted power to local and state-owned utilities. In Ontario, we power manufacturing, refining, health care and industrial operations. And in the U.S., we have long-term renewable power purchase agreements with hyperscalers. Our contracted portfolio and associated customer base is the foundation of our business, and we're in the process of expanding our portfolio to power data centers in Alberta. The North American power industry consists of a complex mix of regional markets, each with their own set of rules, regulations, products and generation and transmission systems. For over 30 years, we have traded power across North America, and energy marketing has become a strategic and core capability of our company, providing us with detailed knowledge, market expertise and customer relationships across Canada and the United States. Our marketing and trading business delivers 3 key value propositions to our company. First, our optimization and energy marketing teams are responsible for hedging, marketing, dispatching and scheduling our generating fleet in Alberta, Ontario and the United States. This includes dispatch and capacity scheduling for our gas, hydro and wind fleets. The team also manages the procurement of gas, pipeline transport and short-term gas storage for our generating facilities. Second, the team supports our growth initiatives by providing market intelligence and due diligence support. Our energy marketing team has established relationships with hundreds of participants, power pools, customers and suppliers across North America. And finally, our energy marketing team has accountability to generate a stand-alone gross margin separate and distinct from the value that they provide to our asset businesses. We have a strong focus on physical power trading as a baseline strategy, but also trade products such as transmission and congestion rights and engage in both term and real-time trading. Our gas desk provides physical and financial gas positions and supports our understanding of the natural gas pipeline network given the interplay between gas and power in the North American marketplace. And our emissions desk manages the sales of all credits generated by our assets, the obligations incurred in our physical power flow business and enters into stand-alone proprietary emission strategies, including the trading of carbon products ranging from offsets to allowances to renewable energy credits in markets across North America. Over the past 5 years, our energy marketing team has delivered almost $800 million of adjusted EBITDA to our business, separate from the value created by our asset optimization activities, and is a consistent cornerstone of our business. Our company has been transformed since 2020, when we were the largest coal-fired generator in Canada. Since then, we have evolved our strategy significantly while remaining focused on prudent growth and expansion to strengthen TransAlta and create long-term value for our shareholders. Since 2020, we have converted 1.7 gigawatts of coal-fired generation to natural gas-fired generation in our core market of Alberta, acquired a 122-megawatt fully contracted solar portfolio in North Carolina, built 250 megawatts of contracted wind facilities in Alberta and a further 500 megawatts of contracted wind facilities in Oklahoma. Built a hybrid solar and battery solution for one of our long-standing customers in Australia, expanded and strengthened our position in Alberta with the addition of Heartland's 1.7 gigawatts of gas-fired assets, which are flexible, competitive and serve leading industrial companies in the province; acquired a 310-megawatt largely contracted gas portfolio in our core market of Ontario; and significantly simplified our corporate structure by bringing TransAlta and TransAlta Renewables back together, and in the process, increased our economic ownership in 1.2 gigawatts of high-quality contracted generating assets. More recently, we've continued to advance the company with the 700-megawatt tolling agreement signed for our soon-to-be natural gas-fired facility in Centralia and the memorandum of understanding we entered into to provide up to 1 gigawatt of power to support data center development in Alberta. This transformation has significantly strengthened the strategic positioning of our company since 2020 by increasing the size of our contracted fleet by 158%, significantly increasing our adjusted EBITDA and free cash flow, improving our operational performance with outstanding safety outcomes, fleet availability in excess of 90% and emissions reductions of 55% and realizing a total shareholder return of 108%, reflecting the increasing value of our company and the opportunities ahead of us. Increasing our contractedness, simplifying our corporate and financial structures, strengthening our balance sheet, repositioning our Alberta business and extracting value from our legacy generating facilities has created a solid foundation for TransAlta. Our company is in a great position to succeed with considerable optionality in its generating base and an exciting growth outlook. Before turning the session over to Joel, I'd like to acknowledge that this will be my last Investor Day with all of you. It has been a privilege and an honor to lead TransAlta since 2021, working with an incredibly committed and talented team. I'd like to thank all of you for your support as we collectively work to advance the company for the benefit of our shareholders. I fully support Joel as the next President and CEO of TransAlta, and I'm confident that he is the right person to advance our strategy during this exciting time of opportunity. I'll now pass the floor over to Joel to provide you with our strategic overview.

Thanks, John, and good morning, everyone. The power industry is entering one of the most exciting chapters in decades, and we're in excellent position to participate. The opportunity set for power generators today is unprecedented. We're witnessing structural change due to the acceleration in demand for electricity across our markets, with no signs of slowing down. Electrification, data centers and industrial reshoring are key drivers, and the grid requires reliable, affordable power to meet it. TransAlta is well positioned to grow in our core geographies where supply and demand fundamentals are tightening, market design is evolving, and our existing assets, optimization capabilities and development platforms give us a clear advantage. We have a well-defined strategy with a clear purpose. We aim to maximize value from our base business while selectively investing in growth opportunities that enhance returns, contracted cash flows and long-term flexibility. The combination of strong market fundamentals, advantage positioning and disciplined execution underpins our strategy. So why are we so optimistic? Power demand is accelerating everywhere we operate at a pace we haven't seen in decades. In the U.S., peak load demand is expected to increase by 100 gigawatts over the next 5 years, driven by data centers, reshoring and electrification. Data centers alone now represent approximately 55% of forecast U.S. electricity demand growth through the end of the decade. Here in Canada, we are seeing similar shift, as electricity demand is expected to grow by more than 60% between now and 2050, and regulators are reviewing data center proposals equivalent to powering roughly 70% of Canadian households. By 2030, data centers currently under review could represent close to 14% of total Canadian electricity demand. In Western Australia, industrial electrification tied to mining and heavy industry are expected to drive electricity requirements nearly 5x today's levels. And so it's not only about additional megawatts, it's about when power is needed. Load growth increasingly requires 24/7 power, adding the need for dispatchable, firm capacity to maintain grid reliability. Overall, across our core markets, demand is rising rapidly. Intermittency is increasing, and reliable generation is becoming more valuable. It's this combination that underpins the opportunity set that we're focused on. The evolving energy landscape offers a great opportunity for TransAlta that we'll pursue while balancing 4 key pillars: reliability, affordability, the rapid deployment of power and decarbonization. In recent years, policymakers and industry stakeholders have placed increased emphasis on decarbonization that resulted in substantial investment in renewable infrastructure is essential for achieving long-term carbon reduction objectives. Due to the intermittent nature of renewable energy, there is increased focus on ensuring grid reliability, which is further heightened by rising demand from AI applications. Coupled with the necessity to replace aging infrastructure, the imperative and rapid deployment of power solutions has become a central consideration. It's essential to ensure that power services facilitate our economic growth rather than becoming a limiting factor. Major shifts in the macro environment are creating new opportunities for power producers. As demand for dependable and affordable electricity surges, supply chain pressures in making installed infrastructure and existing generation assets increasingly valuable. With the tremendous potential of AI and ongoing technological advancements, substantial investment in affordable and reliable energy infrastructure is necessary. Supporting this growth requires an all of the above strategy as it relates to forms of power generation. In the case of TransAlta, this means additional investment in thermal generation and renewable technologies, including wind, solar, hydro and battery storage. We remain confident in our ability to capture these opportunities, whether it's our cost-effective fleet, which ensures affordability, our diversified, flexible and responsive generation to meet grid and customer reliability, our legacy sites that can be repurposed quickly and economically, or our best-in-class marketing trading capabilities, TransAlta is well positioned to capture future growth. Our growth strategy is focused on 4 key geographies: Alberta, Ontario, the Western United States and Western Australia. In these 4 regions, we have an ability to capitalize on our competitive strengths, including those arising from our well-established operations, our marketing and trading expertise and our deep understanding of local regulatory frameworks. We base our strategy on long-term fundamentals and believe there are growth opportunities in these regions that ultimately delivers long-term shareholder value. Ontario presents promising opportunities for us, driven by increasing demand, favorable policy, nuclear refurbishments and the growing value of steel on the ground. With over 30 years of operational experience here and a diversified portfolio comprised of natural gas, hydro and wind facilities, we are well positioned to capitalize on these prospects. Our assets offer strong recontracting and expansion possibilities, supported by adjacent land available for future development. We've also identified M&A opportunities that complement our existing fleet and align with our strategy to expand our contracted asset base, as evidenced by the recent acquisition of the Far North assets. Electricity demand throughout the Western U.S. is projected to increase substantially over the next decade, driven by expanding data center infrastructure, reshoring, electrification and economic growth. The rising demand coincides with the retirement of legacy thermal generation and the growing reliance on intermittent renewable energy sources, reinforcing the need for reliable and dispatchable power generation. The bilateral structure of the WEC supports development of new projects underpinned by long-term contracts. We also see opportunities to capitalize on our expertise in energy marketing and trading, leveraging our long-standing experience and market intelligence to achieve a competitive advantage. This year marks our 30th anniversary in Western Australia. Our fully contracted operations mainly support the mining sector, featuring distinctive remote islanded operations that deliver reliable power using a mix of natural gas, solar and battery generation. We believe hybrid energy solutions are increasingly needed to ensure stable and dependable power supply in the region. There's also growing demand for expanded grid capacity to facilitate electrification and the shift from diesel to renewable and natural gas fired generation. Our ability to operate diverse technologies with a portfolio approach, coupled with our existing footprint, positions us well to participate in future growth opportunities. Our largest and longest existing market is Alberta, which is unique in Canada as it's the only fully competitive energy-only electricity market, which has driven both innovation and volatility over the past decade. Knowing this framework, it's critical to understanding pricing dynamics, investment signals and the direction of the market. Alberta is also one of the only markets in North America that is long power, which is one of its key advantages that has created the opportunity for growth in the data center industry that you'll hear more about later this morning from Chris. As we approach the end of the decade, our strategy remains focused on maximizing both the value of our business and shareholder value. Now we'll accomplish this by focusing on a number of key priorities. Our first priority is to operate with excellence by ensuring safety, reliability, efficiency, actively optimizing our Alberta fleet and strengthening our financial flexibility through thoughtful capital allocation and strict cost management. Our second priority is disciplined growth. We plan to advance our legacy projects, including Centralia and Alberta data centers, pursue value-accretive M&A and advance our high-quality, well-defined project development pipeline for long-term investment opportunities. Successful execution of our strategy will ensure our business remains resilient, geared for growth and responsive to the shifting energy landscape. As we look out to 2029, successful execution of these initiatives is expected to have a meaningful impact on our adjusted EBITDA and cash flow. Completion of our Centralia Coal to Gas project in late 2028, together with improved supply and demand dynamics in Alberta, including our 230-megawatt Phase 1 allocation to Keephills, will have a positive impact on our financial performance. Upside will be influenced by the pace at which 1.2 gigawatts of data centers are commissioned in Alberta, as well as other factors that Chris will address momentarily. It is also worth noting that increases to our adjusted EBITDA from value-enhancing M&A and greenfield developments are not included here. We intend to reinvest our expanding cash flows into attractive contracted opportunities that foster consistent and ratable growth for the long term. I will now turn the floor over to Chris to provide additional details regarding our operating strategic priorities.

