Good morning. My name is Ina, and I will be your conference operator today. At this time, I would like to welcome everyone to TransAlta Corporation Fourth Quarter and Full Year 2023 Results Conference Call. Online participants are placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star then 1 on your telephone keypad. If you would like to withdraw your question, please press star followed by two. Thank you. Ms. Valentini, you may begin your conference. Great. Thank you, Ina. Good morning, everyone, and welcome to TransAlta's Fourth Quarter and Full Year 2023 Conference call. With me today are John Kousinioris, President and Chief Executive Officer, Todd Stack, EVP Finance and Chief Financial Officer, and Kerry O'Reilly Wilks, EVP Growth and Energy Marketing. Today's call is being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our website. A replay of the call will be available later today, and the transcript will also be posted shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two, detailed further in our MD&A and incorporated in full for the purposes of today's call. All amounts referenced during the call are in Canadian currency unless otherwise noted. The non-IFRS terminology used, including Adjusted EBITDA, Funds from Operations, and Free Cash Flow, are reconciled in the MD&A for your reference. On today's call, John and Todd will provide an overview of the annual and quarterly results. After these remarks, we will open the call for questions. With that, let me turn the call over to John. Thank you, Chiara. Good morning, everyone, and thank you for joining our Fourth Quarter and Full Year Results call for 2023. As part of our commitment toward reconciliation, I want to begin by acknowledging that TransAlta's head office, where we are today, is located in the traditional territories of the Peoples of Treaty 7, which include the Blackfoot Confederacy, comprising the Siksika, the Piikani, and the Kainai First Nations, the Tsuut'ina First Nation, and the Stoney Nakoda, including the Chiniki, Bearspaw, and Goodstoney First Nations. The City of Calgary is also home to the Métis Nation of Alberta, Districts 5 and 6. It was another exceptional year of performance for TransAlta, in which we increased our key financial guidance and targets twice. We generated free cash flow of CAD 890 million, or CAD 3.22 per share, from record revenues of CAD 3.4 billion. We had Adjusted EBITDA of CAD 1.63 billion, in line with our record results from last year, and record net earnings to shareholders of CAD 644 million, a CAD 640 million increase from 2022. We benefited from strong power prices, particularly during periods of market tightness, and the exceptional efforts of our optimization, energy marketing, and operations teams. Our integrated and diversified fleet continued to show its value by generating excellent results for the third year in a row. We achieved fleet availability of 88.8% across our facilities, which, when adjusted for the Kent Hills extended outage, actually resulted in an underlying performance of 92.8%. I'm pleased to also share that 2023 was a record year for safety performance. We operated without any lost-time injuries across our global operations and delivered a total recordable injury frequency rate of 0.3, an outstanding result that improved upon our previous best outcome ever of 0.39 last year. During the year, and more recently in the fourth quarter, we delivered on a number of key priorities and strategic initiatives. First, our growth team advanced 678 MW of construction projects. We completed construction and reached commercial operation of our Garden Plain wind facility in Alberta and the Northern Goldfields combined solar and battery storage facilities in Australia, representing an addition of 178 MW of renewables to our fleet. As for our remaining projects, we expect the 200 MW Horizon Hill and 300 MW White Rock wind facilities, along with the Mount Keith transmission expansion, to achieve commercial operation in March 2024. A portion of the White Rock wind facilities reached COD earlier this year. Together, these facilities, along with the fully rehabilitated Kent Hills facility, will contribute over CAD 175 million in Adjusted EBITDA annually. Second, we advanced two key strategic initiatives with the acquisition of TransAlta Renewables and Heartland Generation. The acquisition of TransAlta Renewables represented an important milestone for our company. It allowed us to simplify and unify our corporate and capital structure and add a net economic interest in 1.2 GW of high-quality generating capacity to our fleet. The combination enables us to enhance execution with a simplified and unified strategy, which positions us well for future success. We also entered into an agreement to acquire Heartland Generation, which has approximately 1.8 GW of contracted and peaking generation in Alberta and British Columbia. The regulatory approval process for the transaction is currently underway, and once approved, Heartland will add flexible and complementary assets to our Alberta portfolio, further diversifying our generation capabilities in that market. Third, we continue to advance our customer relationships. In the fourth