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.
spk06: Welcome to the Capital Powers First Quarter 2022 Results Conference Call. As a reminder, all participants are in listen-only mode and the conference call is being recorded today, May 2, 2022. I will now turn the call over to Mr. Rondi Ma, the Director of Investor Relations. Please go ahead.
spk07: Good morning and thank you for joining us today to review Capital Powers First Quarter 2022 Results. which we released earlier this morning. Our first quarter report and the presentation for this conference call are posted on our website at CapitalPower.com. Joining me this morning 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 and ratios 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 gap measures, which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-gap financial measures to their nearest gap measures can be found in our first quarter 2022 MB&A. I will now turn the call over to Brian for his remarks, starting on slide four.
spk04: Thanks, Randy, and good morning. Capital Powers head office in Edmonton is located within a traditional and contemporary home of many indigenous peoples of the Treaty 6 region and Métis Nation of Alberta Region 4. We acknowledge the diverse indigenous communities that are located in these areas and whose presence continues to enrich the community and our lives as we learn more about the indigenous history of the lands on which we live and work. In the first quarter, Capital Power delivered on our strategic objectives of growing our renewables fleet increasing contracted cash flows, and re-contracting our natural gas assets. Strathmore Solar, our first Canadian solar facility, began commercial operations in March. The 41 megawatt facility is fully contracted with 100% of the renewable energy and associated renewable energy credits sold to TELUS under a 25-year PPA. We also executed a 10-year renewable energy agreement with ME Global Canada for the balance of the uncontracted portion of the Whitlaw Wind facility. Whitlaw Wind is now fully contracted for 100% of the energy generated and approximately 86% of the environmental attributes for 10 years. The additional phases of Whitlaw Wind representing an additional 151 megawatts began commercial operations in December of 2021. After four months of operations, it's operating very well with higher generation than forecast. The contract renewal for our island generation facility is nearing completion. We have agreed in principle to the terms of a four and a half year electricity purchase agreement with BC Hydro. Both parties are finalizing details and execution is expected within the next several weeks. We continue to aggressively intervene in the BCUC IRP process based on our expectation that island generation is needed beyond four and a half years. Turning to slide five, I will touch on the significant progress that has been made on our Genesee CCS project in the first quarter and the very encouraging developments that have occurred on the policy front. Enbridge's open access Waubman Carbon Hub which would provide transportation and sequestration services for the Genesee CCS project, was awarded the right to pursue development of a carbon hub as part of the Government of Alberta's CCUS hub process. For our Genesee CCS project, we have completed our preliminary feed study that updated various technical and cost parameters, and feed study activities are proceeding. On April 7th, the federal government provided the details of the proposed refundable CCUS investment tax credit as part of the 2022 federal budget document. The CCS IT for projects undertaken before 2030 would be set at 60% for investment in direct air capture projects, 50% for all other capture projects, and 37.5% for investment in transportation, sequestration, and use. The details of the proposed ITC are encouraging and will provide important support for the Genesee CCS project. We continue our discussions with the Canadian Infrastructure Bank on the framework for financing. We also continue to explore programs the federal and provincial governments have launched that are intended to provide targeted support for accelerated deployment of CCUS and other large-scale decarbonization technologies. We also expect First Nations participation as well as other potential partnerships for the project. We have been clear that a decision to ultimately proceed with the project will require a mechanism for de-risking carbon policy. We were pleased to see the federal government's 2030 Emissions Reduction Plan document released on March 29 included a commitment to explore these types of mechanisms. The ERP specifically stated the following. To enhance long-term certainty, the Government of Canada will explore measures that help guarantee the future price of carbon pollution. This includes, for example, investment approaches like carbon contracts for differences, which enshrine future price levels in contracts between the government and low-carbon project investors, thereby de-risking private sector low-carbon investments. We will continue to engage with the federal government on this issue. Turning to slide six, I'll comment on our prospective growth outlook. In Ontario, our three natural gas assets, York Energy, East Windsor, and Gorway, are currently under long-term contracts with the earliest expiry in 2029. The ISO recently published their annual acquisition report that identified incremental capacity needs of 2500 megawatts by 2027 and an additional 1500 megawatts by 2030. This creates significant opportunities for capital power either for expansion of existing facilities or the addition of batteries. These developments support that these facilities are well positioned for re-contracting in regions with significant needs. We continue to advance numerous sites in our U.S. solar and storage pipeline and expect to begin actively marketing more advanced facilities. With respect to M&A, we are seeing significant opportunities for both thermal and renewable assets and expect to meet or exceed our annual $500 million committed capital for growth target. I'll now turn the call over to Sandra.
