Thank you for standing by. This is the conference operator. Welcome to Capital Power's Fourth Quarter 2020 Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference is being recorded today, February 19th, 2021. I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead. Good morning, and thank you for joining us today to review Capital Power's Fourth Quarter and 2020 Year-End Results, which we released earlier this morning. Our 2020 integrated annual report and the presentation for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vaasjo, President and CEO, Sandra Haskins, Senior Vice President, Finance and CFO. We will start with opening comments and then open the lines to take your questions. Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide two. In today's discussion, we will be referring to various non-GAAP financial measures as noted on slide three. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures can be found in our 2020 integrated annual report. I will now turn the call over to Brian Vaasjo for his remarks, starting on slide four. Thanks, Randy, and good morning. 2020 was an excellent year for Capital Power, which included tremendous growth in renewable development and significant announcements on repowering and our off-coal strategy. With respect to growth, we committed approximately CAD 1.7 billion in capital for seven renewable projects and the repowering of Genesee 1 and 2. The renewable projects included five solar development projects that have confirmed our competitive capability in solar development, which more than doubles our renewable development opportunities in North America. When completed, the repowered Genesee 1 and 2 units will be the most efficient, lowest GHG-emitting natural gas combined cycle units in Canada. They will provide tremendous long-term value. These units will also be capable of 30% hydrogen firing at COD, with the potential for 95% hydrogen at nominal additional capital costs. As part of our commitment to sustainability, we've accelerated our plan to be off coal to 2023, which is six years early. We are also investing in utilization technology with our increased ownership in C2CNT. Our financial results in 2020 were generally in line with our guidance, which resulted in an AFFO dividend payout ratio of 40%, which is below our long-term target of 45%-55%. Overall, solid progress was made in 2020 on our decarbonization strategy. Turning to slide five, I'll review our 2020 performance versus our annual targets, and Sandra will provide more details on our financial performance in her comments. Average facility availability of 95% significantly exceeded the 93% target. This was driven by excellent operational performance on top of the deferral of planned outages due to COVID-19. Sustaining CapEx of CAD 73 million was below the CAD 90 million-CAD 100 million target, mainly due to the deferral of various capital projects to 2021, most notably at Genesee, driven by COVID. We generated CAD 955 million in adjusted EBITDA, which was slightly below the CAD 960 million midpoint of the guidance range. AFFO of CAD 522 million would be above the midpoint of the guidance range, excluding the CAD 6 million impact of the line loss rule proceeding. For our construction targets, Cardinal Point Wind exceeded targets as it was completed early and came in below the low end of the targeted budget range in U.S. dollars. The Whitla Wind 2 project is tracking on budget and is on schedule for COD in the fourth quarter of this year. As I mentioned, we exceeded our CAD 500 million growth capital target by committing approximately CAD 1.7 billion to seven renewable projects and the repowering of Genesee one and two. Overall, we reached solid operational and financial results despite the COVID-19 pandemic. Moving to slide six, which illustrates our continued growth in renewables. Our seven renewable development projects will add a total of 427 MW when completed later this year and in 2022. The three North Carolina and Strathmore solar development projects have long-term PPAs of 20- and 25-year terms, respectively. We continue to pursue contracts for Whitla Wind 2 and 3 and the Enchant solar project. In total, the seven projects are expected to contribute an annualized adjusted EBITDA of CAD 70 million. Our generation mix is shown in the pie charts on this slide. In 2020, our renewable assets contributed 27% of our total adjusted EBITDA, which is expected to increase to 34% in 2025, based on the seven announced renewable projects. Natural gas facilities generated 43% of adjusted EBITDA in 2020, and this is expected to increase to 66% in 2025, including the re-powering of Genesee 1 and 2, and 100% gas utilization at Genesee 3. There will be a significant shift in our generation mix as we transition off coal in 2023. I'll now turn the call over to Sandra. Thanks, Brian. I'll start with a review of our Alberta commercial portfolio optimization activities on slide seven. Our trading desk continues to create value by capturing realized power prices above