quarter, we entered into a joint development agreement with Hancock Prospecting to define, develop, and operate clean energy solutions in Australia. Finally, starting in April, our shareholders will receive a 9% increase to their common share dividend, representing our fifth consecutive annual increase. We also returned CAD 87 million to our shareholders in 2023 through share repurchases. With another quarter of strong cash flow, we continue to maintain a strong balance sheet with over CAD 1.7 billion in liquidity and are well positioned to deliver on our priorities. It's my view that the repositioning of our company and our strong free cash flow results over the past few years and our expectations for 2024 are not being reflected appropriately in the current trading price of our common shares. As a result, we announced an enhanced common share repurchase program for 2024 of up to CAD 150 million to our ongoing normal course issuer bid program. With expected free cash flow of approximately CAD 1.70 per share for 2024, we're trading at an implied free cash flow yield of about 20%, which allows share repurchases to deliver great value to our shareholders. This, together with our increased common share dividend of CAD 0.24 per share, represents a return of up to approximately 40% of the midpoint of our 2024 free cash flow guidance to our shareholders. Given the current environment, we believe this course of action is an appropriate and balanced use of our capital while still permitting us to pursue growth opportunities with appropriate returns and maintain our balance sheet strength and resilience. Over the longer term, we see significant opportunities for the company as the world increasingly electrifies to meet its growth and climate change goals. We continue to view investments in contracted clean energy assets as being in the best interest of the company and have articulated our Clean Electricity Growth Plan to 2028. As you know, the company is targeting to add up to 1.75 GW of new capacity to the company's fleet by investing approximately CAD 3.5 billion to develop, construct, or acquire new assets through to the end of 2028, and expand our development pipeline to 10 GW in the same period, all with a focus on customer-centered renewables storage. We're also focused on the selective expansion of flexible generation and reliability assets where our operating and optimization expertise can add value. As we execute our plan to 2028, we expect that approximately 70% of our Adjusted EBITDA will come to be sourced from clean generation as we increase the size of renewables in our fleet, significantly higher than the approximately 40% that we have today. And as we make the shift, TransAlta will be greener, more contracted, and more diversified. In the meantime, we continue to progress a number of projects towards final investment decision, including projects not currently shown as being in advanced stage. We have been disciplined in advancing these projects, focused on ensuring that they're appropriately de-risked and construction-ready, with appropriate risk-adjusted returns given the environment in which we have found ourselves. Long-term shareholder value creation will ultimately drive our capital allocation decisions. If returns are insufficient, we'll continue to enhance value through dividends and share repurchases and by enhancing the strength of our balance sheet. We're positioned to succeed over the balance of the decade and beyond, with considerable optionality in our generating base and growth pipeline, coupled with our balance sheet strength and strong financial outlooks. In 2023, we expanded our development pipeline by 1.35 GW, or approximately 30%, with prospective projects in all three of our core markets. With the advancement in our growth pipeline in the fourth quarter, we've exceeded our original 5-GW development pipeline target two years in advance. Finally, our commitment to decarbonization remains unchanged, and the addition of the Heartland portfolio will continue to be aligned with our longer-term emissions reductions commitment given Heartland's considerable transition efforts. We continue to remain committed to our decarbonization targets and will achieve a 100% mix of renewables and low-emitting natural gas by 2025 and net zero by 2045. I'll now pass it over to Todd to go through our segment results. Thank you, John, and good morning, everyone. I'll start my comments with a discussion on our Alberta portfolio and how it performed over the full year and fourth quarter of 2023. For the full year, we continued to realize high average merchant power pricing for energy and ancillary services across the merchant fleet in Alberta, and we were able to optimize our capacity across all fuel types in our portfolio. The spot price for the year averaged CAD 134 /MWh, which was below the average price of CAD 162 for 2022. Our hydro fleet in Alberta continued to outperform spot prices with an average realized price of CAD 175 /MWh, an exceptional 31% premium above spot price. Our gas fleet in Alberta also outperformed and exceeded our expectations, operating with strong availability and capturing peak pricing throughout the year of CAD 162 /MWh, which