Thanks, Joel, and good morning, everyone. I'm Chris Fralick, the EVP of Generation. I'm pleased to discuss some of the essential elements of the business, starting with safe, reliable operations. Our operational performance is strong and continues to improve. We are unique in our ability to operate a highly diverse portfolio of technologies and to do so dynamically across our assets within a single market. That flexibility matters as system conditions change and reliability becomes increasingly valuable. We're relentlessly focused on efficiency. Across the fleet, we're driving higher availability, better cost control and smarter deployment of capital to ensure our assets are operating where they create the most value. Flexibility, efficiency and disciplined execution are what underpin reliability and performance, you'll see reflected in our results. Our operations fleet is founded on 4 core principles. Our hydro fleet, largely based on Alberta is unique and perpetual. These assets are critical in meeting peak energy needs and in providing grid support through its leading position in the province and ancillary services market, a market that we expect to grow as data centers come into the province and general load continues to increase. Our gas fleet, consisting of our dispatchable and cogen facilities, these assets serve customers critical to the industrial sectors within our markets and also underpin the reliability needs of the grids. Our larger contracted wind and solar fleet, which provides predictable, stable cash flows and earnings, creating steady base to balance our merchant fleet. And our highly capable energy marketing and trading team, which I will speak about shortly. Our company has a diversified and resilient generating fleet and leading trading optimization and growth capabilities, all guided by a single leadership team driving operational and financial synergies. Let me share with you some of the key aspects that I believe differentiate TransAlta's operations and underpin our competitive advantage. At TransAlta, safety is our core value, and we live by the mantra, safe production is the only production. We firmly believe that a strong safety culture will result in a safer, more engaging and more successful business. Highlighting our total recordable incident frequency, we are very proud of our results. 2025 was our best safety performance on record, and well below the industry benchmark for electric power generation. While these results are positive, we continue to work towards reducing the number of incidents we're focusing on our leading safety indicator of safety report frequency and the identification and mitigation of high energy hazards. We leveraged thousands of reports to identify trends and share learnings across the organization in our pursuit of continuous safety improvement. Our environmental performance has been excellent, reflective of the emphasis that we place on prevention and strong job planning execution. Our operational strategy is built on our rich history and our experienced team to deliver our current and future operational goals. From the foundation of a fleetwide asset management strategy that leverages real-time asset condition and market knowledge, we are able to optimize our portfolio in both the short and long term. Our operations team has a strong culture of innovation with the belief that we can get a little bit better every shift. Through our efforts, we find ways to maximize operational efficiencies and reduce costs, which ultimately benefit our customers and deliver shareholder value. Regarding availability, we have had strong performance, which we continue to optimize. There is a healthy tension between availability and ensuring that we are there to deliver reliable power when we are really needed. Being flexible is critical. Sometimes it doesn't make sense to pay to shorten an outage if the demand isn't there. Given the option of maximizing gross margin or pure technical availability, gross margin wins every time. Looking deeper into our strategy to achieve reliable operations is how we think about operational excellence. Our ability to optimize our performance is built on a disciplined foundation of asset management. By defining what we are solving for, we tailor our strategy to the asset and develop plans to manage each site through its life cycle accordingly, which we execute through adherence to good operational work management and project management practices. Our asset plans encompass economic factors, mode of operation, age, location and customer requirements, all of which is underpinned by a risk management framework and a focus on spend management. We further optimized our plans in real time by leveraging equipment condition knowledge by extracting insights from operational data analytics, which we align to real-time commercial conditions to inform optimal maintenance decisions. I will now shift to our core region that has our largest operating footprint, Alberta. We're entering a period where fundamentals are beginning to shift. Load growth is coming from data centers, population growth and electrification. And over that time, the market will tighten as conditions increase the value of flexible, reliable and dispatchable generation. While Alberta remains one of the only markets in North America that has long power today, it's also a volatile market. Success in this environment requires actively managing the portfolio, optimizing dispatch decisions and positioning assets to perform as conditions evolve. This is where TransAlta is truly differentiated. We're the only operator in the province that operates across 6 technologies, supported by best-in-class optimization and trading capabilities. That diversity allows us to respond across different market conditions and positions us extremely well to recapture value and as the market tightens and growth accelerates. The Alberta power market is one of the only fully competitive electricity markets in North America. It is also unique, given that over 50% of its load comes from industrial demand. The market has undergone significant change since 2020. Load has grown at a steady pace. However, supply has rapidly increased over the past 5 years, driving significant movement in the power price. In 2020, coal made up over 5 gigawatts of the installed capacity, or approximately 1/3 of supply. And by 2024, the last coal-fired plant in the province underwent conversion to natural gas-fired generation. At the same time that coal units are being retired or converted, wind, solar and natural gas generation rapidly expanded, far outpacing the demand that the province required. Given Alberta is the only merchant market in Canada, renewables were built to support sustainability initiatives in other jurisdictions without the corresponding need for physical power. The generation build-out has led to the current oversupply, which our team anticipated and hedged accordingly. While near-term prices are suppressed and given most jurisdictions are short power, Alberta is seen as an attractive location for data center development, which would increase load and rebalance with supply. Our generating fleet in Alberta is the backbone of our company and where we started at 115 years ago, supplying power to the City of Calgary from hydro on the Bow River. Over time, our fleet has evolved to be largely coal-based and has since undergone further transition, moving away from coal fired generation to being a diverse mix of hydro, wind, solar, storage and natural gas-fired generation. The Alberta generation assets are managed and operated as an integrated dynamic portfolio. Our objective is to maximize value through a combination of hedging and contracting and realizing price premiums in the spot market by dispatching our gas and hydro facilities according to market signals at the times of highest value. Our units are dispatched in real time based on the relative efficiencies and costs in order to achieve the highest margin in any given hour, respecting the capabilities of our assets and the unique characteristics of our hydro portfolio. In addition to energy revenues, our gas and hydro assets are valuable