This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk01: 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 Ma, the Director of Investor Relations. Please go ahead.
spk08: 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 Baggio, President and CEO, and 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 Vazio for his remarks starting on slide four.
spk05: 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 $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, and will provide tremendous long-term value. These units will also be capable of 30% hydrogen firing at COD, with a 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% to 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 our 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 73 million was below the 90 to 100 million target, mainly due to the deferral of various capital projects to 2021, most notably at Genesee driven by COVID. We generated $955 million in adjusted EBITDA, which was slightly below the $960 million midpoint of the guidance range. AFFO of $522 million would be above the midpoint of the guidance range, excluding the $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 Whitlaw Wind 2 project is tracking on budget and is on schedule for COD in the fourth quarter of this year. And as I mentioned, we exceeded our $500 million growth capital target by committing approximately $1.7 billion to seven renewable projects and the repowering of Genesee 1 and 2. Overall, we reached solid operational 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 megawatts 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. And we continue to pursue contracts for Whitlaw Wind 2 and 3 and the Enchant solar project. In total, the seven projects are expected to contribute an annualized adjusted EBITDA of $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 repowering 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.
spk06: 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 $56 per megawatt hour was 22% higher than the average spot price of $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 $60 per megawatt hour range. For 2022 and 2023, 27% and 21% hedged at an average contract price in the mid $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 $50 per megawatt hour range for 2021 and 2022. Current forward prices are now $70 per megawatt hour for 2021 and $61 per megawatt hour for 2022. Turning to slide eight, I'll 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 $140 million of coal compensation recognized in Q4 compared with $18 million in 2020. The year-over-year decrease of $122 million is largely a result of the one-time recognition related to the G3-K3 swap in 2019 and 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 $15 million reduces adjusted EBITDA and ASFO for 2020. Looking at our financial results on a year-over-year basis, revenue and other income in the fourth quarter were $516 million, down 24% compared to Q4 2019. Adjusted EBITDA of $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. ASFO of $86 million reported in the quarter reflects $6 million for the first of three payments related to the Milner line loss ruling. ASFO was down $128 million from last year due to similar items that impacted adjusted EBITDA. On slide 9, I'll review our 2020 annual financial performance versus 2019. Revenues and other income of $1.9 billion were slightly below 2019 and, as already mentioned, reflects the accounting recognition change of off-cold compensation payments. Adjusted EBITDA was $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 $522 million, which was down 6% year over year, while AFFO per share was $4.96 per share compared to $5.32 per share in 2019. ASFO was in line with our guidance to be near the midpoint of $525 million before the $6 million line loss payment. I'll now turn the call back to Brian.
spk05: 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. That includes the major plant outages at Genesee II, Decatur, and Sheppard. Our sustaining CapEx annual target is $80 to $90 million. The adjusted EBITDA target is $975 million to $1.025 billion, where the midpoint of the range is 4% higher than 2020. Finally, the AFFO target of $500 to $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. And as in previous years, we have a target of $500 million of committed capital for growth that is aligned with our strategy of growing our renewable assets and are acquiring midlife 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 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.
spk08: All right. Thanks, Brian. Charisse, we're ready to take questions.
spk01: Thank you. We will now begin the question and answer session. To join the question queue, you may press star, then 1 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 2. We will pause for a moment as callers join the queue. The first question comes from David Quevedo with Raymond James. Please go ahead.
spk11: 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?
spk05: Good morning. Certainly, the increasing profile of carbon tax in the province will definitely increase the economics of merchant wind facilities and solar facilities in the province. So 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, $30 this year and $40 next year, or sorry, $40 this year. You know, what you see happening is that that doesn't necessarily translate into what is the market price. And so, for example, you know, you can see prices in a year when, say, the carbon credit posted price was $30. You can see prices actually trading as low as, you know, in the high or the low 20s. So 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 that 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. And 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. So there's a number of factors in play, but we think it will continue to be a fairly robust carbon credit market.
spk11: Great. Thank you for that, Collar. 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? And I guess just any thoughts on how the, I guess, the more supportive administration in the U.S. affects how you see things moving forward?
spk05: So we certainly think that Biden administration and early indications that there will be a more robust environment for building renewables in the United States, 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 sites for ourselves to develop sites with you know in early earlier stages of development with typically smaller developers and certainly would look at you know a portfolio of development assets we're pretty much open to you know any any opportunity depending on you know how it's sourced and in the economics around that particular site so 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.
spk11: Excellent. Thank you for that. I'll get back in the queue.
spk01: Our next question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
spk13: Thank you and good morning. My first question relates to the 2021 guidance. As you've said, you've reaffirmed the guidance, but 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 fall prices? And what if any EBITDA headwinds you may have given a recent event in Texas?