was 22% above the spot price. In the year, the gas fleet in Alberta also benefited from higher production levels during peak pricing, as well as higher power price hedges, which partially offset the impact of lower Alberta spot pricing and increased carbon compliance costs. Our merchant wind fleet realized an average price of CAD 73/ MWh, which was in line with our expectations. Our full year's results were impacted by warm weather during the fourth quarter of 2023, which impacted overall demand in the province and resulted in lower power prices than we were expecting relative to our revised guidance ranges. Weather conditions for the fourth quarter were very mild compared to the fourth quarter of 2022, which had periods of extreme cold weather. In the fourth quarter of 2023, the spot price averaged CAD 82/ MWh, which was significantly below last year's fourth quarter price of CAD 214. Our hedging program was able to partially mitigate the impact of lower power prices experienced in the fourth quarter. We had hedges on both our gas and hydro fleets, with hedged volumes for the quarter of 1,700 GWh at an average price of CAD 92 /MWh. Looking forward to 2024, we have approximately 8,100 GWh of Alberta gas generation hedged at an average price of CAD 85 /MWh, and roughly 72% of our required natural gas volumes are hedged at an average price of CAD 2.76 per GJ. Looking at our full year corporate results, we had another exceptional year, which was led by our hydro, gas, and energy transition segments. The gas segment delivered Adjusted EBITDA of CAD 801 million, a 27% increase over 2022. Strong performance was driven by higher realized prices from our hedging activities, lower natural gas commodity costs, and higher production. Adjusted EBITDA at hydro delivered an exceptional contribution of CAD 459 million. The modest decline compared to 2022 results was due to lower ancillary services volume, lower realized prices, and lower-than-average water resources. These results were partially offset by realized gains from hedging and sales of environmental attributes. The energy transition segment delivered CAD 122 million of adjusted EBITDA, an increase of 42% year-over-year. Strong performance was driven by higher production due to higher availability at our Centralia facility and higher merchant sales volumes, partially offset by lower market prices. The wind and solar segment delivered EBITDA of CAD 257 million, a decrease of 17% year-over-year. Lower results were due to lower emission credit sales, lower power pricing in Alberta, and lower wind resource across the operating fleet, partially offset by the addition of our new assets. Finally, our energy marketing segment delivered Adjusted EBITDA of CAD 109 million, a decrease of CAD 74 million, primarily due to lower realized settled trades during the year in comparison to the prior year. Energy marketing results were at the top end of our revised full year guidance provided in the second quarter of 2023. As John mentioned, overall we delivered another strong year with CAD 1.63 billion of Adjusted EBITDA, consistent with our results from 2022. I'll shift now to our fourth quarter results. In the period, we generated CAD 289 million of Adjusted EBITDA and CAD 121 million of Free Cash Flow. Given the above-average weather conditions in Q4 that contributed to lower-than-expected power prices in Alberta, our financial results for the fourth quarter were below our expectations for the period and below our 2022 results. Let me remind you that our Q4 2022 results were extraordinary and driven by extreme weather and record power prices. As a result, year-over-year performance across all of our merchant assets was impacted by lower Alberta power prices. In addition to power price impacts on both energy and ancillary services, the hydro segment was further affected by a longer-than-planned outage at our Brazeau facility, and the wind and solar segment experienced lower wind resource in Eastern Canada and the U.S. Our gas fleet led performance in the quarter with EBITDA of CAD 141 million and was supported by our highly hedged position going into the quarter. The energy transition segment outperformed expectations, exceeding 2022's EBITDA by 37%, primarily due to higher production that resulted from lower unplanned outages at the Centralia facility. Energy marketing Adjusted EBITDA decreased by CAD 49 million, or 40%, compared to 2022, primarily due to lower realized settled trades during the fourth quarter in comparison to the prior period. As is the nature of this segment, trades are realized in our EBITDA results when they settle, with a portion of trades executed in 2023 settling and being realized over time in 2024 and 2025. Overall, 2023 was a strong year, delivering free cash flow of CAD 890 million, well within our revised guidance range of CAD 850 million-CAD 950 million. In 2023, our hydro assets generated CAD 460 million of Adjusted EBITDA, and we continue to see strength in the 1st quarter of 2024. Energy production and ancillary service volumes remain largely consistent on an annual basis. This provides a long-term predictability and a floor to cash flows that is unique to this asset class. While water