providers of ancillary services and operating reserve to the AESO. So our team evaluates the optimal allocation of total generation capacity between these markets in each hour. We manage our sustaining capital and operating costs in an efficient manner. Across the fleet, we have held our cost per installed megawatt hour below the rate of inflation and flat through the balance of the decade. Our commercial and industrial business acts as a trusted retailer to thousands of customers in Alberta and is an important source of liquidity as part of our portfolio management and hedging strategy to secure predictable revenue and margins. Through this business, we provide both standardized and bespoke energy solutions for our customers and other retail partners. To enhance the competitiveness of our portfolio, our emissions trading desk continuously evaluates the optimal allocation of the emissions credits our renewable generation portfolio creates, whether to use for our own obligations or to execute transactions with third parties. Longer-term strategic decisions are based on our internal analytical capabilities. Because of this internal strength, we can be confident in our decisions for capital planning, investment, M&A activity, and structuring long-term commercial partnerships. By utilizing our portfolio approach, our Alberta business has performed exceptionally well. The optimization team forecast pricing trends years in advance using complex models that take thousands of scenarios of supply and demand and load into account. At the beginning of the decade, we had lower hedge positions relative to now, as we saw tightness in supply and the potential to capture more high-priced hours. In 2023, we forecasted the overbuild of supply from renewables and new gas generation. And we started to lock in a higher hedge position at attractive prices for 2024 through 2027, which overall has resulted in strong realized pricing year after year. Our ability to achieve higher realized pricing and exceptional ancillary service value is highlighted by our historical performance, where we have consistently realized premium pricing to spot. For hydro, our trading and optimization team has been able to strategically use our units to achieve higher-than-average pricing by saving water during periods of low demand and releasing it during periods of high demand. For gas, this is largely due to the work that we have done to improve the flexibility of our units. While this premium may narrow in the near term during the period of oversupply. As loan growth increases, we expect our ability to optimize our premiums will improve. This figure illustrates an example of being there when we're needed. This is from last September, showing how our fleet can respond to capture higher priced hours. During periods of lower renewable generation and hot weather, we saw more volatile and stronger prices. Our dispatchable fleet, inclusive of our hydro and CTG units, were able to quickly ramp up and respond to market tightness when they were needed. Going forward, opportunities for flexible generators should increase as supply tightens over the next few years, and our units are situated to capture both the incremental volume and more frequent higher-priced hours while not running through periods of $0 pricing. This plays to the strength of our portfolio optimization and the unique capabilities of our fleet. In August of 2025, the AESO announced its final design for the Alberta restructured energy market, or REM. The structure is consistent with our expectation and adds greater certainty to the market, something our diverse and dispatch regeneration fleet in Alberta is well suited to provide. The REM is expected to be implemented in 2028, and we will continue our active engagement in the AESO consultation process, which is now focused on implementation. The revised market design favors dispatchable generation. And as I have illustrated, TransAlta's increasingly flexible approach makes us very well positioned. We have calculated the reserve margin here in a similar format to the AESO. The reserve margin has historically shown the tightness, and more recently, the loosening of the margin based on the supply and demand dynamics previously discussed. Our forecast shows that the reserve margin will tighten and existing generation will become increasingly valuable. We expect new firm supply in Alberta to be limited to less than 700 megawatts over the coming 4 years. Assuming the most severe single contingency or MSSC, is raised, along with a modest amount of additional new gas generation and intertie restoration. The current oversupply and potential new additions will be offset by demand growth in the province, which we expect to continue to be 1.5% annually. Data center growth of 1.2 gigawatts is also included, based on the AESO's allocation through the Phase 1 Large Load Integration process. The timing of the data center load ramp will be variable and dependent on customer schedules. We believe that the new load will outpace supply in the short term by a net amount of 1.1 gigawatts, leading to a tightening market. We assume that weather will be normalized, and the load does not account for hotter summers or colder winters. Due to the current oversupply in the Alberta market, our 2.6 gigawatts of coal to gas-fired facilities shown at the bottom of the slide do not run that often. As evidenced last year, when they ran less than 20% of the time, despite being close to 20% of the total installed dispatchable generation. This is largely due to economics and the corresponding management of our Alberta portfolio. The takeaway here is that while this demonstrates our coal to gas units have had a limited role in the current market, they are the main source of supply to benefit from incremental load coming to the province. Our coal to gas units are designed to operate as baseload and are fully capable of operating at 90% capacity factors. Their recent performance has been driven by economic decisions, not capability, and any planned maintenance can be timed and scaled to meet market conditions. Most of our coal to gas units have regulatory end-of-life dates in the back of the half of the 2030s. And our team's ability to effectively operate the facilities has allowed us to run them through the peak lows and lows of the market throughout their operating lives. Our internal modeling shows that the expected low growth will drive higher priced hours. TransAlta's merchant fleet is largely made up of dispatchable units such as our hydro fleet, our converted natural gas units and the peaking gas units acquired in the Heartland transaction. They are operated by a capable team to capture these high-priced hours and provide reliability when supply gets tighter. Based on the previously discussed supply and demand assumptions resulting in a net change of load of 1.1 gigawatts through 2029, we expect the Alberta power price to recover through the end of the decade. We have sensitized the impact on price by changing the net position by plus or minus 200 megawatts, as actual results will vary based on supply assumptions, weather and load ramp. We've assumed that the 1.2 gigawatts of data center load ramps through 2028 and is fully online by 2029. The actual load profile may differ materially from what is presented and is intended to illustrate what the potential impact could be. We do not believe that the forward curve is yet pricing in the incremental load. In fact, we believe the current forward curve offers a decent representation of the power price outlook in the event that load does not increase for data centers. However, we remain confident that data center load will come, beginning with our initial 230-megawatt allocation, as well as our peers' 970 megawatts. Longer term, we expect power prices to moderate in the $85 to $100 per megawatt hour range as supply and demand keep the market relatively balanced and incremental data center load is assumed to be matched with incremental supply. That concludes my section, and I look forward to addressing your questions during the Q&A panel at the end of the presentation. I will now turn it over to Stephanie.

