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Presentation

Operator: Good morning. My name is Julie, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Fourth Quarter and Full Year 2022 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.

Chiara Valentini: Thank you, Julie. Good morning, everyone. And welcome to TransAlta’s fourth quarter and full year 2022 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, Legal, Commercial and External Affairs. 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 be posted shortly thereafter. All of the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide two, which is also detailed further in our MD&A and incorporated in full for the purpose of today’s call.

All amounts are referenced during the call are in Canadian currency unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA 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 results for 2022. After these remarks, we will open the call for questions. With that, let me turn the call over to John.

John Kousinioris: Thank you, Chiara. Good morning, everyone. And thank you for joining our fourth quarter and full year results call for 2022. 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 Niitsitapi; the People of the Treaty 7 region in Southern Alberta, which includes the Siksika, the Piikani, the Kainai, the Tsuut’ina and the Stoney-Nakoda First Nations, as well as home to the Métis Nation, Region 3. TransAlta had an exceptional 2022. During the year, we successfully navigated market challenges and achieved results that exceeded the top end of our updated guidance and expectations for the year.

We delivered $1.63 billion of adjusted EBITDA, a 27% increase over our 2021 results and free cash flow of $961 million or $3.55 per share, a 64% increase over 2021 results on a per share basis. It was a remarkable result for the company and our shareholders, where all fleets and businesses — with all fleets and business segments contributing to the results with strong performances. Availability was excellent across our facilities at 90%, compared to 86.6% in 2021. And thanks to the strong operational performance of our fleet, we were able to successfully supply generation when the market needed it most, benefiting from the strong power prices experienced in Alberta during the year, particularly during periods of market tightness. Our results demonstrate the value of our strategically diversified fleet in Alberta.

We continue to believe that we have the right fleet to effectively supply our customers and realize value for our shareholders. With our fast ramping hydro and our converted gas assets, we can provide cost-effective reliability when the market needs it. Something we are also incredibly proud of was our safety performance throughout the year. We operated without a single lost time injury during the year across our global operations and delivered a total recordable injury frequency across the entire fleet of 0.39, an outstanding result and our best outcome ever. We continue to maintain a strong financial position with over $2 billion in liquidity and are well positioned to deliver on our construction program. During the year, we secured a $400 million term facility with our banking syndicate and followed that up with a US$400 million senior green bond offering in November, the proceeds of which were used to repay our expiring US$$400 million unsecured notes.

Starting in January, our shareholders received a 10% increase to their common share dividend, raising it to an annualized $0.22 per share, representing our fourth consecutive annual increase. On top of that, we returned $54 million to shareholders over the year in the form of share buybacks, which we expect to continue. On the growth side, our development team secured 200 megawatts of renewables growth with the announcement of the Horizon Hill Wind project with Meta, as well as the Mount Keith Transmission expansion project in Western Australia with BHP. We have made excellent progress in advancing the rehabilitation of our Kent Hills facility. All towers are now fully disassembled, 21 foundations have been reported and our first tower has been fully reassembled.

Northern Goldfield Solar, Mount Keith Transmission, Garden Plain Wind, Horizon Hill Wind and White Rock Wind are all under construction and progressing well. Overall, we continue to make progress on increasing our EBITDA contribution from renewables assets with the addition of the Windrise and North Carolina solar facilities last year. EBITDA from our renewables and storage assets reached 54% in 2022, another step towards our 70% target by the end of 2025. And as we have advanced our clean electricity growth plan, our ESG ratings have improved with MSCI upgrading us from BBB to A and CDP upgrading us from B to A-. Today, we are pleased to announce that we have increased our decarbonization ambitions by adopting a net zero by 2045 target. In 2022, we were able to achieve carbon emissions reductions of an additional 2.3 million tons or 18% over 2021 levels.

This now brings our total emissions reductions to 68% or 22 million tons since 2015, a significant achievement. As a result of our emissions reductions journey, the carbon intensity for our converted natural gas units is approximately 57% lower than coal-fired generation and we have reduced our carbon compliance costs by 45% from $16 per megawatt hour in 2020 and 2021 to $9 per megawatt hour in 2022, notwithstanding the increase in carbon pricing during that period. The cash cost of carbon compliance for our company has fallen from $178 million in 2021 to $78 million in 2022. We are committed to maintaining a leadership position in climate change and contributing to a net zero future. Our growth strategy, which is focused on renewable and storage projects is in line with the Paris Agreement goal to limit global warming to 1.5 degree Celsius.

We made great strides in expanding our pipeline for growth in 2022. We added almost 2 gigawatts to our renewable development pipeline across Canada, the United States and Australia, providing great progress towards our longer term goal of having 5 gigawatts of projects in the pipeline. And we recently announced the acquisition of a 50% interest in a 320-megawatt Mountain Pumped Hydro Energy Storage project. This project provides us with a unique opportunity to supply 15 hours of long duration and zero emission energy storage capabilities for the Alberta market, helping to address the increasing intermittency that will be experienced with the growth of renewable generation in the province. Within our development pipeline, we currently have 374 megawatts of advanced stage generation and transmission projects that we are advancing towards final investment decisions in the upcoming quarters, representing additional growth of approximately $600 million.