resource and energy production in 2023 was below 2022, we remain confident in the fleet's ability to realize its long-term average production levels. Realized pricing in hydro continues to be strong, with a premium on spot electricity prices averaging roughly 26% over the last three years and with ancillary services earning an average of 50% of spot prices. Looking forward, we expect the segment to continue to receive a premium to spot pricing. I'd like to remind everyone of our 2024 guidance that we announced in Q4 last year. Looking at 2024, we continue to expect that our results will be impacted by the evolution of the Alberta merchant market and the completion and integration of the Heartland Generation acquisition. For 2024, we expect Adjusted EBITDA to be in the range of CAD 1.15 billion-CAD 1.3 billion, and Free Cash Flow to be in the range of CAD 450 million-CAD 600 million, or CAD 1.46-CAD 1.94 per share. As we've noted, a number of factors are impacting our expected results for 2024. First, we expect Alberta merchant power prices to decline to a range of CAD 75-CAD 95 /MWh. This outlook is based on our fundamental market forecast, which includes the impact of significant new gas-fired supply additions. Second, we are coming into the year with a relatively high hedge position. Hedges have been executed both financially and through our commercial and industrial business. Third, our outlook includes the incremental Adjusted EBITDA contributions for the year from Kent Hills, Garden Plain, White Rock, Horizon Hill, Northern Goldfields Solar, and the Mount Keith Transmission Project. Finally, we expect continuing solid performance from the energy marketing segment, with a midpoint gross margin expectation of CAD 120 million. Over the past three years, we've deployed a significant amount of capital towards our growth program. Since 2021, we've allocated over CAD 1.6 billion to our clean electricity growth plan, with a larger portion of our growth program being funded through our free cash flow. As John mentioned earlier, we are nearing the end of this construction phase, and while we will pursue our growth plan further, we will not grow simply for the sake of growth in order to meet targets. Long-term shareholder value will drive our capital allocation decisions, and as John noted, we consider our common shares to be significantly undervalued at current levels. Accordingly, we're adopting an enhanced common share repurchase program for 2024 of up to CAD 150 million, which is roughly double our historic purchase levels. We believe these repurchases will add value for our shareholders over the long term. At the midpoint of our guidance for 2024, we expect to generate CAD 525 million of free cash flow, which provides continued flexibility and the ability to take a balanced approach to capital allocation. We are well positioned to return capital to our shareholders while prudently pursuing growth opportunities and maintaining our balance sheet strength. With that, I'll turn the call back over to John. Thanks, Todd. As I look at our strategic priorities for 2024, we're focused on progressing the following key goals. First, improving leading and lagging safety performance while achieving strong fleet availability of 93.1%. Progressing the equivalent of 400 MW of additional clean energy projects across Canada, the United States, and Australia. Achieving COD on the White Rock Wind, Horizon Hill Wind, and Mount Keith Transmission Projects next month. Continuing the expansion of our development pipeline by adding 1,500 MW of development sites with a focus on renewables and storage. Closing and integrating Heartland Generation. Achieving EBITDA and free cash flow within our guidance ranges. Proceeding with an enhanced common share repurchase program for 2024 of up to CAD 150 million through our ongoing normal course issuer bid program and advancing our ESG program. I'd like to close by highlighting what I think makes TransAlta a highly attractive investment and a great value opportunity. First, our cash flows are strong and underpinned by a high-quality and growing diversified portfolio. Our business is driven by our unique, reliable, and perpetual hydro portfolio, our contracted wind and solar portfolio, and our efficient gas portfolio, all of which are complemented by our world-class asset optimization and energy marketing capabilities. Both the acquisitions of TransAlta Renewables and Heartland Generation will further diversify and increase the contractedness of our cash flows, while Heartland's peaking assets will complement our Alberta strategy. Second, we're a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. We remain on track to achieve our ambitious CO2 emissions reduction target of 75% by 2026 from 2015 levels, and we also remain committed to Net Zero by 2045. We remind everyone that the Heartland acquisition will not affect either of these commitments. Third, as noted earlier, we have a diversified and growing development pipeline and a talented development team focused on realizing its value with appropriate returns. Fourth, our company has a sound financial foundation. Our balance sheet is strong, and we have ample liquidity to return cash flow to our shareholders through share repurchases, close the Heartland acquisition, and also pursue and deliver our clean electricity growth plan. Finally, we have our people. Our people are our greatest asset, and I want to thank all our employees and contractors for the outstanding work they have done to deliver another record year for TransAlta. Thank you, and I'll turn the call back over to Chiara. Thank you, John. Ina, would you please open the call for questions from the audience? Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the 1 on your telephone keypad. Should you wish to cancel your request, please press the star followed by the two. If you are using a speakerphone, please leave the handset before pressing any keys. One moment, please, for your first question. Your first question comes from the line of Mark Jarvi from CIBC Capital Markets. Please go ahead. Thanks. Good morning, everyone. A couple of questions on the share repurchases. Maybe just first, is it exclusively just a function of the share price, or what other considerations went into the sort of evolved messaging, which seems to prioritize buybacks relative to what you communicated in yesterday in November? Yeah, Mark. Good morning, and thanks for the question. Look, we review our capital allocation approach constantly. We look at kind of the timing of having the growth coming into the company and the needs of the balance sheet as we allocate it in the capital allocation framework that we've adopted. But when we kind of looked at where our trading price has gotten to at a level that was below CAD 10, that certainly became a catalyst for us focusing on allocating more capital to doing share buybacks, supporting the price, which is clearly important to us and important in a context of, at least from our own perspective, seeing it being so undervalued in the marketplace. Maybe I just add that over the last five years, we have pretty consistently bought back our shares, somewhere between CAD 50 million and CAD 90 million marks of shares. In 2023, our average purchase price was around that CAD 11. So we have been active in the market. We've said previously that we'd be opportunistic on it when we don't like where or we don't think the share price is trading at a reasonable price. And where the stock's trading today, clearly, we've sent the signal out there. Understood. And so then if the share price sort of rallies on the back of this or drifts higher, is there a level where you sort of turn it off, or is the message to the market that likely you'll be somewhere close to the CAD 150 million allocation this year? I mean, we basically came out and kind of signaled to the market that where we stand today, we're looking at essentially, I think, Todd, you mentioned it in your presentation, doubling the amount of share buybacks that we would normally do. I think, to Todd's point, the average price that we did share buybacks in last year was just a little bit over CAD 11 a share. And given where we're trading today, that kind of allocation of capital seems to be a reasonable amount when we look at it being kind of carried through over the course of the year. I think the other consideration was the timing of our spend on growth, John. Yep. Just where we're looking at our growth program for 2023, we're coming to the end of a construction phase. We're looking at a number of other projects to move forward in 2024, but I think the capital requirements in 2024 would be relatively light for those new projects. Then just coming to that point, Todd, in terms of the CAD 3.5 billion you outlined in yesterday, now you want to do sort of an enhanced buyback here. How do you pay for everything? Is it just a function of timing updated views in terms of financing options on the growth platform? How do you sort of dovetail in this enhanced buyback activity, at least in the short term, while still sort of trying to deliver on the CAD 3.5 billion CapEx plans? Yeah, I would just say that your comment there around timing, it is somewhat a timing aspect of capital usage within 2024. As we move into 2025, we'll again reevaluate the balance between growth and share buybacks. But I would say, Mark, our clean electricity growth plan is a five-year plan in terms of executing the actual growth. The company has considerable cash flow generation capability over the course of that time period. And as we showed, I think, folks in our investor day that we're very confident in our ability to actually fund the growth. We're more focused on making sure we get the right projects and the right returns, to be honest, more than worried about the cash flow that we're generating to be able to meet the need, certainly over the next period of time. So I think we feel good in our ability to take a balanced approach here. Okay. I'll leave it there for now. Thanks for the time. Thanks very much, Mark. Thank you. And your next question comes from the line of Maurice Choy from RBC Capital Markets. Your line is open. Thanks, and good morning. Maybe sticking with the share buybacks. Maybe bigger picture. I know, John, you mentioned that DCF per share is roughly CAD 1.70. But as you look at the out years, I'm sure Alberta power prices