spk06: Yeah, so as far as 2021 guidance goes, you know, we're very encouraged with what we're seeing happen with pricing, as you've noted. So seeing the market post-PPA very much in line with what we would have expected to see in terms of behavior. So we're pleased to date. But you need to sort of balance out what you're seeing with prices with the megawatts generated. So, you know, we will be doing our forecast on our normal timeline and have, you know, an update to guidance as we come through the quarter. But certainly very pleased with what we're seeing to date. With respect to Buxhorn, you know, we did incur some modest physical damage at Buxhorn as well as at Bloom. We now have access to the equipment, but are in the early stages of assessing as to where we sit contractually, so 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. you know, on the upside of that, we were able to export energy down into the states during sort of the peak days of that storm. So see that as being a bit of a modifying factor with respect to those impacts.
spk13: Thanks. And just to clarify, we've got to see your comments and Texas already bent around it. It sounds like directionally it's negative but not material be that compared to the overall EBITDA and all your guidance?
spk06: 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 the impacts that we've seen. And from our understanding, the weather patterns have kind of passed our sight. So figure we're now in a position where we can look to come up with what the impact is. But definitely not material and not seeing that as an impact on guidance at this point.
spk13: Thanks. And 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. But 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?
spk06: Yeah, that remains to be true. So 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. So in the process of looking at that, but to your point, yeah, asset recycling is still something that we look at in places of equity, given that we do feel that there's a significant value that is – not realized in our renewable portfolio. So given our success in securing those projects, we do see that selling down projects would be a very viable option. So we'll continue to look at that. But as I mentioned, you know, at this point, we haven't started to see any material spend occur. And therefore, you know, 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.
spk13: Thank you. Thank you.
spk01: Our next question comes from Mark Jarvie with CIBC. Please go ahead.
spk10: Thanks. Good morning, everyone. Maybe you updated some of the hedging for the full year. Are you able to share any 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?
spk06: Yeah, so typically we wouldn't give, you know, 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. So, seeing some very high pricing that's gone along with the very cold weather that we've been seeing. But we wouldn't comment on what our hedge position was within the year on a quarterly or monthly perspective.
spk10: Okay. And 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 settlements around those. But do you have a sense right now of when you might have clarity, what the range of potential payments could be, and 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?
spk06: Yeah, so with AFFO and the line loss ruling, so 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 $6 million. In 2021, we have baked in the additional two payments in our guidance. So there'll be another, I believe it's around $11 or $12 million, which will make one of those payments in February. The other one is in March. So at this point, we feel that the line loss payments aren't moving around anymore. So we did pay $6 of the $18 million last year, and the other two payments will be made in Q20. Q1 of this year, and that is included in the guidance that we have provided.
spk10: Okay. Great. And then can you guys give any updated clarity in terms of the timing of the major outages at Decatur, Sheppard, G2? Has any kind of moved around, and can you kind of zero us in on which quarters those will fall in?
spk06: Yeah. So I don't have the quarterly figures. blitz for those, but they haven't moved around in terms of the expected costs or timelines, but I can get back to you on that, Mark, if that works.
spk10: Okay, thanks. That's all I had for my question. Thank you.
spk01: Our next question comes from Rob Hope with Scotiabank. Please go ahead.
spk02: Good morning, everyone. A follow-up question on the Alberta power market. Since January 1st, we've seen 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. And I guess it's probably more prior to the cold snap. And also has the volatility seen there also been in line with expectations?
spk06: Yeah, so it is early days, as you stated, and we are going through a cold snap, which is an unusual time. But yeah, we're very pleased with what we've seen so far in that it does align with our expectations in terms of of how people would be bidding and responding, you know, in a more rational, commercially responsible manner, as opposed to the days when length was held by the balancing pool. So, yeah, we do see things as being in line with expectations, as you've outlined.
spk02: Okay, and then a follow-up there. We've actually seen some strength in ECO gas, too, as well. You know, as you transition your fleet more towards gas and away from coal, how do you think about natural gas supplies and that exposure there?
spk06: It's one where we look at what our expected utilization is in the year, and then we would look to hedge that. So in the current year, you know, the majority of our gas exposure has been hedged at an attractive pricing, and so we would continue to hedge out. And we do have positions that go out a number of years, so we'll continue to leg into hedges on our natural gas burn exposure.
spk08: That's just for me. Thank you.
spk01: Our next question comes from Patrick Kenney with National Bank Financial. Please go ahead.
spk07: 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 $170 per ton.