These include our 180-megawatt WaterCharger battery storage project in Alberta, our 100-megawatt Tempest Wind project in Alberta and our 94-megawatt Southern Cross capacity and transmission expansion projects in Western Australia. Demand for renewables remains strong across all of our operating regions and we see opportunities for growth in our markets. For 2023, we are targeting to reach final investment decisions on 500 megawatts of growth. We also have a goal of adding another 1,500 megawatts of new sites to our pipeline during the year to ensure our growth in the longer term. As we look ahead to advance our development pipeline, we are seeing inflationary and supply pressures mounting with associated impacts on some of our development opportunities.

We have seen significant increases in turbine supply pricing and raw materials are experiencing significant price inflation. We estimate that current build costs for new assets have increased by almost 40% compared to projects that were initiated a year ago in the current environment. As a consequence, in December, we increased our capital target from $3 billion to $3.6 billion. However, despite the increases in capital costs for projects, we are seeing continued robust demand for renewable energy as corporate and government sustainability commitments remain firm. In tandem with the increase in capital costs, we have adjusted upwards our EBITDA target from $250 million to $315 million as we have seen PPA prices respond favorably to the supply and input cost pressures.

We expect returns to remain intact for our shareholders. We also expect the recent announcements regarding the Inflation Reduction Act in the U.S. and the Fall Economic Statement in Canada to be positive for our industry and TransAlta, and will continue to drive renewable energy demand in both regions. To-date, we have secured 800 megawatts of growth projects across Canada, the U.S. and Australia, representing 40% of our 2 gigawatt target by 2025. These projects will contribute approximately $145 million in contracted EBITDA once fully operational or approximately 47% of our five-year incremental annual EBITDA target of $315 million. As we carry out our growth focus, we are investing in our development team to broaden our capabilities as a developer-of-choice and to expand, advance and convert our development pipeline.

We remain confident in our ability to deliver on the remainder of our 2-gigawatt electricity growth plan. Looking forward to 2023, we announced our outlook in December, advising that we expect the company to generate adjusted EBITDA between $1.2 billion to $1.32 billion and free cash flow between $560 million to $660 million or $2.07 to $2.45 on a per share basis. Relative to 2022, we expect adjusted EBITDA and free cash flow to be impacted by three principal factors, including; first, strong merchant pricing levels continuing in Alberta, although at a lower target price range than 2022, based on our fundamental market forecast, we expect the Alberta spot price to be between $105 per megawatt hour and $135 per megawatt hour. This lower price expectation is driven by normalized weather expectations and the addition of new wind and solar supply, which will be partially offset by lower fuel costs due to favorable natural gas hedges.

Second, contributions from our new projects, including Garden Plain, White Rock, Horizon Hill, Northern Goldfield Solar and Mount Keith Transmission. And third, contributions from our rehabilitated wind turbines at our Kent Hills facilities beginning in the first half of 2023, with a full return to service in the second half of 2023. Performance from the Energy Marketing segment is difficult to predict and we have set our target around a midpoint gross margin expectation of $100 million. I will now turn it over to Todd to take us through our financial results for the quarter and year.

Todd Stack: Thank you, John, and good morning, everyone. I will kick off my comments with a discussion on the Alberta portfolio. In Alberta, our hydro, gas and wind facilities are dispatched as a portfolio in order to benefit from baseload and peaking energy sales. During the fourth quarter, our Alberta fleet had excellent availability at 94%, which underpinned our exceptional results. When we revised our guidance at the end of Q3, our balance of year outlook was based on power prices averaging roughly $140 per megawatt hour to $150 per megawatt hour. Ultimately, the spot price in the quarter settled significantly stronger at $214 and our merchant production was able to realize strong margins during this period. Looking at the full year 2022, the province experienced high electricity demand driven by periods of strong weather-driven demand, unplanned outages at several generators and outages on the transmission pipeline, which reduced overall supply capacity.

This resulted in strong pricing throughout the year, with the average pool price for 2022 settling at $162 per megawatt hour, stronger than the average price of $102 per megawatt hour in 2021. The ability of our hydro fleet to capture peak pricing was demonstrated throughout 2022, with realized energy prices of $197 per megawatt hour, which represented a 21% premium over the average spot price. Similarly, our gas fleet also captured peak pricing throughout the year, with realized merchant prices of $194 per megawatt hour, which also represents a 20% premium to the average spot price. Our merchant wind fleet realized an average price of $90 per megawatt hour and also benefited from the sale of renewable energy credits. Looking at 2023, we have approximately 6,800 gigawatt hours of Alberta gas generation hedged at an average price of $98 per megawatt hour and roughly 89% of our acquired natural gas volumes have been hedged at attractive prices.

Our hedging activities provide downside protection and support for the Alberta gas fleet, and we continue to retain a significant open position in order to realize higher pricing during times of peak market demand. Our financial results for the fourth quarter were exceptional. We generated over $500 million of adjusted EBITDA and over $300 million of free cash flow. Strong performance in the fourth quarter was led by the gas segment, which benefited from strong production and strong realized pricing in Alberta. The combined gas fleet produced adjusted EBITDA of $264 million, a two and half fold improvement over last year. Adjusted EBITDA from the hydro segment was $133 million, roughly double our results in 2021. And the wind and solar segment was up 21% quarter-over-quarter.

Energy Marketing continued its strong performance and in the quarter, delivered $63 million of EBITDA, which was significantly stronger than our target expectations. Looking at our full year results. Given the dynamics of our merchant portfolio, our performance was led by the hydro and gas fleets, where hydro delivered an overall increase of 64% in adjusted EBITDA year-over-year and the gas fleet delivered a 29% increase. The increase was driven by strong operations and our ability to supply during premium pricing in the Alberta market. Adjusted EBITDA from the wind and solar segment increased by 19% year-over-year, due to higher production from the full year contributions from our Windrise and North Carolina asset additions, and higher spot prices realized in Alberta.

