Capital Power Corp

TSX:CPX

Earnings Call Transcript 2020-Q4

[Operator]

Welcome to Capital Power's Fourth Quarter 2020 Results Conference Call. [Operator Instructions] The conference is being recorded today, February 19, 2021. I will now turn the call over to Mr. Randy Mah, the Director of Investor Relations. Please go ahead.

[Randy Mah, Senior Manager of Investor Relations]

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 reports 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; 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 2. In today's discussion, we will be referring to various non-GAAP financial measures as noted on Slide 3. 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 4.

[Brian Tellef Vaasjo, President, CEO & Director]

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 7 renewable projects and the repowering of Genesee 1 and 2. The renewable projects included 5 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 6 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 5, I'll review our 2020 performance versus our annual targets, and Sandra will provide more details on our financial performance and 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 million 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 a $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 Whitla 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 7 renewable projects and the repowering of Genesee 1 and 2. Overall we reached solid operational and financial results despite the COVID-19 pandemic. Moving on Slide 6, which illustrates our continued growth in renewables. Our 7 renewable development projects will add a total of 427 megawatts when completed later this year and in 2022. The 3 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 Whitla Wind 2 and 3 and the Enchant Solar project. In total, the 7 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 7 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.

[Sandra Haskins, Senior VP of Finance & CFO]

Thanks, Brian. I'll start with a review of our Alberta commercial portfolio optimization activities on Slide 7. 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 baseload generation is 29% hedged for 2021 at an average contract price in the low $60 per megawatt hour range. For 2022 and 2023, we are 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 8. I'll discuss our fourth quarter results. The fourth quarters of 2019 and 2020 had noncash 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 onetime 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 $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 $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. AFFO of $86 million reported in the quarter reflects $6 million for the first of 3 payments related to the Milner line loss ruling. AFFO was down $128 million (sic) [$42 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 was slightly below 2019, and as already mentioned, reflects the accounting recognition change of off-coal 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. AFFO 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.

[Brian Tellef Vaasjo, President, CEO & Director]

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 $80 million 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 million 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 7 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/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 goals, acceleration of our path to a lower-carbon future from repowering and being off-coal in 2023, 6 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.

[Randy Mah, Senior Manager of Investor Relations]

All right. All right. Thanks, Brian. Sherice, we're ready to take questions.

[Operator]

[Operator Instructions] The first question comes from David Quezada with Raymond James.

[David Quezada, Equity Analyst]

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.

[Brian Tellef Vaasjo, President, CEO & Director]

So 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. So we do expect that they will -- 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 2 things, there's the -- of course the stated price. $30 this year and $40 next -- or sorry, $40 this year. What you see happening is that, that doesn't necessarily translate into what is the market price. And so for example, you can see prices in a year when say, the carbon credit posted price was $30, you could see prices actually trading as low as 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 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. So -- 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.

[David Quezada, Equity Analyst]

Great. That's helpful. Just -- maybe just one more for 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?

[Brian Tellef Vaasjo, President, CEO & Director]

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 -- 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. So again, we have a history, particularly on the wind side, of doing all 3 of what I just described, and certainly we'd be doing that on the solar side as well.

[Operator]

Our next question comes from Maurice Choy with RBC Capital Markets.

[Maurice Choy, MD & Analyst]

My first question relates to the 2021 guidance. As you've said, you 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 floor prices. And what, if any, EBITDA headwinds you may have given the recent events in Texas?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So as far as 2021 guidance goes, 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 we will be doing our forecast on our normal timeline and have an update to guidance as we come through the quarter, but 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. So it will be a few days before we'll 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. So on the upside of that, we were able to export energy down into the states during the -- sort of the peak days of that storm. So we see that as being a bit of a modest modifying factor with respect to those impacts.

[Maurice Choy, MD & Analyst]

Okay. And 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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. It's not material, for sure, relative to what we've seen to date. So 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. And from our understanding of weather patterns that kind of passed our site, so we 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.

[Maurice Choy, MD & Analyst]

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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes, 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, yes, 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. 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, at this point, we haven't started to see any material spend occur. And 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.