Thank you, Chris. We'll take a short break now before we continue, and we'll restart the presentation with our next session in about 15 minutes. Thank you. [Break]

Welcome back, everyone, and hopefully, everybody had a chance to top up their coffee here for the second part of our presentation today. So I'm pleased to share our growth priorities, which advance our strategy to the end of the decade. We're advancing targeted long-term growth opportunities where we'll leverage our existing infrastructure and market expertise to generate attractive risk-adjusted returns. Our data center strategy is intentionally structured to begin with a low capital cost investment that will produce contracted cash flows with high-quality counterparties. This opportunity will provide us with visible platform for future growth. Centralia is also essential to our growth strategy and will be a major focus for us over the next few years. Once complete, Centralia would produce long-term contracted cash flows and support much needed reliability in the state of Washington, creating a strong foundation to fund future growth. We also have a strong track record of M&A. Our 3 most recent transactions were immediately accretive, improve the quality of our cash flows and strengthen our platforms across our core markets. Taken together, our growth strategy prioritizes returns, maintains financial flexibility and consistently enhances shareholder value. Now before diving into specific projects, I want to begin outlining our investment criteria, which serve as a basis for how we assess opportunities. Along with ensuring that projects are aligned with our strategy, we set hurdle rates for each technology type that offers appropriate risk-adjusted spreads over our cost of capital. From there, we analyze factors that might increase or decrease the risk premium above these hurdle rates. We constantly weigh risk and return trade-offs and compare each project against other possible uses of our capital, which I'll talk more about later this morning. Importantly, we do not target a specific asset mix or a number of megawatts in the portfolio. Instead, we direct capital to the most value-accretive opportunities. Our growth strategy is concentrated within our key geographic regions that includes Alberta, Ontario, the Western United States and Western Australia. In addition to pursuing opportunities at our legacy sites, we are advancing a portfolio of development projects designed to position TransAlta for future growth throughout this decade and beyond. For example, in the Western U.S., we are exploring thermal opportunities in Arizona and Wyoming, and we're also progressing a firming expansion initiative at our South Hedland site in Western Australia, alongside several small-scale development projects. We'll provide further details on these early-stage projects as they evolve. Now Alberta presents distinct geographic advantages for data centers. Notably, our natural gas fuel generation sites are situated near competitively priced and accessible natural gas supplies. Furthermore, both the Alberta and federal governments have demonstrated their commitment to fostering growth in data center sector within Alberta, along with the AESO, as evidenced by its Phase 1 allocation for Large Load Integration and continued efforts with Phase 2. TransAlta is well positioned to meet the increasing demand from data center customers by providing timely, cost-effective, reliable and sustainable energy solutions. And this is facilitated by our current portfolio, along with the advancement of our development projects. In connection with our fourth quarter and year-end 2025 results, we announced an MOU with CPP Investments and Brookfield for data center development in Alberta, where TransAlta is the exclusive power and site provider. The Keephills site in Parkland County will see a phased development, beginning with a long-term power purchase agreement for approximately 230 megawatts and a potential expansion up to 1 gigawatt. Keephills offers a compelling platform with extensive zone land, existing transmission, natural gas, water infrastructure and on-site generation. We look forward to partnering with CPP Investments and Brookfield, both experienced global infrastructure investors capable of delivering large-scale projects. As we advance our data center strategy, we'll endeavor to share as much as possible with you. Now last year, we made meaningful progress on 3 natural gas generation projects in Alberta, creating low-cost options for future expansion. Although these 3 developments may not be required in the near term, having multiple alternatives available at this stage provides us with optionality and a competitive advantage. Repowering initiatives for Sundance 5 and Keephills 1 originally launched in 2019, but paused due to market oversupply and economic challenges, remains viable. Each project has the potential to generate up to 800 megawatts of electricity by leveraging existing sites and infrastructure, potentially reducing cost and construction time lines. Additionally, the Flipi gas plant acquired last year is an advanced stage project, is a 460-megawatt natural gas combined cycle power project near Rimbey, Alberta, which can be expedited subject to suitable contracting opportunities. All 3 projects have been submitted as planned units according to Canada's Clean Electricity Regulations and have been filed with the Alberta Utilities Commission following active stakeholder engagement. Whether the CER restrictions are lifted or not, we have a relative speed to power advantage over other Phase 2 options. We are optimistic about these projects and their alignment with the Phase 2 Large Load Integration objectives, and we look forward to advance them, if supported by long-term contracts. Now this slide explains the concept behind repowered combined cycle plant, providing insight into what our Sundance 5 and Keephills 1 projects might involve. Repowering coal-to-gas facilities involves adding new gas turbines and generators. Electricity generated by these new units is delivered to the grid via our existing transmission infrastructure. Hot exhaust gases from the gas turbines are directed through heat recovery steam generators, providing steam. This steam then feeds into existing steam turbines and plant infrastructure, which maximizes energy output while lowering carbon emissions. A repowered combined cycle facility blends both newly installed and existing equipment, resulting in efficiency measured by heat rate that is comparable to that of a completely new combined cycle gas turbine plant and an overall lower capital cost. In December, we signed a long-term pulling agreement with Puget Sound Energy to convert Centralia Unit 2 from coal to natural gas. The tolling agreement gives PSE exclusive rights to Centralia's 700 megawatts of capacity, energy ancillary services and dispatch rights at a fixed capacity price through 2044. The USD 600 million conversion will reduce emissions by approximately 50% and anticipated build multiple of 5.5x with a projected completion date in late 2028 and an FID expected after receipt of all required approvals in early 2027. Last week, the United States Department of Energy issued another temporary order requiring that Centralia remain available if called upon to operate for a period of 90 days through June 14. As required, TransAlta is complying with the order and continues to advance the conversion, in alignment with PSE, in order to achieve the targeted commercial operation date. The project has continued to progress, and I'm pleased to share that PSE recently submitted its associated rate case, advancing the regulatory time line on schedule. Now the conversion of coal boilers to natural gas is technically a straightforward process, as demonstrated by the successful modifications completed at 7 facilities within our Alberta fleet, which will inform our approach to the boiler conversion at Centralia. Transitioning to natural gas offers considerable advantages, including reduced overall cost, greenhouse gas compliance expenses and OM&A. The conversion involves replacing coal burners with gas burners and installing new gas field control systems. Gas boiler conversions also simplify the production process as they remove the necessity for major plant components such as rail-based coal imports, coal handling equipment and ash handling equipment. Now Centralia's capital costs fall into 3 main categories. The largest is for the coal and gas conversion, covering items related to boiler burner upgrades, gas regulation equipment and fan upgrades. The second category is related to planned life extension to maintain operations until 2044, including our auxiliary boiler and feedwater heater replacements, cooling tower rebuilds, software updates and installing a new natural gas supply line. The third category covers reliability and maintenance for major turbine and generator work, control repairs, boiler tube and piping repairs and safety valve overhauls. Our engineering and construction teams are actively preparing to advance the conversion upon declaring an FID in early 2027, with a focus on maintaining the planned schedule and keeping capital costs as low as possible. So while our near-term development is focused on our legacy sites, longer term, we are advancing unique opportunities that leverage our competitive advantages and are grounded by our investment principles. Our development platform is designed to provide strategic optionality and deliver ratable long-term growth. We are advancing smaller, high-returning power solutions in both Alberta and Western Australia that can augment our portfolio. In parallel, we have identified other legacy site opportunities in Western Australia, Ontario, Washington and Wyoming that leverage existing landholdings, infrastructure and relationships. In the Western U.S. We are focused on gas development in states like Wyoming and Arizona, where demand is growing, planning processes point to continue to need for dispatchable generation and regulation is supportive. We also continue to value technology diversification as market conditions evolve. Our investment in Nova Clean Energy gives us exclusive access to a pipeline of renewables and storage projects, and we retain an option to acquire projects when returns meet our thresholds. In Western Australia, our legacy sites give us a platform to grow. Customers continue to electrify both mining and other industrial activities, where reliability is paramount. We are well positioned to deliver firm, reliable power in a market where demand is growing and alternatives are limited. In total, this pipeline opportunity exceeds 5 gigawatts and gives us optionality and positions TransAlta for long-term ratable growth. Now in addition to developing projects, we have a proven history of executing value-enhancing M&A. When considering an M&A opportunity, it must be immediately accretive on a free cash flow per share basis, largely contracted with strong counterparties, does not compromise the balance sheet and provides a platform for future growth. Our disciplined approach has translated into results following the transactions that we've executed since 2023. Between the acquisitions of TransAlta Renewables, Heartland and Far North, we added assets at attractive multiples with high levels of contracted cash flow and with a clear recontracting and optionality upside. These