spot power prices. In Q4 2020, the average realized power price of CAD 56 per megawatt hour was 22% higher than the average spot price of CAD 46 per megawatt hour. At the end of 2020, our base load generation is 29% hedged for 2021, at an average contract price in the low CAD 60 per megawatt hour range. For 2022 and 2023, with 27% and 21% hedged at an average contract price in the mid CAD 50 per megawatt hour range for both years. Since the end of September of last year, the outlook for the Alberta power market has improved. At that time, forward prices were in the low CAD 50 per megawatt hour range for 2021 and 2022. Current forward prices are now CAD 70 per megawatt hour for 2021, and CAD 61 per megawatt hour for 2022. Turning to slide eight, I will discuss our fourth quarter results. The fourth quarters of 2019 and 2020 had non-cash accounting adjustments related to the off-coal compensation payments. In 2019, there was CAD 140 million of coal compensation recognized in Q4, compared with CAD 18 million in 2020. The year-over-year decrease of CAD 122 million is largely a result of the one-time recognition related to the G3, K3 swap in 2019 and impacts revenues and other income, adjusted EBITDA and basic earnings per share in the fourth quarter and full year results. In the fourth quarter of 2020, the Alberta government confirmed increase in carbon pricing under the TIER regulation. As a result, we deferred the utilization of our Alberta emission offset inventory to maximize their value in higher carbon tax years. The higher emission costs incurred of CAD 15 million reduces adjusted EBITDA and AFFO for 2020. Looking at our financial results on a year-over-year basis, revenue and other income in the fourth quarter were CAD 516 million, down 24% compared to Q4 2019. Adjusted EBITDA of CAD 220 million in Q4 2020 is down 38% compared to 2019. In addition to the items already noted, adjusted EBITDA was lower for the Alberta assets due to mild weather in the fourth quarter. In fact, it was the second warmest November since 1950. The mild weather and strong winds reduced the utilization of our gas plants. AFFO of CAD 86 million reported in the quarter reflects CAD 6 million for the first of three payments related to the Milner line loss ruling. AFFO was down CAD 128 million from last year due to similar items that impacted adjusted EBITDA. On slide nine, I'll review our 2020 annual financial performance versus 2019. Revenues and other income of CAD 1.9 billion were slightly below 2019, and as already mentioned, reflects the accounting recognition change of off-coal compensation payments. Adjusted EBITDA was CAD 955 million, down 7% compared to 2019, primarily due to the contributions from asset additions that were offset by the Arlington Valley toll decrease and the off-coal compensation recognition. We generated AFFO of CAD 522 million, which was down 6% year-over-year, while AFFO per share was CAD 4.96 per share compared to CAD 5.32 per share in 2019. AFFO was in line with our guidance to be near the midpoint of CAD 525 million before the CAD 6 million line loss payment. I'll now turn the call back to Brian. Thanks, Sandra. I'll conclude with a recap of our 2021 annual targets starting on slide 10. Our average availability target is 93%, which is the same target as 2020, and includes major planned outages at Genesee 2, Decatur, and Shepard. Our sustaining CapEx annual target is CAD 80 million-CAD 90 million. The adjusted EBITDA target is CAD 975 million-CAD 1.025 billion, where the midpoint of the range is 4% higher than 2020. Finally, the AFFO target of CAD 500 million-CAD 550 million is unchanged from 2020. The positive outlook in the Alberta power market reinforces our financial guidance. Our growth targets are highlighted on slide 11. This includes developing and constructing seven renewable projects on budget and on time for commercial operations starting in the fourth quarter of this year to the fourth quarter of 2022. We are also proceeding with the repowering of Genesee 1 and 2 after issuing full notice to proceed on the project in December 2020. The repowered units will be completed in 2023 and 2024. As in previous years, we have a target of CAD 500 million of committed capital for growth that is aligned with our strategy of growing our renewable assets and/or acquiring mid-life contracted natural gas assets. Turning to slide 12, I'll conclude by mentioning that we released our 2020 integrated annual report this morning. Some of the key highlights of this report include our progress towards our ESG group goals, acceleration of our path to a lower carbon future from repowering and being off coal in 2023, six years early, and our ongoing commitment to innovation with C2CNT and the Genesee Carbon Conversion Center. I'll now turn the call back over to Randy. All right. Thanks, Brian. Charisse, we're ready to take questions. Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. The first question comes from David Quezada with Raymond James. Please go ahead. Thanks. Morning, everyone. My first question here, just on the topic of renewable energy credits, and I guess with the backdrop of a potentially rising federal carbon tax. I'm just wondering how you think the value of those RECs is going to change going forward and how that affects your view of potentially even increased, I guess, merchant renewable development in Alberta. Good morning. Certainly, the increasing profile of carbon tax in the province will definitely increase the, I'll call it, the economics of merchant wind facilities and solar facilities in the province. We do expect that there will be a significant increase in renewable build in the province over, say, the next decade or so, in which, again, we expect to participate in it fully. In terms of its impact on price, because there's two things. There's, of course, the stated price, CAD 30 this year and CAD 40 next, or sorry, CAD 40 this year. What you see happening is that that doesn't necessarily translate into what is the market price. For example, you could see prices in a year when, say, the carbon credit posted price was CAD 30, you could see prices actually trading as low as in the high or the low CAD 20s. There is definitely a market out there, and as there's more and more credits available, it does certainly have an implication on the market value. Having said that, the way the credits work in Alberta is from time to time, the credit allowance for new projects is reset based on the overall carbon intensity in the market. That's approximately 50% today. As things like our repowering and other things roll forward, you'll see the entitlement around new renewable projects actually going down, consistent with the change in intensity in the overall Alberta grid. There's a number of factors in play, but we think it'll continue to be a fairly robust carbon credit market. Great. Thank you for that color. That's helpful. Maybe just one more from me. Obviously, you've had some really good success on the solar side of things. I'm curious about how you're looking at things in the U.S. today. How have you seen things, I guess, progress with maybe some earlier-stage solar developments? Would you consider looking at acquiring a development portfolio? I guess, just any thoughts on how the more supportive administration in the U.S. affects how you see things moving forward? We certainly think the Biden administration and early indications that there will be a more robust environment for building renewables in the U.S. and, in particular, increasing appetite for solar. In terms of how we see it and how we intend to participate, we're continually looking for sites for ourselves to develop, sites in earlier stages of development with typically smaller developers and certainly would look at a portfolio of development assets. We're pretty much open to any opportunity depending on how it's sourced and the economics around that particular site. Again, we have a history, particularly on the wind side, of doing all three of what I just described and certainly would be doing that on the solar side as well. Excellent. Thank you for that. I'll get back in the queue. Our next question comes from Maurice Choy with RBC Capital Markets. Please go ahead. Thank you. Good morning. My first question relates to the 2021 guidance. As you've said, you've reaffirmed the guidance. Can you discuss some of the major moving parts around this position, specifically as it relates to the more positive outlook in Alberta, given the recent surge in pricing, as well as Sandra alluded to higher oil prices? What, if any, EBITDA headwinds you may have given the recent events in Texas? As far as 2021 guidance goes, we're very encouraged with what we're seeing happen with pricing, as you've noted. Seeing the market post PPA very much in line with what we would have expected to see in terms of behavior. We're pleased to date, but you need to, sort of, balance what you're seeing with prices with the megawatts generated. We will be doing our forecast on our normal timeline and have an update to guidance as we come through the quarter. Certainly, very pleased with what we're seeing to date. With respect to Buckthorn, we did incur some modest physical damage at Buckthorn as well as at Bloom. We now have access to the equipment but are in the early stages of sort of assessing as to where we sit contractually. It'll be a few days before we start to know what the financial impact of that will be. The order of magnitude will not be in line with what others have reported. On the upside of that, we were able to export energy `down into the U.S. during the sort of the peak days of that storm. See that as being a bit of a modifying factor with respect to those impacts. Thanks. Just to clarify with regards to your comments on Texas or the events around it. It sounds like directionally it's negative but not material, be that compared to the overall EBITDA and/or your guidance? Yeah, it's not material for sure relative to what we've seen to date. We don't have a number at this point, but as I