Adjusted EBITDA from the Energy Transition segment decreased by $47 million year-over-year due to the announced retirements of Keephills Unit 1 and Sundance Unit 4. This was partially offset by strong performance of our Centralia facility, which improved by $30 million or 41% compared to last year. Our Energy Marketing segment also had another outstanding year, delivering $183 million in adjusted EBITDA, exceeding its historical average contribution. I would like to thank all of our employees for their performance in delivering one of the best years in TransAlta’s history. Slide 12 provides a historical snapshot of the hydro business. Since the expiry of the PPAs in 2020, shareholders have benefited materially from these assets, which generated over $300 million of EBITDA in 2021 and over $500 million in 2022.

Although, production varies quarterly, it remains consistent on an annual basis, providing long-term predictability. In addition, we continue to realize a premium on energy sales of roughly 20% over spot prices. Before I turn things back to John, I will turn to TransAlta Renewables. As you know, our operating wind and solar contracted assets, as well as the majority of our contracted gas assets are held within TransAlta Renewables and are fully consolidated in TransAlta’s results. Despite the ongoing suspension of operation at Kent Hills, R&W’s results for the year have demonstrated the resilience of the diversified fleet and delivered adjusted EBITDA within guidance expectations for 2022 at $487 million. This represents an increase of $24 million or 5% compared to 2021.

The increase was a result of the incremental production from the addition of Windrise and North Carolina Solar. In December, we shared our 2023 outlook with investors that highlights cash flow expectations with a payout ratio of approximately 100%. Adjusted EBITDA is expected to be between $495 million and $535 million. This represents a modest increase over 2022 levels due to the Goldfield Solar and Mount Keith Transmission projects coming online in 2022 and will also benefit from the return to service of Kent Hill’s 1 and 2 wind facilities in the second half of 2023. Cash available for distribution is expected to be between $230 million and $270 million, which is broadly in line with 2022 performance. The capital program for R&W in 2023 is fully funded and will be focused on the Kent Hills rehabilitation and the growth projects in Australia.

In addition to our financial outlook for 2023, our December update provided additional clarity on the strategic focus at TransAlta Renewables. R&W will be principally focused on the sustainment of its dividend in 2023 and beyond. Growth opportunities will focus on organic expansions of our existing assets, of which we have identified over 700 megawatts of opportunities across our three operating regions. With that, I will turn the call back over to John.

John Kousinioris: Thanks, Todd. As I look at our strategic priorities for 2023, our primary goal is to continue delivering clean power solutions to and be the supplier of choice for customers that are focused on sustainable growth and decarbonization. In 2023, we are focused on progressing the following key goals; reaching final investment decisions on the equivalent of 500 megawatts of additional clean energy projects across Canada, the United States and Australia, and delivering $75 million to $100 million in incremental EBITDA; achieving COD on the Garden Plain Wind, Northern Goldfield Solar, White Rock Wind, Horizon Hill Wind and Mount Keith Transmission projects; expanding our development pipeline by adding 1,500 megawatts of development sites with a focus on renewables and storage; completing the rehabilitation of Kent Hills Wind; advancing a new technology roadmap that aligns with our clean electricity growth plan; advancing the long-term contractiveness of our Alberta Electricity portfolio; delivering permanent financing for our growth projects; achieving EBITDA and free cash flow within our guidance ranges; and advancing our ESG objectives, which include furthering reclamation work at High Vale and Centralia; providing indigenous cultural awareness training to all our U.S. and Australian employees; and achieving at least 40% female employees by 2030.

I’d like to close by highlighting what I think makes TransAlta a highly attractive investment and a great value opportunity. We are pursuing a path that will reposition the company towards contracted renewable generation, minimize our exposure to regulatory and carbon risk, and diversify our merchant position in Alberta. We laid out a plan with a clear focus for capitalizing on cash flow generation from our unique legacy fleet in both Alberta and at Centralia, and reinvesting those cash flows towards the expansion and diversification of our contracted renewables to drive shareholder value. I am pleased to say that the legacy facilities, together with our Energy Marketing business are performing well and positioning us to effectively fund our transition towards contracted renewables growth.

Second, we are a clean electricity leader with a focus on tangible greenhouse gas emissions reductions. We have reduced our carbon emissions by 68% and are on track to achieve a greenhouse gas emissions reduction target of 75% by 2026 from 2015 levels. Our Board and management have also committed to a net zero by 2045 target for our global operations. Third, we have an extensive and diversified set of growth opportunities with TransAlta Renewables as our primary growth vehicle. And fourth, our company has a sound financial foundation. Our balance sheet is strong and we have ample liquidity to pursue our growth. Finally, our people. Our people are our greatest asset and I want to thank all our employees and contractors for the work that they have done to deliver our exceptional results this year.

Our strategy is on track and delivering consistent with our expectations, our vision of being a customer-centered leader in clean electricity committed to a sustainable future remains firm. TransAlta has had an exciting time in its evolution and we are well positioned for the future as a leader in low cost, reliable and clean electricity generation focused on serving and meeting the needs of our customers. Thank you and I will turn the call back over to Chiara.

Chiara Valentini: Thank you, John. Julie, would you please open the call for questions from analysts and media.