transactions were immediately accretive, enhance our contractedness, and in the case of TransAlta Renewables, simplified the corporate structure, all while strengthening our balance sheet and financial flexibility. Going forward, we'll stay selective, contrarian when appropriate and focused on long-term value creation. Next, I'm going to address the priority of enhancing our financial flexibility. Our financial position is strong and it gives us meaningful flexibility, and we're seeing attractive EBITDA growth potential driven by load growth in Alberta and Centralia. These opportunities are well aligned with our strategy where we are leveraging existing assets, improving contracted cash flow and supporting long-term capital allocation. We have a diverse set of levers available to us, which I'll go over in more detail here shortly. This flexibility allows us to deliberately funding growth where risk-adjusted returns are compelling, strengthen the balance sheet and return capital to shareholders when appropriate. Taken together, our strong financial position underpins our ability to grow with discipline while maintaining flexibility across economic cycles. These 7 financial principles underpin our decision-making process. We are committed to enhancing the contractedness of our portfolio, which will in turn improve our ability to finance assets with long-term capital. While we're comfortable maintaining our BB+ rating in the near term, we recognize that achieving investment-grade status remains a key objective over the longer term. We value simplicity in our corporate structure, as it contributes both to value creation and operational efficiency. Our approach to capital allocation will remain disciplined, focused on per share accretion, and we'll maintain strong focus on cost control. Active management with the capital markets will continue to be a priority, and we will continue to unlock value through portfolio management. Establishing these key guidelines upon joining the company was a priority for me, and I'm confident that its steadfast adherence to them will strengthen our financial position and enhance shareholder value over the long term. Our balance sheet remains strong, supported by ample liquidity and a well-structured debt maturity profile. Last year, we amended and extended our committed credit facilities totaling $2.1 billion, enhancing our financial flexibility and capacity, and refinanced over $900 million of long-term debt in the Canadian and U.S. debt capital markets at favorable all-in funding levels. We continue to target a long-term debt-to-EBITDA ratio of 3x to 4x, though near-term market conditions in Alberta and Centralia being offline during its conversion to natural gas may result in a modest deviation from this range, which is anticipated to be short-lived. We have a number of funding levers available to support our growth initiatives, which contribute to a stronger business risk profile and further reinforce our credit quality. Turning to our capital allocation framework. Free cash flow serves as a foundation for our capital allocation strategy. Approximately 15% to 25% of our free cash flow is allocated to returning value to shareholders via dividends, with the remainder either reinvested in the business or returned to shareholders via share repurchases. This year, we project a dividend payment of around $80 million, representing a payout ratio of approximately 20% based on the midpoint of our free cash flow guidance of $400 million. We anticipate that our payout ratio will decrease towards the end of the decade as free cash flow continues to grow at a higher pace than our dividend growth rate. The remaining 75% to 85% of our free cash flow is earmarked for growth opportunities. We evaluate all growth opportunities on a per share basis to ensure we are creating shareholder value without compromising our balance sheet. Any opportunities must meet our hurdle rates, be underpinned by a long-term contract and be considered against alternative uses of capital. Our approach represents a disciplined and measured strategy that aims at maximizing long-term shareholder value. Should suitable opportunities not arise, we will consider returning additional capital to shareholders through share repurchases. Now I'd like to emphasize the effectiveness of our share buyback program over the past 5 years. Between 2020 and 2025, we returned CAD 366 million to shareholders via share buybacks, representing approximately CAD 1.25 per share. Returning capital to shareholders has been very effective, particularly during periods in which our share price experienced downward pressure. Going forward, we will continue to carefully evaluate growth opportunities in conjunction with decisions regarding returning capital to shareholders. Our 2026 adjusted EBITDA guidance is projected to be approximately CAD 1 billion at the midpoint of the range. Looking ahead, we anticipate that the Centralia coal-to-gas conversion will contribute an additional CAD 150 million in annual EBITDA by 2029, subject to FID and assuming commercial operation beginning in late 2028. As discussed on Slide 44 regarding Alberta's net load growth sensitivity, a net change of 900 megawatts in load, inclusive of our Phase 1 data center allocation of 230 megawatts, could generate approximately CAD 200 million in incremental EBITDA relative to 2026 levels. Should load increase more rapidly or if additional supply is not made available, an additional 200 megawatts of net demand could contribute an additional CAD 150 million of EBITDA, with an additional 200 megawatts in a high-case scenario potentially adding CAD 300 million. It is important to note that TransAlta's exposure to near-term load growth impacts both volume and pricing, as our coal to gas units currently represent underutilized generation capacity within the province. Our projected free cash flow by the end of the decade, combined with additional debt capacity, assuming an approximate 3.5x debt-to-EBITDA ratio, puts us in a strong position not only to meet our commitment to fund common share dividends and the conversion of Centralia, but also additional contracted investment opportunities. For example, in the event there is a 900-megawatt net load change in Alberta, free cash flow for reinvestment combined with incremental debt capacity would be about CAD 2 billion. In the event that net load increases by 1.3 gigawatts over the period, we estimate an additional CAD 2 billion would be available for reinvestment. As we look to redeploy these cash flows longer term, our strategy is clear. We are developing attractive, largely contracted opportunities that reinforce long-term shareholder value creation. We see multiple scalable reinvestment paths that will largely depend on opportunities that provide the most attractive returns. We can advance up to 1 gigawatt of contracted data center load at our Keephills with an additional Phase 2 opportunities that could build upon that platform. We also have legacy site development potential, leveraging existing infrastructure to deliver speed to power and attractive economics. Beyond that, we have a refined greenfield development pipeline that is focused on bilateral contracted solutions. Importantly, this capital redeployment will be executed with our long-term financial framework, developing ratable growth with a self-funding model that is scaled to our free cash flow and debt capacity. And finally, we retain flexibility for disciplined accretive M&A, in line with our strategy. Our main source of funding continues to be operating free cash flow, but we also have access to several other attractive funding options. We have the ability to finance growth with long-term debt at either the corporate or asset level in both the Canadian and U.S. debt capital markets. The amount of debt capacity is governed by our leverage levels, commensurate with maintaining our current credit ratings. We'll also consider selling noncore assets to raise capital for high-value opportunities and further narrow our focus in main geographic areas. We continuously review our portfolio and weigh the advantages and current market value of potential divestitures. Partnerships, especially for large capital-intensive projects, are another lever. There's significant interest in our opportunities, and we currently have several partnerships in place. Potential partnerships will be based on our funding requirements, strategic fit and ability to diversify financial exposure across projects, portfolios or regions as needed. After reviewing free cash flow, debt portfolio rotation and partnerships, we consider issuing common equity. Now this option is reserved for highly accretive opportunities such as M&A or major growth projects, depending on deal size and the time to cash flow. We always evaluate the impact on earnings and free cash per share when issuing equity, ensuring alignment with our strategy. So turning now to our closing remarks before we open the floor to Q&A. Our strategic priorities are focused on maximizing value. First, we'll operate with excellence through safe, reliable and efficient operations, proactive optimization of our Alberta fleet, enhancing our financial flexibility through disciplined capital allocation and cost control. Second, we will continue to grow with discipline through the advancement of our legacy site projects, including Centralia and Alberta data centers, pursue accretive M&A opportunities focused first in our core geographies and progression of high-quality refined development pipeline for long-term development opportunities. Successful execution of these priorities will ensure our business remains resilient, growth focused and aligned with the evolving energy landscape that ultimately delivers shareholder value. Now I'd like to close by highlighting what I think makes TransAlta an attractive investment and great value opportunity. We are a safe and reliable operator with strong cash flow underpinned by our diversified hydro, wind, solar and thermal generation portfolio located across 3 countries, and complemented by our leading asset optimization and energy marketing capabilities. There is significant and growing value in our legacy thermal sites, which our team is actively working on to repurpose to meet the growing need for reliable generation in the jurisdictions in which we operate in. We remain disciplined in our approach to growth, focused on delivering value for our shareholders as we look to diversify our portfolio within our core geographies and increase the stability and contractedness of our cash flows. And our company has a sound financial position. Our balance sheet is flexible, and we have ample liquidity to pursue and deliver multiple growth opportunities, along with the ability to also return capital to our shareholders. And finally, and most importantly, we have our people. Our success is based on our people, and I want to thank all of our employees and contractors for their commitment and setting the company up for success this year and beyond. Now that concludes my prepared remarks, and we look forward to taking your questions. But before turning the floor over to Ben, I'd like to take the opportunity to thank John again for his leadership, strategic vision and his meaningful contributions to TransAlta. On behalf of the company, thank you, and we wish you all the best, John, in retirement. I'll now turn it over to Ben.