said, there was some positives as well as with the impacts that we've seen. From our understanding, the weather patterns have kind of passed our site. Figure we're now in a position where we can look to come up with what the impact is. Definitely not material and not seeing that as an impact on guidance at this point. Thanks. My second question relates to your funding plan. Obviously, if indeed cash flows from Alberta become a little bit more strong compared to your initial outlook, that obviously offers you financial flexibility. Could you update us on your thoughts on asset recycling, specifically as it relates to your comments on Investor Day, that certain renewable energy projects could be potential candidates for monetization? Yeah, that remains to be true. Since Investor Day, we now have a revised cash flow profile in terms of our spending on repowering, and it does reduce the amount of spend this year, because of our contract with the supplier, with Mitsubishi, in the process of looking at that. To your point, yeah, asset recycling is still something that we look at in place of equity, given that we do feel that there's a significant value that is not realized in our renewable portfolio. Given our success in securing those projects, we do see that selling down projects would be a very viable option. We'll continue to look at that. As I mentioned, at this point, we haven't started to see any material spend occur. Therefore, we wouldn't be looking to come to market so we can continue to forecast what the impact of a stronger pricing in Alberta means for our overall financing plan. Thank you for this comment. Thank you. Our next question comes from Mark Jarvi with CIBC. Please go ahead. Thanks. Good morning, everyone. Maybe you updated some of the hedging for the full year? Are you able to share your outlook for Q1 in particular in terms of your openness and ability to capture some of these higher prices we've seen in recent weeks? Yeah. Typically, we wouldn't give our position within the year in terms of how we've been hedged. Certainly, what we've seen in Alberta in February has been very high pricing. Last week, we actually hit a new record high in demand for the province. Seeing some very high pricing that's gone along with the very cold weather that we've been seeing. We wouldn't comment on what our hedge position was within the year on a quarterly or monthly perspective. Okay. Then with respect to the AFFO guidance, I don't believe you guys had the line loss ruling impact in the 2021 guidance. It seems like there's still some uncertainty around timing and some settlements around those. Do you have a sense right now of when you might have clarity? What the range of potential payments could be and if some of the pushes and pulls and a good start to the year, how that line loss ruling cash payments might impact where you get to on your AFFO range? Yeah. With AFFO and the line loss ruling, we didn't have it built into our 2020 guidance, and there was also uncertainty last year around how many payments may fall in 2020 versus 2021. At one point, we thought we might see two payments last year and one this year. As it turns out, we did have the one payment last year of CAD 6 million. In 2021, we have baked in the additional two payments in our guidance. There'll be another, I believe, it's around CAD 11 or CAD 12 million, which we'll make one of those payments in February. The other one is in March. At this point, we feel that the line loss payments aren't moving around anymore. We did pay CAD 6 million of the CAD 18 million last year, and the other two payments will be made in Q1 of this year, and that is included in the guidance that we have provided. Okay, great. Can you guys give any updated clarity in terms of the timing of the major outages at Decatur, Shepard, G2? Has any kind of moved around, and can you kind of zero us in on which quarters those will fall in? Yeah. I don't have the quarterly split for those, they haven't moved around in terms of the expected costs or timelines. I can get back to you on that, Mark, if that works. Okay, thanks. That's all I had for my questions. Thank you. Our next question comes from Rob Hope with Scotiabank. Please go ahead. Good morning, everyone. A follow-up question on the Alberta power market. Since January 1st, we've seen kind of bidding and offer control move back to owners. Can you just comment on how you're seeing the dispatch curve as well as the economic bidding in the market and whether or not you are seeing what we'll characterize as we'll call it more economic bidding overall in 2021? I guess it's probably more prior to the cold snap. Also, has the volatility seen there also been in line with expectations? It is early days, as you stated. We are going through a cold snap, which is an unusual time. We're very pleased with what we've seen so far in that it does align with our expectations in terms of how people would be bidding and responding in a more rational, commercially responsible manner, as opposed to the days when