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. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. 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, VP 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 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 2, 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 towards reconciliation, I want to begin by acknowledging that TransAlta's head office, where we are today, is located in the traditional territories of the people of Treaty 7, which includes the Blackfoot group comprising the Siksika, the Piikani and the Kainai First Nation, 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 Metis 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 $890 million or $3.22 per share from record revenues of $3.4 billion. We had adjusted EBITDA of $1.63 billion, in line with our record results from last year and record net earnings to shareholders of $644 million, a $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 megawatts 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 megawatts of renewables to order. As for our remaining projects, we expect the 200-megawatt Horizon Hill and 300-megawatt White Rock Wind facilities, along with the Mt Keep 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 $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 added a net economic interest in 1.2 gigawatts of high-quality generating capacity to our fleet. The combination enables us to enhance execution with the 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 gigawatts 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. And 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 $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 $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 $150 million through our ongoing normal course issuer bid. With expected free cash flow of approximately $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 $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 gigawatts of new capacity to the company's fleet by investing approximately $3.5 billion to develop, construct or acquire new assets through to the end of 2028 and expand our development pipeline to 10 gigawatts in the same period, all with a focus on customer-centered renewable 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 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 decisions, including projects not currently shown as being in an advanced stage. We have been disciplined in advancing these projects focused on ensuring that they are appropriately derisked 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 outlook. In 2023, we expanded our development pipeline by 1.35 gigawatts or approximately 30%, with prospective projects in all three of our core markets. And with the advancement in our growth pipeline in the fourth quarter, we've exceeded our original 5-gigawatt 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 continue 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 $134 per megawatt hour, which was below the average price of $162 for 2022. Our hydro fleet in Alberta continued to outperform spot prices with an average realized price of $175 per megawatt hour, 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 $162 per megawatt hour, 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 $73 per megawatt hour, 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 $82 per megawatt hour, which was significantly below last year's fourth quarter price of $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 gigawatt hours at an average price of $92 per megawatt hour. Looking forward to 2024, we have approximately 8,100 gigawatt hours of Alberta gas generation hedged at an average price of $85 per megawatt hour and roughly 72% of our required natural gas volumes are hedged at an average price of $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 $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 $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 $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 $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. And finally, our Energy Marketing segment delivered adjusted EBITDA of $109 million, a decrease of $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 $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 $289 million of adjusted EBITDA and $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 in 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 $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 $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 $890 million, well within our revised guidance range of $850 million to $950 million. In 2023, our hydro assets generated $460 million of adjusted EBITDA, and we continue to see strength in the first quarter of 2024. Energy production and ancillary service volumes remained 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 were 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 $1.15 billion to $1.3 billion and free cash flow to be in the range of $450 million to $600 million or $1.46 to $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 $75 to $95 per megawatt hour. 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 contribution for the year from Kent Hills, Garden Plain, White Rock, Horizon Hill, Northern Goldfield Solar, and the Mount Keith transmission project. And finally, we expect continuing solid performance from the Energy Marketing segment with a midpoint gross margin expectation of $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 $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 $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 $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. And 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 megawatts 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 megawatts 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 $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 contractiveness 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. And 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, will you please open the call for questions from the analyst?

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. 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 are the considerations that went into the sort of vault messaging, which seems to prioritize buybacks relative to what you communicated at Investor Day in November?

Thank you for the question, Mark. Good morning. We continuously review our capital allocation strategy, considering the timing of growth and the needs of our balance sheet within the framework we have set. When we noticed our trading price drop below $10, it prompted us to focus more on allocating capital for share buybacks to support the price. This is very important to us, especially since we believe our stock is undervalued in the market.

Over the past five years, we have consistently repurchased our shares, spending between $50 million and $90 million. In 2023, our average purchase price was around $11. We have been active in the market and have previously mentioned that we would take advantage of opportunities when we find the share price unreasonable. Given the current stock price, we are signaling our intent to take action.

Understood. If the share price increases as a result of this or rises further, is there a point at which you would stop buying back shares, or should the market expect you to allocate close to the $150 million this year?

We have indicated to the market that currently, we are planning to significantly increase the amount of share buybacks compared to our usual practice. As Todd mentioned in his presentation, the average price for our share buybacks last year was just above $11 per share. Considering our current trading price, this level of capital allocation appears to be sensible as we plan to maintain it throughout the year.

I think consideration was the timing on growth, John.