Operator: Thank you. Your first question comes from Mark Darby from CIBC Capital Markets. Please go ahead.

Mark Darby: Hi. Thanks. Good morning. John, you talked about inflation and changes in power prices offset that. So that’s answer today in terms of contracting environment, how would you say that is? Is there sort of a bit of spread between developers and buyers of power? Is it on the same page? And I guess when you think about the 2025 targets, is that something where that to have contracts in hand and maybe CODs don’t really come until 2026 or just confidence on, I guess, the time line for getting to the element of income on EBITDA?

John Kousinioris: Yeah. Good morning, Mark, and thanks for the question. I think I maybe misspoke during the presentation. I think at one point, I said that, one of our — having TransAlta Renewables is our primary growth vehicle that actually isn’t correct. It is TransAlta. In fact, that’s the primary growth vehicle and I think we made that clear in December — in our press release that we did in December. In terms of getting back to your question, look, we have seen inflationary pressures creep into sort of the new projects that we are developing. We do think that our PPA counterparties, those individuals that we are speaking to really see that. They see it not just from us. I think they see it from all developers that in the marketplace trying to provide projects to meet their needs and our sense is that those PPA prices are calibrating upwards to be able to make sure that those returns remain where they need to be.

In terms of TransAlta’s approach, we are going to remain very disciplined from a capital allocation perspective. We are not going to rush into doing growth for the sake of doing growth. We do have hurdle rate expectations and continue to do pretty robust risk assessments on the projects that go forward and it’s not just about the contracted period, it’s also about the merchant tail period once the contract rolls off. So that factors into the way that we are thinking about pricing and we will proceed with projects when we are comfortable that we are getting appropriate risk adjusted returns. In terms of growth, I think, our total approach on growth was actually landing transactions, getting to a determination to proceed with transactions in that 2-gigawatt pipeline by 2025.

We are confident that we will be able to do so. And I speak to our growth team, they have a pretty clear sense of which projects slot in where and at which timeframes in terms of the generation that we are looking to develop to be able to meet that target and we have got a cushion given the increase in the pipeline that we have going forward.

Mark Darby: Understood. And then my second question, just on the Alberta power price year-to-date. It’s been a little soft relative to the forward curve during the start of the year. So what’s your updated view there? Is that just milder weather, are you seeing any other sort of elements on the supply-demand side that might contribute to where settlement prices are below the forward curve at beginning of the year?

John Kousinioris: Yeah. I would say that, the prices so far this year haven’t been sort of wildly outside the ranges of what the fundamental forecasting was kind of expecting. I think for purposes of the guidance that we provided, we were looking at pricing in that $1.05 to $135 range over the course of the year. I think year-to-date pricing has been roughly in the $119 range and I think month-to-date has been, I think, about $109, $110, although we have had quite a bit of weather here in the last little bit, which is lifting prices here as we move to the balance of the month. I think the forward curve is in the mid-$130s right now, Mark. So that would be kind of at the upper end of what we thought things would go. I would say we have had some pretty benign weather so far at the front of the year in terms of compared to sort of a normalized price expectation.

So I think the weather has been less cold than we would expect. And as a result, I think we have seen quite a bit of renewables generation in the market, which tends to occur at kind of the temperatures that we have seen and the weather conditions that we have seen in the year-to-date. As you know, that can change pretty quickly and we are seeing that change right now. In terms of the balance of the year, I don’t think, in terms of supply additions into the marketplace, I think, what we have seen is, frankly, constructive to pricing in the year. I think some of the larger gas facilities that we were looking at potentially coming in earlier in the year are looking now to come in certainly later in the year and possibly even into the early part of next year.

So from a supply perspective, I think that’s, I’d say, on balance, probably, more positive to seeing better pricing in the year than maybe our original base assumption was when we were looking at our guidance for the year.

Mark Darby: Okay. Thanks for the comments, John.

John Kousinioris: Thanks a lot, Mark.

Operator: Your next question comes from Maurice Choy from RBC Capital Markets. Please go ahead.

Maurice Choy: Thank you and good morning. I just want to start with buybacks, and obviously, you started — you stated in the past that you will consider opportunistically buying back your stock, particularly if the share price falls below your view of the intrinsic value. If I compare the capital you have allocated to buybacks in Q4, the transactions seem to be around the $12 to $13 range, which is quite similar to the earlier parts of 2022. So with the share price being where it is today, how do you view your buyback activity level in 2023?

John Kousinioris: So, good morning, Maurice. So I would — I think you are right in terms of kind of identifying the levels that we would typically be in the market buying back shares. I would say, given where the share price is trading today and given our view generally on where we think value is for the company, it would be low. So it would be the kind of circumstances we would be more active in the market and buying back shares. As you know, we have a pretty set view on how we allocate capital in the company and we have got that bucket of, I think, 35% to 50% that is oriented towards growth, debt repayment and returning capital to our shareholders through share buybacks. We do have a pretty significant growth program that’s in flight right now that we are making sure that we are allocating capital to appropriately there.

But for sure, we would look to being constructive in buying shares in the marketplace when we are seeing the shares trading kind of at lower levels.

Maurice Choy: Thanks. And if I could just finish with the R&W/TAC question and thanks for the clarity on the development pipelines in your slides. When I look at — when we exclude the projects under construction, it does seem like R&W’s pipeline is about 15% of TAC’s pipeline or a total pipeline combined. Maybe some thoughts on how these lines were drawn? And also, am I right to assume that if an asset sits on the TAC side and not on R&W side, that asset to still be dropped down to R&W?