spk05: Thanks, Brian. On slide 7, I'll touch on the financial highlights for the first quarter. Overall, financial performance was strong company-wide, resulting in double-digit percentage increases in all key financial metrics. Revenues and other income before unrealized changes in fair value of commodity derivatives and emission credits was $746 million, a 23% increase year-over-year. We reported adjusted EBITDA of $348 million, the highest quarterly adjusted EBITDA in two years. Adjusted EBITDA benefited from higher generation from the Genesee units in Clover Bar Energy Center and favorable Alberta commercial performance. We also had a full quarter of performance from the additional phases of Whitlow Wind that began commercial operations in December of last year. In Ontario, we saw 2.5 times higher generation from Gorway from increased dispatch, mainly due to nuclear outages that required additional baseload generation. And our U.S. renewable facilities performed well from higher generation, partly offsetting the higher consolidated adjusted EBITDA with slightly lower year-over-year performance from our U.S. contracted facilities. Buckthorn Wind had lower financial performance this year due to the impacts from the extreme weather events in Texas in February of 2021, while lower heat rate call option margins, higher gas prices and maintenance costs resulted in lower financial performance from Arlington Valley. We reported AFFO of $200 million in the first quarter, a 26% increase from a year ago, and net cash flow from operating activities was $415 million in the quarter, that doubled the $206 million a year ago. Overall, a very strong first quarter to start the year. Moving to slide 8, I'll touch on the Alberta power market and our hedge positions. The average Alberta spot price was $90 per megawatt hour in the first quarter, reflecting high availability of generation in the province, mild weather, and strong wind generation. Our realized power price was $84 per megawatt hour in the first quarter, compared to $77 per megawatt hour in the first quarter of 2021. This slide shows our hedge position for power and natural gas for 2023 to 2025. For 2023, we are 58% hedged in the low $60 per megawatt hour range. In 2024, we are 37% hedged in the high $50 per megawatt hour range, and for 2025, we are 24% hedged in the high $50 range. This compares to forward prices of $78, $63, and $59 per megawatt hour for 2023 to 2025, respectively. In 2023 and 2024, the hedges currently in place are predominantly longer-term contracts. The contracts capture a lower price relative to the forwards but reduce price risk in future years when we see prices moving down. For example, in 2023, 58% of our baseload is under long-term contracts, many of which are three to five years or longer in duration. The long-term hedges have an average price in the low $60 per megawatt hour range, which reflects longer-term forwards. Natural gas prices have an increasing impact on our financial results as we transition off coal. We have been actively hedging our expected natural gas burn for the Alberta fleet at favorable prices relative to forwards. As previously disclosed in our 2021 year-end results, 100% of our expected natural gas volumes for 2022 are hedged at an average hedge price between $2 and $2.50 per gigajoule. For 2023 and 2024, we are over 90% hedged and over 50% hedged in 2025. The average hedge price for all three years is between $2 and $2.50 per GJ, which is much lower than the forward prices at the end of the quarter, as shown in the table. Turning to slide 9, I'll conclude my remarks by reviewing our 22 targets and comment on the outlook for the remainder of the year. Availability in the first quarter was 95% compared to our full-year target of 93%, which reflects the planned outages at Genesee 1 in the first quarter and a planned outage for Genesee 3 scheduled later in the year. Sustaining CapEx was $25 million in the first quarter compared to our target of $105 to $115 million. Sustaining CapEx is expected to be above the target range due to increased work planned for the remainder of the year and the timing of work. We continue to monitor the impact from rising inflation rates, which currently only have a modest unmitigated exposure on our operating results. For our growth projects, we are managing our construction exposure, which includes having a significant percentage of our procurement costs locked in for the Genesee repowering. We expect strong internally generated cash flow based on favorable Alberta price outlook that supports financing for our growth CapEx and refinancing of PREF shares. Both S&P and DBRS recently reaffirmed our investment grade credit ratings with credit metrics well above the current rating threshold. Overall, we now expect to meet or exceed the upper ends of our full year guidance ranges of $1.11 billion to $1.16 billion for adjusted EBITDA and $580 to $630 million in AFFO. We are also reiterating our 5% annual dividend growth guidance out to 2025. Finally, we continue to target $500 million per year of committed capital for growth. 2022 is expected to be another exceptional year, both financially and strategically. I'll now turn the call back over to Randy.