Thank you, Joel. Good morning, everyone. My name is Ben Harris, and I'm the Manager of Investor Relations. We'll now begin the question-and-answer period. [Operator Instructions] I'd like to invite John, Joel, Chris and Nancy to join us on stage now to begin taking questions.

All right. Rob Hope from Scotiabank. I was hoping you could add a little bit more color on Slide 70 on the potential EBITDA uplift in the data center scenarios. I just want to get a better sense of that incremental $200 million of EBITDA for the 900 megawatts. Is that also including the uplift in pricing across the portfolio, such as the wind and hydro? And then also, kind of what capture or increasing utilization of those coal-to-gas units are you implying there?

Yes. I'll start here, Rob, with it. Yes, it's -- that scenario assumes obviously the higher pricing that you saw in the graph that Chris walked everyone through, which we believe is not reflected today in the forward pricing. And particularly when you look out to 2028, 2029, that we see that forward pricing today is not indicative of where we see pricing going. And I think we have a demonstrated track record of really being accurate forecasters or where we see our pricing going within the province. So it is reflective of the 900 megawatts, which really benefits our entire portfolio. Which, again, Chris showed earlier where our coal to gas units that are running less than 20% capacity last year. Certainly, we'll benefit from that. But we also see some uplift in our hydro fleet, although they're running near full capacity today at most times, but we do see an opportunity for our hydro fleet, even our wind fleet that's not contracted in Alberta to also benefit from the uplift that we'd see in pricing, along with what's in that number would be what we deem to be kind of the contracted portion from our Phase 1 allocation of 230 megawatts. So it's all kind of in that bucket, Robert.

All right. I appreciate that. And then maybe just as a follow-up question. If I take a look at Slide 48, which has your outlook for power pricing in Alberta relative to the forward pricing. So in 2028, we have, we'll call it, $75 to $100 pricing versus the forwards and 60s. Can you maybe talk to why you are above the forward market? And does that include some step in data centers in '28?

It does, Robert. If you look at where forward pricing was even towards the end of last year, it was in that kind of $80 range when you look out to 2028. And I think even north of $80 in 2029. There hasn't been a lot of liquidity in both CAL '28 and CAL '29 that we've seen this year. So it doesn't take much to remove the pricing. And there's a big bid/ask spread, if you will, in the forward curve right now. I think what's really going to improve that forward outlook will be when you see further announcements for data centers. So obviously, there's a competitor out there that has 970 megawatts under Phase 1. When they get to a point of announcing their project, I think that's when you probably see the market get further comfortable to say this load is actually coming in the time period that we expect where we see the ramp-up, they occur in '27 through 2029. So again, I think that will be a key moment there. And I think when we get to our definitive agreements, too, that for our 230 megawatts, I think, further support that confidence, if you will, in forward pricing. So again, we kind of go back, we spend a lot of time with our forecasting analysis that you heard Chris talk about. We met thousands of different scenarios. We have a full team on this, and we firmly believe in our pricing scenario that we have on that chart today that's not reflective in the forward pricing due to that load liquidity that we're seeing. And I think, again, not a lot of visibility quite yet. Our confidence maybe from the market on the 1.2 gigawatts of load that's coming.

All right. Thank you, Robert. Our next question comes from an investor online. How does the company evaluate the potential of acquiring or creating a new gas asset versus a renewables asset?

Yes. It's about risk-adjusted returns for us. So we're not looking to say, okay, we have to have so many megawatts in our portfolio that's renewable or natural gas. It really comes down to what our customers are looking for and then evaluating, okay, on a risk-adjusted basis, what offers the highest returns for us and our shareholders. We'd say right now, we're seeing more opportunity in natural gas, no surprise there, in all of our 4 geographies in which we operate in. As I mentioned in my prepared remarks, we see opportunities right now in Wyoming, in Arizona. These are still early days, but we are seeing real opportunity there and real support, both from a policy side and from customers to build new thermal generation there. But at the same time, there's still interest in renewables. And this is 1 of the reasons why last year we made the decision to invest in Nova Clean Energy and really, I kind of say outsource our renewables development platform to them. They are increasingly focused on the WEC. And for them, the benefit they get from TransAlta is not only financial support, but they get to really leverage our marketing and trading expertise in the region. So we could see real opportunities where we're actually coupling both thermal and renewable generation together in certain geographies like Wyoming, for example, or even maybe in Arizona. So the question really is around how do you evaluate it. It does come down, like I said, to what customers want and where are we going to get the highest risk adjusted returns. We have to have a long-term contract where we get a full return of and on capital within that contract period.

All right. Our next question comes from Maurice Choy from RBC.

Maurice Choy, RBC. Two questions. I'm just going to ask it right away. First question is, can you give us a sensitivity? Not that we don't believe your assumptions, but if you give us every $10 change in the 1,100-megawatt scenario, what every $10 change means to your EBITDA? And the second question is ultimately, to your point about free cash flow per share and that ultimately drives how you view things, could you give us an idea as to what that CAGR looks like and/or what drivers are changing between now and 2029? Because your $2 billion of FCF effectively triangulates to over 20% CAGR. So I wanted to make sure my math is right.

Thanks, Maurice. I'll address the second part of your question. First, you're correct in that high scenario when we showed you the EBITDA, that would translate to probably just over 20% CAGR, whereas at the low end, we're probably around 11% or 12%. And what's interesting there is very capital light for us, right? Not a lot of spending on Phase 1 for 230 megawatts and really dependent upon where the market goes, and it tightens up, as Chris mentioned in his prepared remarks. So we do see a lot of upside in our EBITDA. It will ultimately depend on where the pricing settles in at, but just based -- we want to get to give you that range here today. When we look at the conversion of EBITDA to free cash flow, I think the good rule is to use roughly 45%, maybe 50%. One example that I'll give you that's really interesting, though, is when we look at Centralia, for CAD 150 million, that effectively is all cash flow. There's no real interest associated with that asset. There's no project financing in place. And we have loss carryforwards in the U.S., such that our cash taxes remain very low. So that's a really unique opportunity where CAD 150 million of EBITDA essentially drops down to free cash flow. So that's part of the reason why I say that 45% to 50%. There's certain opportunities here like Centralia where it's actually going to be 100%. But when you put it all together, it's around that 45% to 50%. When you talk about the sensitivity here, I think whenever we look at kind of our sensitivity for every kind of dollar change, it's anywhere from $2 to $3 of EBITDA for us. So think of it as $1 but 1 -- $2 million to $3 million of additional EBITDA. So to give you kind of that sensitivity in the model.

And I would say depending on our hedge position. So as we're more open, I would say, in the future, it might be a bit higher than that.

Good point, John.

Any idea how much higher?

Yes.

On that note, congrats, John.

No, no. I mean it's -- like all joking aside, it could be -- I mean, you could see sort of it nudging up towards 4, I would say, depending on where we are. But it also depends on fuel costs and whatnot, Joel, I would say. So it's a bit of a malleable number.

Yes.

Thanks, Maurice. Our next question comes from online. So in the past, TransAlta has been quite tied to its assets. So Joel, how are you thinking about asset rotation?

Yes. So we have 92 assets in the portfolio today. And in my remarks, I said that we would look to portfolio rotation here to fund future growth. For us, it really depends on the opportunities, what's the use of proceeds whenever we look to raise capital, whether that's in the debt capital markets or rotating capital, there has to be a clear use of proceeds. We also consider the geography. We also consider the ability to recontract that specific facility and take that all under consideration. But I would say to you that we're very excited about the opportunities that we see in front of us both in the near term, but also in the longer term in our core geographies. So I do expect that portfolio management will become a more active funding lever, if you will. The last point I would make is as we talk about our geographic focus, if you look at the map, we still have some assets that are kind of outside of that, if you will. So I think those would be assets that we would look at potentially monetizing here down the road. But again, it comes down to the use of proceeds here that -- we don't want to give up cash flows or EBITDA, if you will, and not have a go anywhere. So we have to have clear use for that. And we are seeing that. When we look at, for example, Centralia, that spend will ramp up starting next year in 2028. So there could be a potential there, we would like to rotate assets. But right now, our funding model would indicate that our free cash flow and debt capacity should be able to fund that project.

Next question comes from Ben Pham from BMO.

First question for Joel is you've -- as you think about taking the baton from John, just thinking about 2029 numbers, you have a good sense of 2026. Can you give us some very high-level viewpoints of where you think the business is going to go? I'm thinking particularly contracted percentages, geographic mix? And anything else you can share around that, just in terms of your ideal scenario where you see things going?