John Kousinioris: Yeah. Maybe I will start with your last question first and then Todd and I can just talk about the allocation. I think, well, first of all, I think, Maurice, the broad percentage kind of allocation that you talked about is about right. I tend to think of it as sort of in that 17% to 20% would be the total that would be on the R&W side. I think it is the case that the projects that are on the TAC pipeline could, depending on the circumstances, be candidates for a drop down to TransAlta Renewables. So we haven’t hardwired that. So that would be done on an asset-by-asset basis in light of the circumstances that we see. I think on the R&W pipeline, those assets that have been articulated there as being very clearly for R&W.

You tend to be expansions of existing assets that are within the R&W family. So for example, when you think of the Canadian battery opportunity, just a simple one, that’s tied to Kent Hills, which is an R&W asset. Willow Creek is sort of a step-out growth from existing assets that they would have and the U.S. assets would fall into a similar vein. And then step outs in terms of our existing relationships in Australia would also naturally fall towards TransAlta Renewables, given the — given their investments that they have in that part of the world. Todd, I don’t know if you want to add any more color to that, but.

Todd Stack: I think you have covered it well, John. Yeah. I mean the — in particular, the nearest term projects are the Australian ones, which are currently the expansions of existing facilities under the existing contractual relationships. Those are the most advanced and the ones that we are keeping our eye on in the near-term here.

Maurice Choy: Thanks for the color.

John Kousinioris: Thanks, Maurice.

Operator: Your next question comes from Rob Hope from Scotiabank. Please go ahead.

Rob Hope: Good morning, everyone. I want to revisit your comments on capital allocation. I understand you want to save some dry powder for your development pipeline. But when we take a look at your $1.1 billion of cash on the balance sheet programs in flight, as well as the potential to sanction another $600 million of growth. You still have quite a lot of dry powder there. So when you take a look at where you want to put capital to work, could we see you do incremental returns to shareholders or is there a bias towards something else, whether that’s kind of more on the development side?

John Kousinioris: It — good morning, Rob. You are right when it comes to sort of the strength that we have in the balance sheet. We tend to when we look at our capital allocation, look to a view on what’s in sort of the best interest of our shareholders from a longer term perspective. So we are of the view that growth is the primary way. appropriately risk adjusted growth is the primary way that we can increase value for our shareholders. That really underpins our entire clean electricity growth plan. And the legacy business is generating strong cash flow right now and that is helping to drive the strength in that balance sheet and the allocation. As I said before, we do look at where the share price is trading at any given time and continue to lever in share buybacks as appropriate.

When it comes to sort of the way that we look at our dividend policy and that’s a Board issue, obviously. Again, we look at it from a long-term sustainability perspective and making sure that we are layering in that dividend sort of going forward. So I think maintaining a strong level of liquidity in a bit of an uncertain time that we are in right now and with the kind of growth that we expect to see going forward is prudent and also given kind of the evolution of the Alberta merchant market as well, making sure that we are strong from a financial perspective.

Todd Stack: Yeah. No. I’d just add that, look, that’s all correct. In our minds, I think, we are probably earmarking sort of that $50 million to $75 million number similar to what we have done in prior years. But we are planning and thinking about an Investor Day later in the year and we will have an opportunity to update you with our thoughts at that point in time.

Rob Hope: All right. That’s great. And then maybe a little bit more of a granular question. M&A kind of picked up in Q4, specifically at the gas and the hydro assets. Can you give some color what happened there, was that in part just an acceleration of work just given how much — just how strong pricing was?

Todd Stack: It was effectively a factor of that is the strong performance. It is a combination of different things, some of the incentive programs we have as some of the ongoing costs. So it’s basically triggered with the stronger performance, Robert.

John Kousinioris: I think also, Robert

Rob Hope: Okay.

John Kousinioris: as a line item, I would say, insurance has ticked up pretty significantly

Rob Hope: Yeah.

John Kousinioris: across the Board and that’s being reflected in the OM&A side, particularly on the hydro.

Todd Stack: That’s particularly in hydro.

John Kousinioris: Yeah.

Rob Hope: Was that just a Q4 item or is that — has been occurring all through 2022?

John Kousinioris: It’s been a gradual increase throughout the year, I would say.

Todd Stack: Yeah.

Rob Hope: Okay. Thank you.

John Kousinioris: Yeah.

Operator: Your next question comes from Patrick Kenny from National Bank. Please go ahead.

Patrick Kenny: Thank you. Good morning. Just back to the clean growth strategy and just wondering as you look back over the past year, given the resurgence in market demand for reliable natural gas-fired generation across multiple jurisdictions. I know you expect the inflationary pressures within your renewables backlog to be offset by higher PPAs. But just curious if you are having conversations with your Board with respect to shifting towards more of a balanced growth strategy between renewables and gas. Again, given the new geopolitical environment, as well as the extra cash that you have on the balance sheet?

John Kousinioris: Good morning, Patrick, and thanks for that. Our clean electricity growth plan, kind of the status quo plan that we have now that takes us out to 2025, continues to be the focus of the company and the primary direction that we are going in. I would say that the importance of our gas fleet and the role that it plays, for example, in Alberta and even in Southwestern Ontario, very critical and we are very much focused on what are the attributes of that fleet to be cost effective going forward and as flexible as possible given — just given the market dynamics that we see developing in both of those jurisdictions. In terms of incremental new, I think, gas build, we do consider it periodically. We aren’t seeing a ton in terms of it being contracted, getting us to a place where we are comfortable with the kind of cash flows that incremental natural gas generation build would provide.