spk07: All right. Thanks, Sandra. Operator, we're ready to take questions now.
spk06: 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 Rob Hope with Scotiabank. Please go ahead.
spk12: Morning, everyone. First question is just on the solar supply chain. We're seeing the potential for tariffs in the U.S. and a relatively, we'll call it, conflicted supply chain out there right now. How is that impacting your existing projects as well as the next phase of projects that you could be adding to the development pipeline?
spk05: So for the existing projects, when we're looking at the cost of panels or the impact on the projects, it's mostly isolated to the North Carolina solar projects, where for us at this point, the key consideration is the higher transport cost to bring panels over from Vietnam. And so given the timing delays on that project, we feel that we'll see some normalization in those container costs as we move forward and and that will be the key consideration there. With respect to future projects, as we get a line of sight on the implications on the cost of panels going forward, we see that that will be built into the economics of any new projects, and that would be industry-wide, so it wouldn't just be specific to projects we're doing, but I think you'll see that some of those cost considerations will become a factor in the cost of future projects.
spk12: Thanks for that. And then maybe as a follow-up, it seems like you're speaking more favorably about M&A activities and the opportunities you're seeing out there. Is it more on the renewable side? Is it more on the thermal side? And if we do see a slowdown in kind of the development pipeline for solar, does this push you more into the M&A side?
spk04: So, Rob, you know, as we've said sort of all along, you know, we don't really – prefer one side, development versus M&A, over the other. What we're seeing in front of us today is a very significant level of opportunities on the M&A side. I think we've been talking for the last year that we've expected a significant uptick at some point. Well, that's happened. So that's why we're a little bit more bullish on that today. And as you pointed out, Particularly on the solar side, there's maybe a little bit of a pause associated with just uncertainty around pricing. So I would say on a very temporary basis, we're not quite as bullish at the front part of this year on solar or wind, but certainly expect to be able to pull the trigger on a renewable project this year. But as I say, there's a significant amount of traffic out there on the M&A side that actually fits us.
spk12: I appreciate it.
spk06: Caller, I'll hop back in the queue. The next question comes from David Gazzata. with Raymond James. Please go ahead.
spk02: Thanks. Good morning, everyone. My first question here, just on the Genesee carbon capture project, I guess now that you've done some engineering work, I'm curious if you can provide any color on how that budget has been refined and maybe any commentary around return expectations and how de-risking on the policy front could affect your return expectations there.
spk04: So the work that we've done to date, that being completion of the pre-feed study and moving into the feed study, more or less confirms our price range that was there before, our costs from $1.8 to $2 billion. So no change on the pricing side, or any of the significant operating type costs or parameters continue to be the same. When we look at the overall returns, we've generally been targeting something around a merchant risk. And so as we see the support coming in in different ways, such as supporting the capital costs through investment tax credit, et cetera, and a forward view as to what carbon pricing looks like, That tends to drive a cash flow that, again, we're looking for something around emergent return. The challenge that our next challenge is in dealing with the federal government and developing something like a contract for differences on carbon pricing that actually reduces the return. It doesn't necessarily increase the level of cash flow, but significantly reduces the risk to the project. Again, we've been kind of thinking about it in terms of a merchant-type risk, given the nature of the asset and the overall opportunity, and we think that that fits well.
spk02: Excellent. Thanks for that, Brian. Maybe just one more from me on the clean energy standard and the equivalency review that's happening right now. Just curious what you see as potential outcomes, and I guess any call you could provide on, you know, what that equivalency outcome ends up being and how that would affect your strategy going forward?