length was held by the Balancing Pool. We do see things as being in line with expectations as you've outlined. Okay. A follow-up there. We've actually seen some strength in AECO Gas, too, as well. As you transition your fleet more towards gas and away from coal, how do you think about natural gas supplies and that exposure there? It's one where we look at what our expected utilization is in the year. We would look to hedge that. In the current year, the majority of our gas exposure has been hedged at an attractive pricing. We would continue to hedge out. We do have positions that go out a number of years. We continue to leg into hedges on our natural gas burn exposure. That's it for me. Thank you. Our next question comes from Patrick Kenny with National Bank Financial. Please go ahead. Yeah. Good morning, everybody. Just wanted to follow up on the decision to defer some carbon offset credits in Q4. I just wanted to confirm if you expect to utilize those credits in 2021, or should we expect a similar strategy, defer some of those credits until you get clarity on the carbon tax moving up to potentially CAD 170 per ton? Our 2021 guidance had already expected that we would be utilizing offsets as permitted under the regulation. The deferral that we did from 2020 does allow us to have more inventory as we go into 2022 and then 2023 before our exposure becomes less on a volume basis with repowering. Certainly, as you said, if here we're to be in lockstep with the federal plan, then we would see carbon taxes grow even higher and the value of those offsets increase as each year comes with a step-up in carbon pricing. The deferral just allows us to have more inventory in 2022 and 2023, whereas 2021 isn't impacted, and therefore, the decision not to use them last year doesn't change our guidance for 2021. It does mean that is extended out to those future years. As you noted, we could see carbon price eventually move up to CAD 170. I guess, just to clarify, Sandra, if you do defer your carbon credit inventory on a quarterly basis, sort of in line with Q4, if that ends up being the run rate through 2021, you're still comfortable with your EBITDA guidance range at this point? Yes, that's right. Okay, great. Just to move over to the integrated report here, and you have some attractive emission reduction targets by 2030, but just curious if you have any thoughts around business mix, say, more near term, call it middle of the decade, after Genesee is repowered. Given you'll be off coal by then, do you have any internal targets on, say, percentage of EBITDA coming from renewables or non-emitting fuel sources like hydrogen, in that 2024, 2025 range? Yeah. Go ahead, Brian. No, go ahead, Sandra. Yeah. We haven't set targets specific to fuel type beyond 2025. We look at opportunities to deploy our capital in the types of generation that we've iterated before as far as renewables or midlife gas, but see that we will be within our ESG targets, so that becomes part of the criteria that we would look at. As far as fuel mix, we do sort of forecast out to that mid-decade based on the projects that we currently know are in the hopper. As far as incremental growth after that, we don't have a set target in terms of an annual mix. I can also add that in setting those targets and in terms of our indications that we are on track to meet those targets, there is no either hydrogen or significant carbon capture and storage within those numbers. Having said that, we are right now actively looking at both utilization of hydrogen and carbon capture and storage as it relates to our Genesee facilities. I wouldn't say that we wouldn't, at some point in time, have significant carbon mitigation impacting on both the targets and our actual results. It's a little bit early at this point in time to speculate on where that might be going. To say that we are very actively looking at those two technologies from the standpoint or in relation to our Genesee facilities, in particular, the repowered Genesee one and two. Okay. Just maybe a last cleanup question, if I could. Just wanted to square up the investment growth target for 2021. Are you still looking to secure an additional CAD 500 million of growth on top of what you have on the go today, which appears to be like CAD 1.7 billion over the next few years? I was just curious how much of that target for 2021 might already be spoken for, if any. Actually, none of it's spoken for. Obviously, we've got a lot of construction on the go. We've got a lot of activity. In setting that target, we did do a full assessment of what our opportunities are out there, but also assessed both our financial and our physical capability of being able to execute on whether it be an additional build or whether it be an acquisition. We're comfortable that if an appropriate opportunity or opportunities come by on either the natural gas acquisition side or on the new build renewable or potentially a renewable acquisition, we're in position and have the capability that we can execute on it. Felt that