spk06: Yeah, so our 2021 guidance had already expected that we would be utilizing offsets as permitted under the regulations. So 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. But certainly, as you said, if here were 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. But the deferral just allows us to have more inventory in 22 and 23, whereas 2021 isn't impacted and therefore, The decision not to use them last year doesn't change our guidance for 2021, but it does mean that that is extended out to those future years. And as you noted, we could see carbon price eventually move up to the 170.
spk07: I guess just to clarify, Sandra, so 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?
spk06: Yes, that's right.
spk07: Okay, great. And then 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, you know, after Genesee is repowered. Just given you'll be off coal by then, do you have any internal targets on, say, percentage of EBITDA coming from renewables for non-emitting fuel sources like hydrogen, kind of in that 2024-25 range? Yeah, so we haven't – go ahead, Brian.
spk06: No, go ahead, Sandra. Yeah. So we haven't, we haven't set targets specific to, uh, fuel type, um, beyond, you know, 2025. Um, we look at opportunities to deploy our, our capital in, in the types of, of generation that we've, we've iterated before as far as renewables or midlife gas, but, um, see that, you know, we will be within, uh, our ESG targets. So that becomes part of the criteria that we would, would look at. But, um, 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. But as far as incremental growth after that, we don't have a set target in terms of an annual mix.
spk05: I can also add that we – 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. So 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, but it's a little bit early at this point in time to speculate on where that might be going, but 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 1 and 2. Okay.
spk07: And then just maybe 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 $500 million of growth on top of what you have on the go today, which appears to be I think $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.
spk05: So 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 you know, what our opportunities are out there, but also assess 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. And 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, Yeah, we're in position and have the capability that we can execute on it. So I felt that keeping a $500 million committed capital target was reasonable under the circumstances.
spk07: Okay, that's great. Thank you.
spk01: Our next question comes from Andrew Kuski with Credit Suisse. Please go ahead.
spk03: 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 and really we can focus maybe on Q4 and then for the year to date on how maybe their attitudes have changed a bit. There's obviously the PPA system rolled off. We saw a lot of market volatility. more market oriented versus under the PPA framework. And so any color you have on that and just how your counterparties and prospective counterparties are really behaving, any fundamental differences?
spk05: So, you know, obviously, you know, on the U S side, there's a growing optimism and that, that they'll continue to be good economic opportunities for counterparties to, um, gain long-term access to renewable energy. So, you know, that plays into it a little bit, but we haven't really seen any sort of disruption in the market. And we don't really, because it's, you know, it's going from a kind of a robust environment to, you know, a robust environment. The expectation was that there'd be a significant trough with a potential continuation of the the Trump administration, and, in fact, you know, I think it will be more the case of, you know, 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 companies 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. So not a lot of change yet, but we do expect in the longer term there will be again, more and more contracting available on the renewable side.
spk03: That's very helpful. And then 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? How do you think? What's a sweet spot for you?
spk05: So, you know, certainly... We see the merchant renewable market in Alberta as being positive and creating good value for shareholders. And we do also see that having it contracted as much as practical is also good. And 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. So 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.
spk12: Okay, thank you.
spk01: The next question comes from Ben Pham with BMO. Please go ahead.
spk12: 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 some of the blades. And then what are your thoughts or thoughts in general now observing the last five days in a market? Does it improve your appetite for the market? What are gas-fired generation or renewables? Are you you're feeling maybe that's not a market that you want to expand in anymore?
spk06: Yeah, so 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, you know, icing on blades. So it's of that nature. You know, as far as the market, you don't see this as being necessarily a highly reoccurring event. So, you know, certainly we'll take a look at I look at things, but no immediate shift in strategy or thinking at this point as a result of this weather-driven event.
spk12: Okay. So you feel you've got a good sense, I don't know what the conditions are improving now, but you get a sense of how your financial hedge is structured at Buckthorne, your contract for differences and ability to manage the revenues in the hedge portion of it?
spk06: Yeah, I think that, you know, as I said, contractually we are assessing where we are, so not in a position to really comment on that at this point. It'll be a few days, but, you know, you don't see a large exposure there relative to what you're hearing in the market. So it's something that we'll be able to comment on at a later point more fully. Okay.
spk12: Maybe on... On Alberta, then you have 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, $70?
spk06: Yeah, so there's a few things. I think when we came into the beginning of the year, you know, you did see milder temperatures in January. So, you know, there's less opportunities now that we're seeing prices settle. We are continuing, you know, to add hedges to the book as we see, you know, opportunities to do so at prices that are in line with our expectations. So, continue to hedge out the book as we move forward. But, you know, there are more megawatts, and therefore liquidity isn't necessarily as strong. But now that we've seen, you know, 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.