spk04: So in terms of the federal perspective, you know, we're seeing some, you know, definitely some positive elements around it. You know, certainly the federal government is recognizing, for example, that, you know, you're going to need in Canada, you know, significant levels of natural gas generation beyond 2035. and that certainly something with abated natural gas like Genesee 1 and 2 may well be operating below a standard set at that point in time. So the general environment for setting the equivalency standards is actually much more positive than it has been in the past. What that ultimately looks like is a matter of course over the next number of months through to, I believe, the end of this year. Now, once the federal government sets its overall framework, and it is happening and will happen through that period, the provincial governments who look for equivalency will be negotiating and negotiating and looking at the various equivalency elements and levers that they have within their jurisdictions. We've been told by the provincial government that they very much want to hold the 0.37, so we'll see how that goes. In the event that it doesn't hold and it drops, we expect that consistent with the way the federal government has been signaling things over the last number of years that what they're looking to do is to actually set guideposts out there so that it doesn't cause any significant disruption. So we think any glide path down from the point 37 won't be extremely abrupt, but would be a relatively soft glide path. And from that perspective, we don't really see that it would necessarily change our strategy. In some respects, more severe glide path in the short term is probably more positive for us in terms of the implications for the market and power prices, et cetera. And I think as you know, our exposure to carbon tax is essentially only in Alberta. Our facilities in BC we're not responsible for the carbon tax implications, likewise with our assets in Ontario. So, you know, increasing the variable cost in the province of Alberta just tends to increase everybody's variable costs and power prices.
spk02: That's great, Collier. Thank you. That's it for me.
spk06: The next question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
spk11: Maurice Choi Thank you, and good morning. Just the first question, and it's probably a follow-up on the policy side. There's clearly some clarity needed on these policy matters, and particularly I'm thinking about, as you mentioned, guaranteeing the price of carbon pollution, the CES, and the federal review of the performance standards. Yet you still continue to expect to make an FID by mid 2023 for CCUS. So from now until mid 2023, can you lay out the timing of when you expect these policy matters to emerge? And also, is there in your range of outcomes the potential of delaying the FID if necessary?
spk04: So very good question because what we base our investment decision timing on is the development of these major parameters. I think as we had signaled earlier in the market, we thought we might have a complete investment decision by the end of this year. And what moved that off was the slowdown, in our view, of the development of decisions around the Alberta hubs. So, again, that we saw as taking a considerable amount of time, given the prudent way in which we want to proceed. In terms of the other elements of the government that is important to us, the first one is we expect, in relatively short order, more details, more specific details around the investment tax credit and the degree to which it applies to us. And, again, it does apply to us in terms of our project. you know, are 100% of the project costs eligible or, you know, what may they allow or disallow in their determination of eligible assets to be in the calculation. And then after that, or, you know, at the same time and going in parallel, are discussions and negotiations around, you know, and I'll just call it a contract for differences on carbon price. Those discussions are ongoing. We've had a number of conversations with the federal government about the need and the nature of it. We expect that they will be proceeding on that fairly rapidly. In the background, one has to recognize that the federal government is trying very much to significantly reduce carbon in the atmosphere by 2030, which means anything needs to be operational by 2029, which means it needs to be really, truly operational sometime in 2028 to ensure that it can function properly. And there's always a commissioning and other activities to get a facility like this up to the to the carbon capture level that you're looking. So there isn't an awful lot of time in this framework to achieve some of the carbon reduction targets. And the federal government is very, very aware of that. And they are, I would say, moving extremely quickly in terms of trying to develop these frameworks and these mechanisms so that decisions like ours can be made. Thus far, the speed of the federal government actions have not slowed our project down, but it wouldn't be too long into the future that it actually would. So we would hope, and this is a long way to answer your question, we would hope the whole contract for differences, that element, would be done by the end of this year. Then after that, it's more or less just normal project process to get us to an investment decision by the middle of next year.
spk11: And just to follow up on that, the CES and the Federal Review of the Performance Strategy view that timing to be around the same time as the carbon CFD that ended this year as well?
spk04: Yeah, we're hopeful that there'll be a very significant amount of clarity around that in and around the end of this year.
spk11: Great, thank you. And my second question is about market share. And obviously, once the Genesee Repowering is complete, the facility should have a rather dominant baseload position in Alberta Power Market. Where do you see your market share being? Is there a target for what you want to be? and whatever that amount or percentage is, what's the mix between merchant and contract, recognizing the comments from S&P earlier this month as well on your business risk?
spk04: So, you know, we've never really had a market share target, and we actually don't have a market share target. As we look at it, What we try to do is position our assets and either build or historically, like with Shepard, acquire a position in an asset so that it can perform very well in the market. So when you look across our assets, especially after the repowering, we'll have you know, the lowest asset in terms of dispatch and best efficiency in the marketplace. And when you look at, you know, one that's a little bit higher in the curve being the Sheppard Energy Center, you look at our peaking facilities, they continue to be the best in the province, the most efficient. So that's what interests us. Getting just more megawatt generation doesn't appeal to us. So again, we're more focused on quality of assets and competitiveness than we are on quantity.