keeping a CAD 500 million committed capital target was reasonable under the circumstances. Okay, that's great. Thank you. Our next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Thank you. Good morning. This is a broader question, and it really just relates to some of your counterparties and just their view on contracting and maybe how that's evolved over the course of last year. Really, if we can focus maybe on Q4 and then sort of year to date on how maybe their attitudes have changed a bit. Because obviously, the PPA system rolled off. We saw a lot of market volatility for a variety of reasons. You mentioned some of the bidding strategies and how they've become more market-oriented versus under the PPA framework. Any color you have on that and just how your counterparties and prospective counterparties are really behaving, any fundamental differences. Obviously, on the U.S. side, there's growing optimism that there'll continue to be good economic opportunities for counterparties to gain long-term access to renewable energy. That plays into it a little bit, but we haven't really seen any sort of disruption in the market. We don't really, because it's going from a kind of a robust environment to a robust environment. The expectation was that there'd be a significant trough with a potential continuation of the Trump administration. In fact, I think it'll be more the case of the avoidance of the trough. From the Canadian perspective, and in particular in Alberta, we're not seeing a big difference in people's expectations or in appetite. There continues to be a lot of interest in a number of large power consumers in terms of gaining long-term contracts for renewable energy. As we indicated at Investor Day, we had a number of ongoing conversations going in respect of contracting, and those conversations continue to be there and continue to move forward. Not a lot of change yet. We do expect in the longer term, there will be, again, more and more contracting available on the renewables side. That's very helpful. Maybe just specific to Alberta, how do you think about just your market positioning on contract versus merchant and open exposure on a near-term basis and then on a longer-term basis? What's the sweet spot for you? Certainly, we see the merchant renewable market in Alberta as being positive in creating good value for our shareholders. We do also see that having it contracted as much as practical is also good. It ends up being where we see the best trade-offs. We wouldn't sacrifice significant economics in order to gain a contract. On the other hand, one does recognize that to move to a contract, you do typically give up at least a forecast EBITDA from a merchant perspective. In the long run, I think we generally favor, again, with a fair trade-off of economics and security of cash flow. We would typically rather have more contracted than not. There definitely is a preference for us to be more contracted, but again, not willing to give up a lot of economics to gain those contracts. Okay. Thank you. The next question comes from Ben Pham with BMO. Please go ahead. Hi. Thanks. Good morning. I wanted to follow up on Buckthorn in Texas. You mentioned there's some physical damage. Could you clarify that a bit more? Is it some icing on the blades you had to replace on the blades? What are your thoughts in general now observing the last five days in the market? Does it improve your appetite for the market, whether gas-fired generation or renewables? Do you feel maybe that's not a market that you want to expand in anymore? Yeah. As far as the physical damage, as I said, we've just gotten access to the sites and are looking at that. We've seen damage to a set of stairs at Bloom and icing on blades. It's of that nature. As far as the market, you don't see this as being necessarily a highly reoccurring event. Certainly, we'll take a look at things, but no immediate shift in strategy or thinking at this point as a result of this weather-driven event. Okay. You got a good sense, I don't know what conditions are improving now. Do you get a good sense of how your financial hedge is structured at Buckthorn, your contract for differences and ability to manage the revenues and the hedge portion of it? Yeah. I think as I said, contractually, we are assessing where we are. Not in a position to really comment on that at this point. It'll be a few days, we don't see a large exposure there relative to what you're hearing in the market. It's something that we'll be able to comment on at a later point more fully. Okay. All right. Maybe on Alberta, to update your hedge position. What's the thought process then of not moving higher on your hedge position given where pricing is right now on the forward curve, CAD 70? Yeah. There's a few things. I think when we came into the beginning of the year, you did see milder temperatures in January. There's less opportunities now that we're seeing prices settle. We are continuing to add hedges to the book as we see opportunities to do so at prices that