Do we evaluate potentially adding some peaking gas, particularly from an Alberta perspective, the answer to that would be yes, for sure, expecting that to be more merchant in orientation. But in terms of sort of greenfield natural gas prices or natural gas projects, we see a bit of interest for that in Western Australia and sort of those remote kind of operating regions. But we aren’t seeing a ton of that certainly from a North American perspective.

Patrick Kenny: Okay. Got it. Thanks for that. And then on the new pumped hydro storage opportunity. Wondering if you can comment on what sort of hurdle rates you would need in order to proceed with the investment? Would it be in line with the 11.5 times build multiple on the base

John Kousinioris: Yeah.

Patrick Kenny: clean growth plan or would you be needing a higher return just to compensate for development risks and maybe you can walk us through what those key risks on execution might look like?

John Kousinioris: No. For sure. So I would say that Tent Mountain is a real early-stage opportunity, Patrick. So in terms of what are hurdle rates, so we are very excited about the opportunity. But it’s years away from coming to reality. In terms of what the hurdle rates would be, our preference would be that we would see that facility contracted in some way or have some kind of a revenue stream that provides at least a relatively predictable cash flow stream for that kind of asset, given the size of capital investment that would be required to bring it through. So I think the returns that we would be looking for would be in the context from a risk adjusted perspective on that profile. I don’t think that our company right now is viewing that kind of project as a merchant project just to address your question on returns.

In terms of some of the development elements associated with that, again, early days, just making sure that we are clear from a pricing perspective, what it would cost to get to the project to be executed, we have a sense of what that would be and there has been technical work done, but there is a bit more that we need to do to make sure that it’s there. And then kind of the age-old question, it seems increasingly important is transmission interconnection. It is in a relatively remote part of the province and the issue would be how much would it cost and what were the timeframes to be able to bring that power into the grid from an interconnected perspective in an efficient manner. So those are just trying to give you a bit of a flavor of the kinds of ways we are looking at it.

Patrick Kenny: Okay. That’s great color. Thanks, John. I will leave it there.

John Kousinioris: Thanks a lot, Patrick.

Operator: Your next question comes from John Mould from TD Securities. Please go ahead.

John Mould: Good morning, everyone. Maybe just starting with your 2023 objective of securing long-term contracts for the Alberta merchant fleet. How much of that fleet would you ideally like to contract and maybe what’s realistic? And what does the competitive environment look like for contracting those assets right now, given the pipeline of new build renewable power development projects out there in the province, including your own?

John Kousinioris: Yeah. Good morning, John. So right now — so what we focus on and when we think of the kinds of contracting that we are doing, I am going to separate kind of the contracting that we would do to kind of underpin new growth, greetfield growth from a PPA perspective and kind of just focus on the kind of recontracting that we are focusing on for our merchant fleet right now, which is really what the goal is directed towards. We are seeing some interest in having renewables from off-takers come in. I think the work that we have done with Lafarge, for example, to supply some of their operations from our existing wind fleet. On the gas side, which is an even bigger focus for us as we go forward. Our C&I business is an important component.

It has grown for us. So when we talk about our hedge levels, I would say, Todd, 40 — almost 50% of that is probably underpinned by our C&I business as we go forward as opposed to just hedging in the financial market. That tends to be in that three-year range. We have seen more recently a bit of an uptick in interest from customers in terms of making sure that they lock in power prices, given some of the just higher prices that we have experienced over the last little bit and our C&I team is looking at increasing that. We tend to focus on that, I would say, Todd, is kind of representing what the equivalent would be of our version of baseload generation from a thermal perspective and making sure that it’s contracted in an appropriate — at an appropriate level with a view to long-term generation over that period.

So, hopefully, that gives you a little bit of color.

Todd Stack: Yeah. Yeah. I would say it really is focused on the C&I business, because it is an attractive way for us to hedge out three years to five years. That really doesn’t exist in the financial markets to any magnitude. And as John mentioned, sort of thinking that 300 megawatts plus is a nice baseload level of fixed-price contract to have period.

John Mould: Okay. Great. Thanks for that. And then maybe just coming back to the R&W pipeline. There’s nothing in there for Ontario. You are qualified for Ontario’s first upcoming long-term RFP. Just given the slight outlook in the province, are there opportunities for adding storage, optimizing Sarnia or wind expansions at some of the sites within R&W’s portfolio or with any opportunities in that province really land beyond the 2026-ish, excuse me, time horizon that you are covering seemingly in that pipeline?

John Kousinioris: Yeah. We are, John, looking at potentially adding a bit of incremental generation in some of our existing gas facilities in Southwestern Ontario, particularly in areas where we think just given sort of power demand and the grid that they would be in demand. We aren’t at this point in time anyway is expecting to be sort of a major player in that period of time or sort of stepping out in any significant way some of the existing wind facilities, for example, that we have in the region, I think of Marlington or facilities or Wolfe Island, sorry, just outside of Kingston. I think those are pretty well built up. And so we are not seeing it as a big opportunity of runway for us going forward. And we recently did participate in one of the RFPs that we had in Ontario and it helped with some of our post-PPA contracting in Ontario at Marlington. So we will do it opportunistically, but we don’t have a ton of focus on that right now.

John Mould: Okay. Great. Thank you. I will leave it there.