[Operator]

Our next question comes from Mark Jarvi with CIBC.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Maybe you updated some of that -- 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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So 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, so seen some very high pricing that's gone along with the very cold, cold weather that we've been seeing. So -- but we wouldn't comment on what our hedge position was within the year by -- on a quarterly or monthly perspective.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

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. I see that 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 if it -- some of the pushes and pulls and seeing a good start to the year, how that line loss ruling cash payments might impact where you get to on your AFFO range?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. 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 2 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 2 payments in our guidance. So there'll be another, I believe it's around $11 million or $12 million, which we'll 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 million of the $18 million last year. And the other 2 payments will be made in Q1 of this year, and that is included in the guidance that we have provided.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay. Great. And then can you guys give us any updated clarity in terms of the timing of the major outages in the Decatur, Shepard, G2? Has any kind of moved around? Can you kind of zero us in which quarters those will fall in?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So I don't have the quarterly split 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.

[Operator]

Our next question comes from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

A follow-up question on the Alberta power market. Since December or since January 1, 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? 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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So it is early days, as you stated. And we are going through a cold snap, which is an unusual time. But yes, we are 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 [ lines ] was held by the balancing pool. So yes, we do see things as being in line with expectations, as you've outlined.

[Robert Hope, Analyst]

Okay. And then a follow-up there. We've actually seen some strength in ecogas 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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So 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, 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.

[Operator]

Our next question comes from Patrick Kenny with National Bank Financial.

[Patrick Kenny, Managing Director]

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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So our 2021 guidance had already expected that we would be utilizing offsets as permitted under the regulation. 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, we're to be in lockstep with the federal plan, then we would see carbon taxes grow even higher. And the value of those, 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 doesn't 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.

[Patrick Kenny, Managing Director]

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?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes, that's right.

[Patrick Kenny, Managing Director]

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 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 or non-emitting fuel sources like hydrogen, kind of in that 2024, '25 range?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So we haven't -- go ahead, Brian.

[Brian Tellef Vaasjo, President, CEO & Director]

No -- no, go ahead, Sandra.

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So 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 mid-life gas. But see that we will be within our ESG targets, so that becomes part of the criteria that we would look at. But 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, like, an annual mix.

[Brian Tellef Vaasjo, President, CEO & Director]

I can also add that we -- 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 facility. 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 2 technologies from the standpoint or in relation to our Genesee facilities, in particular the repowered Genesee 1 and 2.

[Patrick Kenny, Managing Director]

Okay. And then just maybe a last cleanup question if I could. I 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.

[Brian Tellef Vaasjo, President, CEO & Director]

So actually, none of it's spoken for. We obviously -- we've got a lot of construction on the go. We've got a lot of activity. We did, in setting that target, we did do a full assessment of 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, we're in a position and have the capability that we can execute on it. So we felt that keeping a $500 million committed capital target was reasonable under the circumstances.

[Operator]

Our next question comes from Andrew Kuske with Crédit Suisse.

[Andrew M. Kuske]

I guess as 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 if you 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 for a variety of reasons. You mentioned some of the business strategies and how they become 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?

[Brian Tellef Vaasjo, President, CEO & Director]

So obviously on the U.S. side, there is growing optimism that there'll continue to be good economic opportunities for counterparties to gain long-term access to renewable energy. So 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 going from kind of a robust environment to a robust environment. The expectation was that there would be a significant trough with a potential continuation of the Trump administration. And in fact I think it will be more the case of the avoidance of the trough. From a 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. 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 renewables side.

[Andrew M. Kuske]

That's very helpful. And then maybe just specific to Alberta, how do you think about just your market positioning on contract versus merchants and open exposure on a near-term basis and then on a longer-term basis? How do you think -- what's the sweet spot for you?

[Brian Tellef Vaasjo, President, CEO & Director]

So certainly, we see the merchant renewable market in Alberta as being positive in creating good value for our 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, you -- 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.

[Operator]

The next question comes from Ben Pham with BMO.

[Benjamin Pham, Analyst]

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 got to replace some of the blades? And then what are your thoughts about ERCOT in general now observing the last 5 days in the market? Has it improved your appetite for the market whether gas-fired generation or renewables? Or you feel maybe that's not a market that you want to expand in anymore?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. 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 icing on blades, so it's of that nature. As far as the market, you don't see this as being necessarily a highly reoccurring event. So certainly we'll take a look at -- look at things, but no immediate shift in strategy or thinking at this point as a result of this weather-driven event.