can change. So in your opinion, does the logic of buybacks hold true even when you're using projections for DCF per share beyond 2024? Is it sound to have such a program for not just one year, but for years to come? Yeah, look, I would say absolutely. We've been positioning our portfolio, adding in contracted assets, building up our CNI business. We're not giving long-term projections here on free cash flow, but at CAD 10 a share, I still see purchases being accretive to the shareholders. Yeah, I would agree with Todd, Maurice. Good morning, by the way. In terms of his response, it certainly is something that we would be looking at over time. As Todd pointed out, we've traditionally done in that CAD 50 million-CAD 80 million range. I think, Todd, over the course of the last number of years, we've bought back almost 30 million shares, I think, is the actual number. So it's certainly a greater focus. We're doubling up kind of the expectations of what we're going to be deploying in terms of share buybacks. But right now, I think there's a great opportunity for us to do that. Maybe just a follow-up on that. Your free cash flow guidance of CAD 1.47-CAD 1.96, which, by the way, I like to focus on per share metrics here. Can you confirm that there's no buybacks in there? And given your comments, Todd, just now about where the shares are trading, any buybacks are immediately accretive to this guidance? Just the last half of that question, but the first half, you are correct. We have not included in the denominator a change in share count in that Free Cash Flow forecast. So, to answer the second part of your question, because I think I did hear it, Maurice, it would be accretive, correct, to the number, to the free cash flow per share number, which is something that we're focused on, clearly, as an organization. Great. Thank you. And maybe just to finish off, John, you mentioned that you continue to view investments in contracted clean energy assets as being the best interest of the company. And Todd, I think you also mentioned that you want growth for growth's sake. As you look at the projects that make up your clean electricity growth plans, can you paint a picture as to what the average free cash flow yield is? And broadly speaking, in a very near term, what projects are at the higher end of that free cash flow yield range? Maurice, we tend to look at it as a portfolio. So there would be projects that we would be developing that would have returns that would be lower on the sliding scale. We've talked to people about this when we look at it from the context of the returns on a risk-adjusted basis. So if you have a renewables project in Australia, for example, where we get a full return of it on capital during the contracted period, having a high single-digit return for a project like that may make sense. If you're looking at a project, for example, like Water Charger, which would be a merchant battery project where we're relying on our optimization team here in Alberta to extract value from that facility through the skill set that they have, we would be looking at considerably higher returns, well into the double-digit returns for a project like that. Then depending on the risk profile of the project and our ability to de-risk it as we go forward, everything from the supply chain to the contracting approach that we're taking for the development, it would lie in between. So it isn't a bright line, singular kind of approach that's being done. It isn't sort of a point number that's being done. We tend to look at, on a project-by-project basis, what are the attributes of the project, and what is the skill set that we can bring to it from a value proposition going forward? So it really does vary. I guess it's fair to say that any dollar that goes into growth projects, that dollar will compete with a dollar into share buybacks, depending where your share price is trading. I'm sorry, you broke up there, Maurice, and I couldn't quite catch that, Todd. New growth projects. No, I'm just saying that. They do. It's part of the mix, Maurice, when we look at the allocation of capital. Yep. Great. Thank you. Once again, if you would like to ask a question, simply press a star followed by the number one on your telephone keypad. Your next question comes from the line of John Mould from TD Cowen. Your line is open. Thanks. Good morning, everybody. Maybe just continuing on the development theme, I'm just wondering if you can give a little more color on what you're seeing as the greatest gating factor right now for finalizing development projects. Is it financing costs, equipment, project-specific challenges like Interconnect? And second part, just on Alberta specifically, are you finding that renewable development, from your perspective anyways in Alberta, and I'm speaking about within your company, just to be clear, is it all constrained until you get clarity on whatever power market changes might be getting announced next month or in the months ahead? Yeah, good morning, John. You kind of answered the first part of your question, I think, by reference to the second part of the question. As you might recall, when we talked about kind of our growth pipeline and where it is, we