John Kousinioris: Thanks, John.

Operator: Your next question comes from Ben Pham from BMO. Please go ahead.

Ben Pham: Hi. Good morning. Just a couple of questions on R&W. I am wondering — I know you got the backlog in the slide. But with R&W, just looking at the 8.5%, 100% payout, like, I mean, how do you — how does R&W even contemplate even making any sort of acquisitions or drop-downs of that cost of capital?

John Kousinioris: Yeah. Hey. Good morning, Ben. Look, I think, really two avenues that we are focused on, and clearly, as we mentioned, the Kent Hills remediation is fully funded. But on top of that, the company does still have some bit of cash in Canada. It also has access to some cash down in Australia from those operations. So there’s a little bit of cash remaining available. And on top of that, the company really has modest leverage. So there’s additional capacity on the leverage side that we can look to entertain. But it was one of our core — your comment is exactly driven around one of our core discussions internally about allocating growth and how do we do growth going forward. And it was clear that was TransAlta was sitting on larger cash balances and that would just naturally lead you to a more moderated growth profile down at TransAlta Renewables, and basically, you have to pick your focus areas of why you want to invest, and clearly, that’s in the Australian and the Alberta businesses.

Ben Pham: Okay. Got it. And I know maybe just another question on R&W. We have seen U.S. YieldCo launch a strategic review, because of a high yield. Is that something that the R&W Board and the team is considering or looking at?

John Kousinioris: Yeah. I don’t — and look, and Todd can speak to this. I don’t think there is any sense of doing a big sort of strategic review right now from a TransAlta Renewables perspective. I think we have talked about the convergence of the strategies of the two companies and the notion that in terms of the broader TransAlta Group, having an interest in simplifying our structure if we can. That has a number of elements to it. It requires — when we think about what that means going forward, clearly, that would need to be fair to TransAlta Renewables shareholders. It would need to be appropriate and make a lot of sense for our existing TransAlta Corporation shareholders, whatever we would do would need to make sure that we would or consider that it continue to permit us to grow and execute on our clean electricity growth plan, and obviously, maintain our credit rating.

So it’s an ongoing thing that we assess internally, I would say, rather than doing any kind of a public sort of strategic review.

Ben Pham: Okay. Got it. And then, John, maybe my last one as a follow-up. I mean you have had probably the best year, I have seen TAC put out forever for a long time and your stock sitting in languishing over the last year. How much do you think that’s attributed to how the R&W vehicle has moved? I mean is there something else to that you think is driving that disconnect?

John Kousinioris: Ben, I’d be speculating. I mean, I think, for sure, the way that TransAlta Renewables trades and how it all fits within the family has an impact on the company and how it trades. But I have to tell you, we are just focused on trying to execute our business plan. We are looking at making sure that we operate our facilities as best as we can. We are trying to be as disciplined as we possibly can from a capital allocation perspective and making sure that the projects that we are bringing on makes sense and achieve the metrics that we have set for them and create value for our shareholders. And our belief is, if we continue to execute well, that would be the key thing that, that value that we are creating will be reflected in the marketplace. So we, again, taking a long-term view.

Ben Pham: I got you. Okay. Okay. Thanks, John. Thanks, everybody.

John Kousinioris: Thanks a lot, Ben.

Operator: Your next question comes from Naji Baydoun from IA Capital Markets. Please go ahead.

Naji Baydoun: Hi. Good morning. Just wanted to start off with a brief update on Garden Plain. Still no sort of changes to the ownership structure there, no indications from Pembina?

John Kousinioris: Good morning, Naji. No indications from Pembina. We are getting close to getting that wind farm up and running. I think, Todd, by and large, we would think that we would be substantially there, I would say, by the end of the quarter, roughly speaking. So I think we are entering into that zone on when — on Pembina would consider whether it would be wanting to exercise its option to acquire its interest in the facility, but no — nothing more than that at this point.

Todd Stack: They haven’t given us indication of which way they are leaning at this point.

John Kousinioris: No. Not one way to the other.

Todd Stack: I just want to point out that, Garden Plain is connected to the grid and a number of turbines have been commissioned and generating in. So it’s up and running. It’s not finished yet. But it’s up and running and contributing. So we are happy to see that.

John Kousinioris: Yeah.

Naji Baydoun: Okay. Okay. That’s good color. Thanks. I just wanted to try to understand about the capital allocation. I mean amazing year, great free cash flow generation, 2022 and then 2023 as well, yet kind of the stock price is slowing the other direction. You get a bit of buybacks in Q4, but not much. I guess once permanent financing is completed for the existing projects, is that enough to maybe launch like a more meaningful share repurchase program, maybe even in SIB?

John Kousinioris: Yeah. I don’t want to — Naji, I wouldn’t speculate on what we would do in terms of whether we would do a substantial issuer bid or anything more. I can tell you, it is a constant discussion that we have in our management team, a concept discussion that we have with our Board of Directors every meeting that we have in terms of what an appropriate level of capital allocation would be. Again, we are focused on the long-term, but at the kind of trading prices that we have recently seen for the share price, I think, you can expect that we would be in the market being active from time to time buying back shares.

Naji Baydoun: Okay.

Todd Stack: Yeah. And just to point out, again, we — I think it was mentioned, we still have to finish the existing construction on the announced facilities and then we are targeting 500 megawatts of new growth, which would equate roughly to north of $1 billion of capital spend. So, look, that is our primary focus. So we are not, as John said, sort of entertained SIB at this point.