And then just coming to the point, Todd, in terms of the $3.5 billion line in Investor Day, now you want to do sort of an enhanced buyback here. How do you pay for everything? Is it just a function of timing, update us 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 trying to deliver on the $3.5 billion CapEx plans?

Yeah. I would just say that your comment there around timing, it is somewhat a timing aspect of capital uses, which in 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've shown, 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 needs, 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 your 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, bigger picture. I know, John, you mentioned that DCF per share is roughly 70. But as you look at the outer years, I'm sure where the power prices can change. So in your opinion, does the logical buybacks hold true even when you're using a projection 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 it's absolutely. We've been positioning our portfolio, adding in contracted assets, building up our C&I business. We're not giving long-term projections here on free cash flow. But at $10 a share, I still see purchases being accretive to the shareholders.

I agree with Todd that this is something we would consider over time. As he mentioned, we've typically operated within the $50 million to $80 million range for buybacks. Over the past few years, we have repurchased nearly 30 million shares. This demonstrates our increased focus on share buybacks. We are elevating our expectations for the amount we will allocate to this initiative. Currently, I believe there is a great opportunity for us to proceed with buybacks.

Maybe just a follow-up on that. Your free cash flow guidance of $1.47 to $1.96, which by the way, I'd 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?

I missed the last part of that question, but the first half, you are correct. We have not included in the denominator or a change in share count in that free cash flow forecast.

To address the second part of your question, I believe I didn’t catch it entirely, Maurice. It would indeed be accretive to the free cash flow per share, which is a clear focus for us 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 to grow or to grow 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 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. And then depending on the risk profile of the project and our ability to derisk 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 is a sliding scale that's being applied. 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 dollar and their share buybacks, depending on where your share price is trading?

I'm sorry, you broke up there, Maurice, said I couldn't catch that. Todd?

New growth project.

It is part of the mix, Maurice, when we look at the allocation of capital.

Great. Thank you.

Your next question comes from the line of John Mould from TD Cowen. Your line is open.

Thanks. Good morning, everybody. Maybe just continuing 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 the second part, just on Alberta specifically, are you finding the renewable development from your perspective anyways, 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 were kind of 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 derisking the projects and getting them to a place where we're increasingly comfortable with both the cost and even the revenue side of where we could go through. Having more certainty regarding market evolution is very important to us and to our Board. We expect to gain some clarity on the Alberta market in the next 45 days, particularly regarding responses and direction on the renewables pause. This will help us understand the pathway for market evolution, which presents opportunities for our organization in light of existing market gaps. These are likely the most critical factors for us. 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 are very much tied to their investment decisions as we go forward. Kerry, I don't know if there's anything else to add to that?

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 CR, the discussion document that was released last Friday, the ITC hasn'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 #1 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 our 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 now? 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 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. We're 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 or 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, will it stand out?

My current expectation is we would look to start reducing our inventory volumes of those emission credits over the next three to five years.

I totally agree.

And the only thing I would add is that more to your holistic future carbon credit question, what we saw in the last Friday's discussion document was the introduction by the federal government is 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 carbon aspect, it will continue to be attractive in the short and midterm.

Okay. Thanks. That's helpful. And then maybe I'll just slide one last one on Heartland. Can you just provide any updates on the transaction timing and how the competition process is expected to unfold?

Yeah. 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 got great engagement, I would say, with the Bureau and our team engages with them regulatory and giving them the kind of information they need 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. So from a timing perspective, we remain 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. And 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?

When considering the possibility of the government establishing a company to ensure grid reliability, I view this as an unlikely situation that would arise only if there were significant concerns about market reliability. In our evaluation of investment choices and optimizing our fleet moving forward, we are not factoring this scenario into our short-term considerations. 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%, 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 approach and the thinking of the government, at least based on our discussions with Upstate.

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 limits 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?

Yes, the federal government has released a discussion paper regarding the CER. We are actively engaging with them as they work through this process. However, there is still a significant amount of caution involved. I wouldn't suggest that people see this as concrete proposals from the federal government regarding the future of the CER. How they will proceed remains uncertain. That said, based on what we've observed, the general direction seems positive for us. The previous emergency provisions were not practical, but the new ones are much more effective, allowing provinces to manage whatever generation is necessary during emergencies to maintain reliability. I think in terms of unabated gas and to your point, moving 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 Temple will be in the details, right, in terms of where we are. And 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 and what they're proposing.

Okay. That's great, John. I appreciate your comments.

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.

Thanks everyone.