went through a period where the projects that we had had a bit more of a U.S. flavor with a little bit of Australia thrown in. Right now, in terms of the relative readiness of projects to go forward, they have a bit more of an Alberta and Australia flavor going forward. So when we're looking at them from a gating perspective, we've done a ton of work in terms of de-risking the projects and getting them to a place where we're increasingly comfortable with both the costs and even the revenue side of where we could go through. But I think having a bit more certainty from a market evolution perspective going forward is something that certainly is important to us. It's important to our board. And we're close to getting some of that certainty or clarity from an Alberta market perspective over the course of the next probably 45 days or so as we begin to get some responses and direction on the renewables pause and what's going to come out of that and kind of the pathways from a market evolution perspective in many respects, which create opportunities for us as an organization given some of the gaps that are in the market. So I'd say those are probably the critical pieces. And then just touching on Australia briefly, and I'll see if Kerry wants to add anything as well. She's on the call today. We're in many respects tied to the timing and the process that our customers have as they go through their own process. And when they look at their capital needs and the evolution of the markets that are in that part of the world, we work with them, but we very much are tied to their investment decisions as we go forward. Kerry, I don't know, is there anything else to add to that, or? I think the only thing I would add is just to underscore the impact of regulatory uncertainty. You would have read in our release that we monetized 83% of the PTCs relating to Oklahoma. And when we look at the CER, the discussion document that was released last Friday, the ITCs haven't been fully enacted; it really does impact our ability to attract investment to our Canadian jurisdictions as well as to Alberta. So I think I'd probably choose that as my number one challenge that we're faced with right now. I mean, stability is really critical, right, to making sort of the long-term bets that we make when we make investments, John. So that's probably driver number one over some of the other items that you itemized in your question. Okay. No, that's all fair points on stability. And maybe touching on something related, just on the carbon credit front, it looks like you did increase sales of carbon credits from your hydro portfolio in the fourth quarter. Can you maybe just provide us an update on how you're thinking about the carbon credit portfolio more broadly and the pace at which you're thinking about monetizing that? Sure. And I can start, and then Todd and Kerry can jump in as well. Look, it's quite a valuable asset that we have in the organization, and it grows. So we've got a pretty capable team that manages it very, very actively over time. And the kind of decisions that we make around it is, does it make sense to take it in-year? Does it make sense to kind of defer it for a year? We are seeing carbon pricing increasing. We are seeing the value of the credits over time increase, even though the discount, as against the face value, if I can call it that, sometimes increases over time. They are increasing. And then the trick is, at which point, because of the proliferation of renewables, does the value begin to wane, if I can put it that way, from a carbon credit perspective? So it's a calculus of trying to, frankly, monetize or extract the greatest amount of value that we can from the portfolio of credits that we have, while also looking at sheltering the carbon obligations that the company has as it goes forward and whether we can actually use some of those credits to shape products for customers that meet their needs going forward. So it isn't an easy answer, but at least in the near term, when I think of the next year, next two years, there is significant value in kind of picking the right timing, so to speak, in terms of when we monetize. I don't know, Todd or Kerry, whether there's any doubt. My current expectation is we would look to start reducing our inventory volumes of those emission credits over the next three to five years. Totally agree. The only thing I would add is that more to your holistic future of carbon credit question, what we saw in the last Friday's discussion document was the introduction by the federal government of saying that they're not hard and fast in terms of emissions, that they're introducing an ability going forward to use offsets and credits against your emissions. So I would say in that front, carbon credits will continue to be attractive in the short and mid-term. Okay. Thanks. And that's helpful. And then maybe I'll just slide one last one in on Heartland. Can you just provide any updates on the transaction timing and how the competition process is expected to unfold? Yep. Happy to. So we had three major approvals that we required from a regulatory perspective. The first one was from the British Columbia Utilities Commission. We've actually secured