Naji Baydoun: Okay. Okay. Perhaps, I guess, more updates to as the year unfolds and we look forward to that Investor Day. Just maybe one last question on those aside these new projects. You have got Tempest and WaterCharger that kind of maybe takes you to 300 megawatts. Just any more color on kind of the remaining 200 megawatts could come from to get you to 500 for the year?

John Kousinioris: Yeah. We have — I think it’s just under 100 megawatts in Australia actually at Southern Cross that we are working with BHP to actually land as well. So when you look at the entire portfolio, I think, when you do the math, it’s just under 400 megawatts of late-stage projects that we have got in place and the team continues to work various other elements in our pipeline, including potentially other projects that you don’t see in our pipeline that could come forward. So we are feeling pretty confident of our ability to land 500 megawatts over the course of the year.

Naji Baydoun: Okay. Okay. So just to be clear, that 94 megawatt expansion, that’s a gas project, correct? So the 500 megawatts is not all renewable, it’s just total?

John Kousinioris: Yeah. That’s right.

Todd Stack: That’s fair.

John Kousinioris: Yes.

Naji Baydoun: Okay. Got it. Thanks for that clarification.

John Kousinioris: Thank you.

Operator: Your next question comes from Chris Varcoe from Calgary Herald. Please go ahead.

Chris Varcoe: Hi. It’s a question for John. John, we see natural gas prices across North America tumbled this year pretty sharply. But I am wondering what kind of impact do you see these lower gas prices heading up on your business and upon power prices in Alberta in 2023? And separately, do you view these lower prices as something that might be sustainable through the year or do you view this as just more of a temporary phenomenon?

John Kousinioris: Yeah. Good morning, Chris. In terms of natural gas prices, maybe I will try to answer the question this way. I mean, I think, having lower natural gas prices tends to help in terms of moderating kind of prices that you would see in the marketplace. I mean natural gas prices are still one of the most critical input costs in terms of pricing that goes on in the market. And as you know, last year, prices were high kind of had been almost in some places record levels of cost. We have seen prices come down, as you say, right now, we are in the mid-$2 range, I think, Todd, in terms of what we are expecting. And I think we see that as being relatively stable, certainly for this year into 2023 and even going into 2024.

And our company has largely procured its natural gas needs for the year at pricing that would be in that mid-$2 range, kind of in that $2.50 a range. I think more importantly, when you look at the province of Alberta, there continues to be, at least from our company’s perspective, a very real need to have natural gas-fired generation in the province. I mean you have cold days like today or super hot days, the renewables just can’t provide the level of security and reliability that we need for the grid. So we think from a long-term perspective, it continues to be a critical part of the menu that needs to be in the province. But I think we are in a bit of a period of more moderated gas pricing right now, kind of a stable period, I would say. But who knows?

I couldn’t — I probably would have said something similar at the beginning of 2022 and then the world turned upside down.

Chris Varcoe: Just changing gears, I wondered if you could lay out for me a time line and the next steps for your early-stage pumped hydro project, the Tent Mountain Renewable Energy Complex?

John Kousinioris: Oh! Great. So in terms of the next steps internally for us, it continues to be a considerable amount of due diligence, more technical work being done on making sure that we can in a very effective way, move water from the upper reservoir to the lower reservoir, up and down at an appropriate period of time, really pressure testing, the construction cost of that and the economics associated with that, thinking through regulatory requirements, thinking through interconnection to the grid, which is a critical component there, making sure that we deal with our stakeholders in an appropriate way to make sure that the development is appropriate and they have an ability to provide input into that before we get anywhere near to being able to bring it in a real meaningful way to our investment performance committee and our Board for assessment.

It remains years away, I would say, Chris, and one of the key things, I think, before we can begin actioning on it, not so much doing the diligence we need to develop it, but to actually bring it forward as a viable project would be visibility or a revenue stream. How confident are we that we are going to be able to get paid for developing a project like this. We think it’s exactly the kind of thing that the problems will need in the future. But we are not quite there, I don’t think, from a market construct perspective where the value of that would be, I think, fully recognized yet in the marketplace. I think we will get there, though.

Chris Varcoe: And just finally, how do you view it vis-à-vis the Brazeau project, and I guess, maybe can you update me on where that project now sits within the company?

John Kousinioris: Yeah. Brazeau is also a later-stage project, similar considerations, I would say, with Brazeau. I think we have a better sense of some of the technical requirements of Brazeau in the sense that we have been working on it for a longer period of time and periodically refresh the costs associated with developing that project. But it too needs to have some kind of line of sight or visibility to the revenue stream before we would be able to bring it forward. And again, we think it’s the kind of battery effectively that the province will need in the future. In some respects, the Montem site is our Tent Mountain site is even better than Brazeau. It’s 15 hours of storage, we think, right now. Brazeau might be a little bit less than that and we really like the high differential between the upper reservoir and the lower reservoir.

Also is more bite-size capital cost. Brazeau, although we can stage it, we can phase out the size of Brazeau. It’s a pretty big project. I think right now, it would roughly be in the $3 billion range to put it in place and Tent Mountain would be quite a significant order of magnitude less than that.

Chris Varcoe: Thank you.

John Kousinioris: Great. Thank you.

Operator: Presenters, there are no further questions at this time. Please proceed with your closing remarks.

Chiara Valentini: Great. 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 later today. Thank you very much.

Operator: We thank you for joining and ask that you please disconnect your lines. Thank you.