are in line with our expectations. Continue to hedge out the book as we move forward. There are more megawatts and therefore liquidity isn't necessarily as strong. Now that we've seen prices continue to move up, even as we've gone through January and February, we'll sort of take positions as we see those opportunities. Okay. Then has your view changed then long-term CAD 55 prices when you take what you've seen so far this year and put that to a higher carbon tax? Yeah, you would expect that as carbon taxes increase, that will be reflected in higher power prices as well as you move forward. At this point, we see the CAD 40 has been confirmed for 2021. The TIER program has not indicated what it would be in 2022 and forward, but to the extent that it is lockstep with the federal program, it expects to go to CAD 50 and then increase by CAD 15 a year after that. You will see that reflected in power prices. The units that are on the margin will bid that in with their costs, and that will set the price then in the market. Okay. Maybe my last question here. You put out a pretty detailed ESG sustainable report, a lot of data there. You're pushing forward with renewables. I'm wondering, how do you balance really the, maybe the perception versus reality on gas-fired generation, when you look at building that portion of your business out against renewables here where cost of capital is low, that's where most of the money's flowing to. How do you balance it over the next few years in your mix? Well, I think if you look at the mix of CapEx over the next couple of years, actually most of it's going towards natural gas, i.e., the Genesee 1 and 2 repowering. You're quite right. When you compare the returns on natural gas assets and the returns associated with the renewable assets, the returns are higher. As we look forward and look at our overall mix of natural gas and renewables, we do have to strike a bit of a balance between significant increases in cash flow and so on in support of dividends with a stable base of long-term renewable contracts that, again, generate good, relatively low-risk cash flows. It is, at this point, continues to be a little bit of a balancing act, depending on changes in economics and perception. We do expect events like what's happening in the U.S. might create some increasing interest in natural gas. Interestingly enough, if you look at the statistics, coal was basically what saved the U.S. from actually having a much greater disaster. Coal plants performed extremely well. It's incidents like this that actually show the real dynamics and the need for dispatchable energy, the resiliency of dispatchable energy. Again, we saw a little bit of, with California, last year, actually over the last couple of years, increasing sense of the need for dispatchable natural gas. Certainly believe coal is limited. These events can result in an increasing interest in natural gas, which would create, again, a little bit more compression on returns for a company like ours for looking at new natural gas asset opportunities. Overall, a little bit uncertain, but do definitely, as we go forward, need to continually think about the balance between higher return natural gas assets and lower return renewables. Okay. All right. Thank you. The next question comes from John Mould with TD Securities. Please go ahead. Thanks. Good morning. Maybe just like to start with dispatch during the recent and I guess ongoing cold snap in Alberta, and I appreciate you may not want to say too much about dispatch decisions. It looks like Clover Bar didn't run much in January, and one of your Genesee units was maybe running below where we might have expected earlier this month, just given the pricing environment. Is there any context you're able to provide on whether the weather's had any impact on coal fuel availability or any other operational factors that might have constrained dispatch at your Alberta thermal fleet thus far in the quarter? There was no issue of availability of our facilities. They're fully capable of operating. What you saw was more the overall bidding approaches and strategies associated with the Alberta market that Sandra was discussing earlier. Okay, great. That's helpful. Maybe just one last one on C2CNT. You said you're taking your stake up to 40% as expected. Can you provide an update on where they're at in the cement testing cycle and what milestones you're anticipating from that entity or hoping for over the coming year? From the C2CNT perspective, as I indicated, they have finished the XPRIZE process. They continue, though, and one of the surprises to us and to them was there continues to be some very significant reporting requests, technical requests coming that is consuming a significant amount of the C2CNT's time. It has slowed and which has impacted all across the board. When you think of the timing of testing cement and so on and so forth, that was always in the latter stages of having the facility at Shepard operating and in process. Likewise, the testing on the cement side