spk11: Thank you very much.
spk06: The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
spk00: Thank you. Good morning. I just wanted to come back to the inflation theme here. Just curious in light of the ongoing pressures out there, if you might revisit potentially crystallizing the off-coal compensation payments as a way to help mitigate the need to access other sources of equity for your various investment opportunities. And I guess if not, maybe you can touch on what other funding levers you might be exploring today, either divesting of certain mature assets in the portfolio or perhaps bringing in financial partners at the asset level, for example.
spk05: Thanks, Pat. So we continue to look at all of those things. But if you think about where we sit today in terms of our funding plans, we did redeem the PREFSHARE fund. at the end of December and have another tranche coming up in September that we expect to redeem and replace those with a hybrid instrument. But based on our current cash flow and spending profile, we're actually not in a position to have to be raising any kind of funding and just the replacement of those two hybrids, those two perhaps will give us more than enough cash flow for what we've currently done from a growth perspective on our committed capital. With respect to thinking about increased funding for growth that will be forthcoming, it would depend on the nature of what we see, whether it's more renewables or an acquisition. So find that we're very well positioned currently. If we were to do something in advance of the reset of our press in September, have the opportunity to upsize that and take advantage of our full hybrid capacity in the capital stack as one way of funding. As far as the crystallizing the off coal, it's something that we've looked at, but it's not been particularly attractive from our perspective. But that would be an option, and we continue to look at whether or not selling down any portion of some of our projects would be a good vehicle in lieu of raising equity, but would also consider any one or a combination of those as being something that would be available to us. But no specific plans. As I said, it will be dependent on our growth and what form that comes in.
spk00: Okay, thanks for that, Sandra. And then just with respect to natural gas prices here, you know, being at levels we haven't seen in, say, over a decade, obviously higher power prices are helping to maintain robust merchant margins, but given you've contracted over 90% of your base load gas supply needs through 2024, I'm curious, you know, at what power price does it make economic sense to... say, start dialing back some dispatch in order to realize higher margins on some of your contracted gas supply?
spk05: Yeah, so that's something that we do look at in terms of the balance between the price forecast increase as well as natural gas, but I couldn't tell you what sort of price level we would say that that would trigger that, but we do look at optimizing around both of those commodity values.
spk00: And then maybe just a follow-up, just giving your expectation of generating some excess free cash flow this year over and above your initial budget. I don't suspect that you'd be leaning towards a higher dividend increase this summer, but maybe you can just confirm your priority list in terms of allocating that excess free cash flow, whether towards debt repayment, share buybacks, perhaps tuck-in acquisitions, etc.? ?
spk05: Yes, so as usual, our first priority would be on growth and allocating that to more acquisitions and development. You're right around the dividend and not leaning towards an increase. I think that 5% dividend increase feels like the right level, so don't expect that we'll be revisiting that. With the buyback or reduction in debt, we don't have any near-term debt that needs to be So in terms of an early call of our 2024 tranches, that's probably not in the offering. And given the amount of growth that we see in the relatively near to mid-term, probably not looking at share buybacks at this point and just hoping that we're able to deploy the capital to growth and feel optimistic that that is what will unfold for us.
spk00: All right, that's great. I'll leave it there. Thank you.
spk06: The next question comes from Mark Jarvie with CIBC Capital Markets. Please, go ahead.
spk08: Thanks. Good morning, everyone. Brian, you made a comment earlier at the start of the Q&A session about likely or expect to pull the trigger on a renewable project this year. Was that in the context of M&A or on an originated project internally? Yeah, that's more an originated project. And then just with the solar tariffs and supply chain stuff in the U.S., when you're talking about looking to pull the trigger or do something, is it more activity in Canada right now, just a little bit of uncertainty in the U.S., or maybe just kind of give us sort of some context in terms of how things are looking north and south of the border right now?
spk04: So we've got ongoing activities on both north and south of the border. And, you know, there certainly is a bit of a cause for some pause on the – on the solar side in terms of doing something right now. In fact, there was an RFP opportunity for us in the States that we looked at, and we said, you know, there's just too much uncertainty right now to be, you know, moving forward with, you know, committed prices, et cetera. So, you know, there's a bit of a pause there. But we expect that given the importance of solar development in the United States in the shorter term, that those issues will be resolved fairly quickly. I would say at the end of the day, I would expect that there will be some increase in solar costs, but it won't be as sporadic as it is today in terms of people thinking a little bit more stable. But again, I think everybody's price will go up a bit, and that will get reflected through to customers. On the Canadian side, we continue to see opportunities here in Alberta, and certainly we see some significant or very interesting developments in Ontario. When we talk about renewables, we're also talking about battery activity. We see some very near-term developments in Ontario as well. On both sides of the border, we're pretty optimistic.