[Benjamin Pham, Analyst]

Okay. So you feel you've got a good sense that, I don't know, weather conditions are improving now. You get a sense of how your financial hedge is structured at Buckthorn to account for differences and ability to manage the revenues and the hedged portion of it?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. I think that -- as I said, it's contractually, we are assessing where we are, so I'm not in a position to really comment on that at this point. It will be a few days, but we 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.

[Benjamin Pham, Analyst]

Okay. Okay. And maybe on Alberta then, you are yet 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 in the forward curve $70?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes. So there's a few things. I think when we came into the beginning of the year, you did see milder temperatures in January. So 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. So we continue to hedge out the book as we move forward, but there are more megawatts, and therefore liquidity isn't necessarily as strong. But 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.

[Benjamin Pham, Analyst]

Okay. And then has your view changed then long term $55 prices when you think what you've seen so far this year and a potential higher carbon tax?

[Sandra Haskins, Senior VP of Finance & CFO]

Yes, 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 the $40 has been confirmed for 2021. The TIER program has not indicated it -- what it would be in 2022 and forward. But to the extent that it is lockstep with the federal program, I'd expect it to go to $50 and then increase by $15 a year after that. You will see that reflected in power prices. So the units that are on the margin, we'll bid that in at -- with their costs, and that will set the price then in the market.

[Benjamin Pham, Analyst]

Okay. And 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 is flowing to? How do you balance it over the next few years in your mix?

[Brian Tellef Vaasjo, President, CEO & Director]

Well, I think if you look at the mix of capital expenditures over the next couple of years, actually most of it is 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 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. But it is at this point, continues to be a little bit of a balancing act. And depending on changes in economics and perception, and 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 is 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 the need for dispatchable energy, the resiliency of dispatchable energy. So again, we saw a little bit of -- with California last year, actually, over the last couple of years, an increasing sense of the need for dispatchable natural gas, certainly, we 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 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.

[Operator]

The next question comes from John Mould of TD Securities.

[John Mould, Research Analyst]

Maybe I'd 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 on dispatch decisions. 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 has had any impact on coal fuel availability or any other operational factors that might have constrained dispatch of your Alberta thermal fleet thus far in the quarter?

[Brian Tellef Vaasjo, President, CEO & Director]

There was no issue of availability of our facilities. They're fully capable of operating. So what you saw was more the overall bidding approaches and strategies associated with the Alberta market that Sandra was discussing earlier.

[John Mould, Research Analyst]

Okay. Great. That's helpful. And then maybe just one last one on C2CNT. You've 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?

[Brian Tellef Vaasjo, President, CEO & Director]

So from the C2CNT perspective, we do -- I mean 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. So it has slowed and -- which is 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. 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, there's -- I'll just comment around just the details of the cement testing. There's 2 different phases of that. One phase is where you're actually testing what they call mortar. So small samples, not in a lab, but on a little bit bigger scale than what you think of in terms of the 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 where -- that's the process that's taking place right now. So again, it's -- it was slowed up as well, but continues to be generally as expected in terms of our -- and in terms of the evolution of the C2CNT development.

[Operator]

[Operator Instructions] Our next question comes from Naji Baydoun with IA Capital markets.

[Naji Baydoun, Equity Research Analyst]

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 or hydrogen that you're considering, and maybe some color on how much capital you'd be comfortable deploying into earlier-stage opportunities.

[Brian Tellef Vaasjo, President, CEO & Director]

So 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? 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, 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. And again, we're doing that work now and do expect that at the end of the day, we will start, well 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 are -- have been empty 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 then 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 if it will be a necessary part of the mix, and we expect the Genesee facilities to be part of that. So again, timing is a little bit uncertain, but there is tremendous amount of anticipated government support for these kinds of initiatives going forward. So how much would we risk per se? I wouldn't -- I mean to put it more clearly, I wouldn't expect that we would be say -- 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, the Genesee 3 as well. So we'd be looking more at the fundamental preliminary engineering studies and then move on to FEED studies and then ultimately to a project. So just sort of the normal transition of a project, as you would expect. But "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.

[Operator]

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.

[Randy Mah, Senior Manager of Investor Relations]

Okay. Thank you, Sherice. If there are no more questions, we will conclude our conference call. Thanks again for joining us this morning for -- and for your interest in Capital Power. Have a good day, everyone.

[Operator]

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.