that approval. The second one is from the FERC in the United States, and we're awaiting that, I would say, imminently as we go forward. The final one and the most significant one would be how the review that's being undertaken by the Competition Bureau. We are progressing with that. We've had great engagement, I would say, with the bureau. Our team engages with them regulatory and giving them the kind of information they need to be able to properly assess sort of the competitive impacts of the proposed merger in real time, given the evolution that we're expecting to see in the marketplace in the province of Alberta. From a timing perspective, we remain sort of optimistic that we'll be able to get through that process in an appropriate way and be in a position to close the transaction kind of in the latter part of the first half of the year. That would be about where we are right now, John. Okay. Great. Those are my questions. I'll get back in the queue. Thank you. Thank you. Your next question comes from the line of Patrick Kenny from National Bank Financial. Your line is open. Thank you. Good morning. Maybe just sticking with the regulatory frontier and specifically the Alberta government potentially creating this generator of last resort entity. How are you guys thinking about protecting the economics for your Alberta portfolio, including the Heartland Generation assets here, which I know you see a lot of value in the peaking capacity there? Just wondering how we should be thinking about the risk of a new government-based participant in the market? Good morning, Patrick. Look, when we think of the government potentially stepping in to create a company that would either acquire or create generation to ensure the reliability of the grid, I think that is very much an in extremis, I would say, kind of scenario, a scenario in which there is a genuine concern over the reliability of the marketplace. So it's not, I would say, when we look at our investment decisions and when we look at sort of the optimization of our fleet going forward, it doesn't candidly feature in our assessment kind of in the near term when we look at things going forward. I think there is a genuine concern on the part of the government of Alberta that if the CER is enacted in a way and is maintained in a way that results in the reliability of the grid in Alberta being challenged, then they kind of see themselves as having an obligation to ensure that the grid is reliable. And we saw the consequences that could arise just last month when we had temperatures that were approaching minus 40 degrees Celsius, and we were on the edge in terms of maintaining the reliability of the grid. So it's really a last-ditch, at least our view would be that it's really that last-ditch insurance policy kind of approach in the thinking of the government, at least based on our discussions with them today. Okay. Thanks for that. And you touched on the CER, John. Maybe just delving into that a little bit more and thinking about this potential shift towards emissions limit versus intensity performance standards. Curious your thoughts on how these changes might impact your outlook for optimizing generation or overall margins for your fleet going forward as well? Yeah. So as you know, the federal government came up with kind of a thought paper, really, on the CER. We're obviously responding and engaging with them as they go through the process. I think a caution I would like to pull a thought piece for them. I don't know that folks should be viewing it as kind of tangible, accepted proposals from the federal government in terms of where they would evolve the CER. So I think there's still an open question as how they would proceed. But I would say, in respect of what we've seen, directionally, I think it's positive for where we are. I think, one, the emergency provisions that they had before, I think were unworkable. They're much, much better now in terms of letting the province touch on whatever generation it needs in a circumstance when there is an emergency and they need to ensure reliability. I think in terms of unabated gas and, to your point, moving from a specific performance factor more to an envelope of emissions is the way I think of it. It's also positive. And I think our view, at least based on the work that we've done to date, would suggest that it provides more room, certainly for peakers, to be able to run to ensure, again, the reliability of the system going forward. So directionally, I would say helpful in terms of where we are, certainly in the context of the Heartland Generation transaction and our broader fleet. But, Patrick, the devil will be in the details, right, in terms of where we are. We still have a lingering concern that although the signaled flexibility is helpful, we may actually need a bit more to ensure that the grid remains reliable in the province of Alberta than what they're proposing. Okay. That's great, John. I appreciate your comments. Thank you. Okay. Well, thank you, everyone. That concludes our call for today. If you have any further questions, please don't hesitate to reach out to the TransAlta Investor Relations team. Thank you and have a great day. Thank you all.