spk12: Okay. And has your view changed in long-term $55 markets? prices when you take what you've seen so far this year and the potential higher carbon tax?
spk06: Yeah, you would expect that as carbon taxes increase, that that will be reflected in higher power prices as well as you move forward. At this point, we see that $40 has been confirmed for 2021. The CARE 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 50 and then increase by 15 a year after that. You will see that reflected in power prices. So, you know, the units that are on the margin will bid that in with their costs, and that will set the price then in the market.
spk12: Okay. And 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 how do you balance really the maybe that perception versus reality and gas fired generation? When you look at building that, that portion of your business out against renewables here where profit capital as well, if that's where most of the money is flowing to, how do you how do you balance it over the next few years in your mix?
spk05: Well, I think if you look at the mix of capital expenditures over the next couple of years, actually most of it's going towards natural gas, i.e., the Genesee 1 and 2 repowering. And typically, and 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. And, you know, as we look forward and look at our overall mix of natural gas and renewables, you know, we do have to strike a bit of a balance between, you know, significant increases in cash flow and so on and supported dividends with a stable base of, you know, long-term renewable contracts that, you know, again, generate, you know, good, relatively low risk cash flows but you know it is you know at this point continues to be a little bit of a balancing act and depending on you know changes in economics and perception you know and we do expect you know events like what's happening in the US might 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, much greater disaster. Coal plants performed extremely well. So it's incidents like this that actually show the real dynamics and, you know, the need for dispatchable energy, the resiliency of dispatchable energy. So, again, we saw a little bit of, you know, with California, last year, actually over the last couple of years, increasing sense of the need for dispatchable natural gas. I certainly believe coal is limited, but 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 products. asset opportunities. So 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.
spk12: Okay. All right. Thank you.
spk01: The next question comes from John Mould with TD Securities. Please go ahead.
spk04: Thanks. Good morning. I'd maybe just like to start with dispatch during the recent and, I guess, ongoing cold snap in Alberta. And I appreciate, you know, you may not want to see too much of a dispatch decision. But 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 dispatching your Alberta thermal fleet thus far in the quarter?
spk05: There was no issue of availability of our facilities. They are fully capable of operating. So what you saw was more the overall availability bidding approaches and strategies associated with, with, you know, the Alberta market that, you know, Sandra was discussing earlier.
spk04: Okay, great. That's helpful. And then 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, 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?
spk05: 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 um, the C2CNTs time. So it, it has slowed and, um, you know, which has impacted, you know, all across the board. You know, when you think of the timing of, you know, testing cement and so on and so forth, you know, that was always in the latter stages of, you know, having the, um, the, uh, facility at Shepherd, you know, operating and, and, uh, in process. So likewise, the testing on the cement side slowed as well. So it's ongoing, it's happening as we speak. And 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 think of in terms of a laboratory. So there's been extensive testing done from that perspective and it now moves to significant larger scale testing at a typical cement plant site. And so 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.
spk04: Okay, I'll leave it there. Thanks for taking my questions.
spk01: Once again, if you have a question, please press star, then 1. Our next question comes from Naji Beydoun with IA Capital Markets. Please go ahead.
spk09: 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. So just wondering if you can talk about other opportunities, be it in batteries, carbon capture, hydrogen that you're considering, and maybe some color on how much capital you'd be comfortable deploying into earlier stage opportunities.
spk05: So, you know, as we've always said, the answer to, you know, Carbon mitigation, you know, on a global basis is sort of the answer is all of the above in terms of the technology. You know, when we look at the technologies that we would deploy, it is all, you know, essentially on does it make commercial sense and does it make sense for, you know, capital power facilities. Now, 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, but 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. Certainly with repowering, that changes that view. So as I said earlier, we're looking at mitigating the carbon exposure for those facilities and do believe at some point, you know, 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 technical, 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. So we're in the right province, and as you've been hearing both in the United States and in Canada, there's huge, 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 you know, the Genesee facilities to be part of that. So again, timing's a little bit uncertain, but there is tremendous amount of anticipated government support for, you know, these kinds of initiatives going forward. So how much would we risk per se? You know, I wouldn't, I mean, 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. So we'd be looking more at the fundamental, you know, preliminary engineering studies, and then move on to feed studies, and then ultimately to a project. So just sort of the normal, you know, transition of a project as you would expect, but quote, unquote, investing in R&D. You know, you might at some point see a modest investment, you know, maybe, you know, in the same, you know, 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.
spk09: Thank you. That's a great color. That's it for me.
spk01: This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Ma for any closing remarks.
spk08: Okay, thank you, Cherise. 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.
spk01: This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
Disclaimer