slowed as well. It's ongoing. It's happening as we speak. Having said that, I'll just comment around just the details of the cement testing. There's two different phases of that. One phase is where you're actually testing what they call mortar, so small samples, not in a lab, but a little bit bigger scale than what you would think of in terms of a laboratory. There's been extensive testing done from that perspective, and it now moves to significant, larger scale testing at a typical cement plant site. That's the process that's taking place right now. Again, it was slowed up as well, but continues to be generally as expected in terms of the evolution of the C2CNT development. Okay. I'll leave it there. Thanks for taking my questions. Once again, if you have a question, please press star then one. Our next question comes from Naji Baydoun with iA Capital Markets. Please go ahead. Hi, good morning. Just wondering if you can give us an update on where you see opportunities to invest in new or different types of technologies. I appreciate you've increased your stake in C2CNT, but it is a small investment within your portfolio right now. Just wondering if you can talk about other opportunities, be it in batteries, carbon capture, or hydrogen, that you're considering, and maybe some color on how much capital you'd be comfortable deploying into earlier-stage opportunities. As we've always said, the answer to carbon mitigation on a global basis is sort of the answer is all of the above in terms of the technology. When we look at the technologies that we would deploy, it is all essentially on does it make commercial sense, and does it make sense for Capital Power facilities? Certainly, up until the investment in repowering Genesee 1 and 2, we had a bit of a different perspective on carbon mitigation at the Genesee facility. Certainly, C2CNT holds some promise for some modest mitigation. Certainly, the fact that they were coal or dual-fuel facilities impacted in terms of our long-term view as to whether, for example, in the longer term, you put hundreds of millions of dollars into mitigating their carbon profile. With repowering, that changes that view. As I said earlier, we're looking at mitigating the carbon exposure for those facilities and do believe at some point there will be something in place that will mitigate the carbon emissions from those facilities. The issue is what is the technology and what is the timing? As we're looking at it today, we're actively looking at whether it makes sense from a hydrogen perspective or whether it makes sense from, I'll call it a more traditional carbon capture and storage perspective. Again, we're doing that work now and do expect that at the end of the day, we will start some degree of more in-depth technical analysis on one or both of those technologies as we move forward. I think the one thing to recognize about this point in time is that firstly, for carbon storage, typically enhanced oil recovery or just simply I'll call it burying the carbon. Alberta is ideal. It's got the geology, whether it be caverns that have been emptied of oil or whether it be salt aquifers much, much deeper. Alberta has the geology to actually support very extensive carbon storage. We're in the right province, and as you've been hearing, both in the United States and in Canada, there's huge expectations around carbon capture and storage. It's seen as one of the ways in which we'll meet our carbon objectives. Maybe a little bit of a stretch for 2030, but certainly in the longer term, it will be a necessary part of the mix, and we expect the Genesee Facilities to be part of that. Again, timing's a little bit uncertain, but there is tremendous amount of anticipated government support for these kinds of initiatives going forward. How much would we risk, per se? To put it more clearly, I wouldn't expect that we would be, I'll say, developing a technology around hydrogen or around carbon capture and storage. I think what you would find us doing is looking at established or near established technologies and the application into Genesee 1 and 2, or in some circumstances, Genesee 3 as well. We'd be looking more at the fundamental preliminary engineering studies and then move on to FEED studies and then ultimately to a project. Just sort of the normal transition of a project as you would expect. Quote unquote, "Investing in R&D," you might at some point see a modest investment, maybe in the same order of magnitude of C2CNT, which has been quite modest, but you wouldn't see or at least I wouldn't expect a significant investment in R&D. It's more the implementation of actually established technologies. Thank you. That's a great color. That's it for me. This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks. Okay. Thank you, Charisse. If there are no more questions, we will conclude our conference call. Thanks again for joining us this morning, and for your interest in Capital Power. Have a good day, everyone. This concludes today's conference call. You may disconnect.