Yes, Ben, I think the first thing is being increasingly contracted is really important for us. That's going to add value for our shareholders longer term. What we're experiencing right now in Alberta, the volatility that we see by having a merchant component. We want to reduce that as much as we can over time. So whether that's going to Centralia under a 16-year contract, for example, or as we look to development opportunities that we're seeing in Alberta, those would all be underpinned by long-term contracts such that over time, we see the merchant component of our portfolio decreasing. So by 2029, ideally, if we could be at least 70% contracted, that would be ideal. If we could go higher than that, even the better. I think that translates into a stronger business risk profile, which may allow us to improve our credit ratings. But more importantly, I think we get a better valuation in the marketplace. And for us, providing that visibility and stability that we see in our EBITDA and cash flows going forward really helps us plan our strategy. So that's the key, I think, for us. And as I look at taking the baton, the strategy remains the same here as we focus on our key geographies. So again, when we see opportunities in Alberta, we see opportunities in the Western United States. And in particular, as mentioned, right now, we're looking at opportunities in Arizona and Wyoming. I think having more physical assets in that region, given our marketing and trading capabilities is really important for us. So again, we're very excited by that. We have a team that's in place. I was actually down in Denver a few weeks ago meeting with the team, and I was pretty excited by what I was seeing with those opportunities that they're identifying. Early days, but we're looking at opportunities here in Ontario. It's great. We've got some existing assets like Sarnia, for example. There's an ability here to do more with that facility. Then in Western Australia, the same thing. The team sees lots of opportunities, albeit smaller scale, kind of in that 10 to 50-megawatt kind of size, but ultimately, they could get some larger opportunities as well. So really having that discipline on geographic focus, underpinned by long-term contracts, that's what we're looking for here. But also being able to fund it kind of living within our means, if you will, with our free cash flow, debt capacity to the extent that we see portfolio rotation, we'll do that.

Okay. And maybe a related question. Now you have Alberta power mix, roughly, what, 50% today, give or take. And then you have some pretty good sensitivities you provided in terms of the uplift there, plus you got Phase 2 potentially. And I'm not against -- or I should say again, I'm thinking about that portfolio mix, Alberta increasingly shifting very high, looking at what I'm seeing today is -- how do you think about that -- I'm not made putting all the eggs on a basket is the right term for it, but is there a constraint or a limit of how much you want Alberta to be? Or do you feel that TransAlta is the best play in Alberta and do you want to move towards that path?

For us, I think what Chris identified is we have these underutilized assets today with our coal to gas fleet around 2.6 gigawatts that have potential upside here with really very little, if any, kind of capital investment for us. And so as you look out to 2029, yes, a lot of this is really due to power pricing in Alberta because the rest of our fleet is essentially contracted. Our job will be to take those cash flows to the extent they are merchant and convert them into contracted opportunities. So yes, we see an opportunity here from 2026 out to 2029 that Alberta is going to generate a lot of that cash flow. But our job will be to take those cash flows and like I said, redeploy them elsewhere, even in Alberta. So if we think about Phase 2, we identified the 3 facilities that we have real optionality there, whether the CER stays or goes, which I think is really critical here. We're talking up to 2 gigawatts there with those 3 facilities. The objective there would be to invest in 1 of those or maybe all of them over time, they have to be underpinned by a long-term contract. But you think about where we're at today, where it's all about speed to power. Right? So we got all this load growth coming in, looking for areas that are long power. Alberta happens to be one of them. So we see there's a real opportunity to bridge, if you will, that growth with our existing units and knowing that we will eventually have to replace those units kind of post 2030. So that's what we're thinking about today. But when we make that capital investment in any new opportunity in Alberta, rest assured, it's underpinned by a long-term contract. So again, the objective here, Ben, is to, over time, take those cash flows and redeploy them elsewhere in cases -- maybe in Alberta, but underpinned by a long-term contract.

Yes. Our next one comes from Mark Jarvi in room.

So in the press release this morning talks about ratable growth, Joel. And you painted the upside of 2029. How do you frame this for investors beyond that in terms of how people can expect the growth to come from deploying free cash flow? There's not a big greenfield development pipeline in front of us here today. So is it largely M&A? Or how else do you instill confidence about the growth rate beyond '29?

Yes, Mark, I would say this is something that's really important for all of us is part of our strategy where we want to have, call it, ratable growth where you have that amount of your capital allocated toward kind of greenfield, brownfield development kind of every year, hopefully quick time to cash flow, depending on the investment opportunity that you're seeing. Complemented at times for M&A that is really viewed as being opportunistic, if you will, if you could feather that in as well. But what's really important here is that we are -- always have capital spending, but assets coming into service, using that free cash flow from that investment opportunity then to redeploy elsewhere. So we talk about ratable growth. It's where we have projects like a Centralia. Maybe not that same size, but we're spending money every year, and you see assets coming into service kind of almost every year, that kind of regular cadence. That's what we refer to ratable growth. That's -- that's how I view it. We're not quite there yet, but we're working on it. So when we talk about our pipeline, we said the 5 gigawatts because we're thinking about post 2029. We know with supply chain constraints and that it takes a long time to get anything built. We're fortunate, though, in this period of time with Centralia and what we're doing there. We're fortunate what we could see here in Alberta with the uplift in pricing, along with our Phase 1 230 megawatts, as mentioned, that we're good. We're seeing this out to 2029, and so what do we do with that cash flow after? So we have to be thinking about that today so that ideally, we started spending money maybe later this decade, maybe get an asset in service in 2030, 2031. Maybe another 1 a few years later, that type of thing. That's that ratable growth. But to the extent that we don't see opportunities that meet our hurdle rates, then we'll look to other opportunities, whether it's putting back to the shareholder. And that's what we did over the last few years. We didn't have that ratable growth. So for example, in 2025, we bought back about $145 million of our shares at just over $10. That was good. That was the best use of the proceeds at that point in time. But ideally, we want to get to that more kind of ratable greenfield brownfield growth, supplemented at times with opportunistic M&A.

When should we expect you guys to be able to put that in front of investors, then?

I think it will be kind of continuous, Mark, as these evolve. So as we see these opportunities -- and we know that some things will be advancing, some will be pulled out and others go in. So again, part of our financial tenets is obviously active communication with the capital markets. We're out all the time talking to our investors. I think it's important that we continuously update where we're at with certain projects that we're looking at. So a lot of them right now are still very early days, but we remain optimistic and the team is focused on that. And what's key here is that we're not looking at like 30 different projects either. We're very focused on how we look at our corporate development. So laser focused, obviously, right now in certain regions I talked about in the Southwest or Wyoming. We're focused obviously in Alberta. We're certainly focused on Centralia. And then the great thing is with Nova Clean is that we're kind of relying on them, they could start bringing projects forward as early as 2028. So -- but so long as it meets our expectations, we have right of first offer, if you will, on those opportunities as well. So we can't forget about that at Nova Clean. They've got over 2 gigawatts kind of very advanced in their pipeline right now that we could start having a look at to see if that's something we want to invest in or not.

And just going back to the power price outlook, you talked about your own vision, where it should be relative to the forward curve. And just how would you communicate that to the market in terms of where the minimum level of contracting would be then for TransAlta is 85%, sort of the low end of the range that you'd accept the price in a long-term contract? Or would you be willing to flex a little bit on the low end, provide that contracting us, what you think is important for the cost of capital and the valuation of the stock?

Yes, Mark, I think it depends. I would say certainly not at 50%, but you're kind of right. I think around that 80%, 85% area would be ideal, if not higher. But I think it depends. So for example, given our marketing and trading capabilities, for example, in the WEC, could we look for an opportunity whether it's M&A related or what have you, that, say, 75%, 80% contracted, knowing that there's probably some asymmetric upside? Given our capabilities, we would look to that. But I think overall, as we look at how we allocate our capital going forward, whether it's greenfield, brownfield or M&A, it has to be largely contracted.

Thank you, Mark. Our next question comes from online. What role does TransAlta see new technologies such as lithium ion batteries, hydrogen, where SMR is playing in its long-term plan?

So I'll start with that, and I know, Chris, you might want to chime in on this one. I think we remain open to all technologies. Our focus, obviously, is around thermal, hydro, wind, probably to a lesser extent, solar. We do have some investments in batteries, both in Western Australia and in Alberta. Hydrogen is interesting. I think the economics are very challenging right now. We have looked at opportunities with hydrogen fueled power, for example, but it is just very difficult to make that math work. But these are still evolving technologies. And I think that we have to remain kind of open to that and keep our eye on the ball, which we do as these technologies evolve. I think with SMRs, very interesting. I think that's going to take a lot of time. And I think we all believe that nuclear is going to play a very important role as it relates to power generation globally and obviously helping reduce emissions in providing reliable power. It's not a business that we're in today. We've got enough on our plate as it is, but we certainly kind of keep an eye on how that technology emerges as well. So again, I think the key takeaway here is we look at all these technologies, it will be an evolving landscape, but the economics have to work before we look to deploy capital in them.

Great. Next question coming from online is what upcoming recontracting opportunities are you seeing for your Far North assets and any others?

Sure. So with Far North, there's 4 assets there, total around 310 megawatts. All 4 were part of the MT2 contracting, which actually takes effect in May of this year and runs through 2031. The plan would be then to look to extend those contracts beyond 2031 for another 5-year period. . So again, when we looked at making that investment in Far North, we just stepped back and looked at the fundamentals. That's always key in making capital allocation decisions. And we looked at the fundamentals of Ontario and realize that gas is going to play a very important role here going forward. We really like these assets, complemented with our largest asset at Sarnia as well to say that when we think about going out too from 2026 to 2031 and the recontracting that would occur there, we feel very good at this point in time that we'll have an ability, not only with those Far North assets, in particular, the Kingston and the Iroquois Falls assets. Those are the 2 largest, Cochrane Casing, North Bay being smaller. We feel very confident that we'll have the ability to recontract those and similar to some of our other assets that we're seeing, whether it's Sarnia. We were part of the MT2 program here with our Wolfe Island assets just outside Kingston. So again, feeling very good right now in our ability to recontract those assets going forward.

I think maybe just to supplement that. I think we're also looking at Wyoming wind, as that PPA comes to an end, as being something that we could recontract. And Joel, maybe just chat a little bit about how we're seeing our merchant gas in Alberta potentially being available as a bridge, because I do see those coal to gas units as being sort of contracted in the context of a bridge for a data center opportunity.

Yes. That's a good point, John. So again, as we talked about earlier, and you saw in Chris' remarks, that our coal to gas units, which is roughly 2.6 gigawatts in Alberta, they're running at less than 20% capacity. And knowing the supply chain constraints that we're seeing today and actually seeing really no new incremental supply coming into the province through the end of the decade, other than what Chris mentioned, where we see some operate in certain assets outside of our portfolio inside our company, along with maybe an increase in intertie that our assets could serve as a bridge to a new generation. And so it's really important to note that, that we've got a lot of optionality there with our assets. We are actively working with the AESO and the Alberta government to really demonstrate that as we think about Phase 2 of Alberta data centers and what can be done there because it's all about bringing your own power, their generation, if you will, which we fully agree with. But we think there's an opportunity to use these assets. And the benefit for the province there is these assets stay in service. They could serve a data center customer or customers, but at the same time, really ensure the reliability of the province, which is critical for the government to ensure that there is that reliability there. At the same time, it actually could reduce costs overall. So when you look at your power bill on any given day in Alberta, roughly 1/3 of it is for the electrons and the other 2/3 are really for the transmission. So if you can have more load in the province, you could actually lower that part of the invoice for our bill for customers. So it actually overall benefit, even though we might see rising power for the electrons, the rest of it actually comes down. So again, I think our assets in Alberta are a great bridging opportunity to new generation, next decade.

Final call for questions in the room. John Mould from TD.

I'd like to start with the Alberta data center levy. There were some second, I think it's fair to say around the changes that were made in the last couple of weeks. Just wondering how have those factored into your broader data center conversations? Do you think the changes are sufficient? Do you see the levy at all as a headwind to seeing some real final investment decisions in the province on data centers this year?

Yes. I'll start, and Nancy, you want to maybe add a few things, or John or Chris. I'd say to you that, first of all, we're dealing with our counterparties being CPPI and Brookfield, right? So we're the power provider to them. And it's really up to them to say, okay with the levy. That's all, I think, been taken under consideration. We can't speak for them. But this has been known for some time. And I think obviously, what we saw over the last few weeks that it got refined. Certainly, what we're seeing here is still Alberta is a very competitive jurisdiction as it relates to power supply for data centers. And we remain still very optimistic by it. And I think it provides clarity, which is good for our customers to understand what do those levies look like.

And maybe -- sorry, John, just to supplement that. Our discussions aren't just with CPPIB and Brookfield. As you can imagine, we're speaking to other parties too in terms of the future trajectory. The levy, I mean it'd be better not to have the levy, just being honest about that, but it doesn't seem to be a big determinant. You know what I mean, one way or the other in terms of interest, I would say, for people from an inbound perspective coming into the jurisdiction. That hasn't -- like it hasn't featured all that high in those kinds of conversations, I would say, so far.

Okay. Great. And maybe just clarity on the assumptions that have gone into the big EBITDA slide. Just curious what you can tell us about, a, carbon pricing, how that's considered? And I appreciate there's a lot up in the air on that right now. And then b, how you've considered the potential for Brookfield to convert its securities into an ownership in your hydro assets?

Yes. So as it relates to carbon, we certainly see carbon pricing is staying, and it's going to rise gradually there as part of our assumptions. What we've heard with the MOU is that we see an increase up to $130. The question will be at what pace that grows at. And well, I think we'll learn a lot more here they are not too distant future as it relates to the MOU between Alberta and the federal government around that. So we've made some assumptions around the carbon pricing staying. We're not being overly conservative in that. I think that the reality is that carbon pricing would stay. With the Brookfield conversion, that became exercisable on the first of January last year, and it's exercisable to the end of 2028. And recall, what this is for is they provided $750 million to TA back in 2019 for a conversion into our hydro assets in the province. There are certain other mechanisms in place where depending on where our share price is at, where they could flex up to ultimately get to the 49% threshold that they could get to. So if our shares are trading at $14 above, they can add an additional 10%, that would be a cash infusion to the company. Then if our shares are trading above $17, they could flex all the way up to 49%, depending on the trailing EBITDA over the last 3 years for the initial conversion of the $750 million. So our assumptions right now is that it's probably sometime in '27, but '28 at the latest. We factor that into our model here that we haven't factored in the flex up, but just the initial conversion of the $750 million. The dialogue with Brookfield is excellent. We have 2 nominees in the Board of our directors, which are fantastic. And so a really good relationship there. I think they still remain very interested in those hydro assets, but it's really going to be up to them as to when they want to convert, knowing that, that option expires at the end of 2028, so they might wait.

And John, just as you recall, the carrying costs of the debt and the preps that we have right now is broadly equivalent to what their ownership interest in the EBITDA would be. So it was broadly neutral on a free cash flow basis.

Our final question comes from online. How is your data center project with CPP Investments and Brookfield progressing? And does the strong progress underpin your confidence in your outlook?

Yes. The big accomplishment was the MOU being signed here that we announced earlier in the year, actually in connection with our Q4 and year-end 2025 results. And that was the culmination of a lot of work between ourselves and CPPI and Brookfield that really went back to probably the summer of 2025. This isn't your standard MOU. It's a very comprehensive document. A lot of the commercial terms have been landed on with the MOU. So we're very pleased with the progress thus far. Next step is really to get toward definitive agreements here throughout this year. But I would say, so far, we're very pleased to have CPPI and Brookfield. Again, 2 major players in this market that we feel very confident in and the fact that they would like to scale up to 1 gigawatt. The fact that they've selected our Keephills facility as their site and we're the power provider is fantastic. So really, the next steps here is just to really work towards the definitive agreements through this year. And as more unfolds, we'll be sure to share that with you because I know a lot of people are really asking us a lot. We can't say a lot at this point. It's confidential, obviously, but as more unfolds here, we'll be sure to share it with you.

I'll now turn it over to Stephanie for closing.

Thanks, Ben. That concludes our 2026 Investor Day. Thank you all very much for taking the time to be with us today. If you have any further questions, please feel free to reach out to the TransAlta Investor Relations team, and have a great day.