spk08: Okay, got it. And then with the MSSC and sort of like a cap, I guess, on the units in terms of capacity and in your work around with the batteries, it talks about in MD&A, you guys are, you know, there is a review around maybe increasing that, the MSSC. How does that factor in your ability just either to pause on the batteries or move ahead or scale those? Like, can you pull it together in terms of whether or not that's creating uncertainty and how you adjust if there is an increase?
spk04: So we keep monitoring that as well. I mean, we certainly believe the batteries will have an enduring value beyond just simply providing a capacity when called for. But we are watching that. We're also watching things like, for example, if you have a CCUS project that's continually drawing energy from those facilities, that effectively creates the same thing and reduces what would otherwise be considered as requirements for batteries. So we're looking at that. We are in a position where we can modify the size of the batteries as we go, so very much a current conversation, current consideration.
spk08: And then the last question is just on realized pricing. It didn't seem as if there was as much dispersion or volatility pricing this year versus last, but you got higher realized pricing. Is there something just the way you guys have become smarter in the dispatch as you've seen the market evolve in the last year or adjusting certain assets? So maybe just kind of comment on how you guys were able to sort of push higher on the realized pricing.
spk05: Yeah, good question. As far as if we've gotten smarter, I think we've always been deep in expertise in that area. So as far as the volatility, that is a part of the captured price. So when you're looking at the number of megawatts that were run, that's your denominator. And then on the top is sort of your pool receipts plus your trading gains. So you are seeing some increase on the trading side that would push that up. So definitely good results from the desk would be a large part of what you're seeing in terms of the higher realized price in the quarter.
spk08: And was there anything in particular about the hedge positions for Q1 that drove some higher realized pricing that maybe not come through in the balance of this year or do you feel like you're set up quite well for 2022?
spk05: I think we're set up quite well for the balance of 2022.
spk08: Great. Thanks, Andrew.
spk06: The next question comes from John Mould with TD Securities. Please go ahead.
spk09: Hi. Good morning, everybody. Maybe just pivoting back first to the CCUS project, it sounds like Clarity on carbon pricing is the biggest gating factor, and you ran through some of the other considerations. I'm wondering where potential partnerships fall into this timeline. And just to be clear, I'm referencing partnerships on the actual capture initiative and not the carbon hub. I think you suggested on a previous call that maybe from your perspective, ownership of just over 50% is maybe the sweet spot, depending on governance. Is that something that you would finalize at FIDE or something that you could announce sooner than that as you continue to develop the project and maybe some of those other policy questions fall into place?
spk04: In terms of a partnership, as we had said earlier, what we didn't want to do until we had gotten past some of these gates was to start engaging with other people to you know, talk about partnerships until, you know, the project had matured a bit, you know, including completion of the pre-feed study. You know, we're at that point now. You know, we are starting to engage with First Nations for participation in the project and do expect that that will proceed. First indications are very positive in terms of their desire to participate in the project. So, again, we'll see where those conversations to lead us to. In terms of bringing on additional partners, there's a few that we would see as strategic and valuable partners. One of the challenges that we have is how you actually consider Genesee 1 and 2 repowered versus the CCUS project and how they interrelate. So we're sort of working through some of those details now. And certainly with a 50% investment tax credit, we're actually today looking at it as it's a billion-dollar project, not a $2 billion project. So it is certainly with some First Nations participation something that is definitely in our wheelhouse in terms of being able to carry the capital ourselves. Having said that, we are open to a partnership depending on if it can be structured in an equitable risk way between the various partners. So some of those discussions we see will likely start in the next quarter or so, But definitely by the time we'd make an investment decision, we'd expect partners to be on board.
spk09: Okay, great. Thanks for that. Maybe just pivoting to Alberta and Bill 22, this modernizing Alberta's electricity grid bill, which I realized it was just tabled last week, but includes some provisions on energy storage, unlimited self-supply with exports, some other updates. I'm just wondering if you've got any preliminary thoughts on the law you can share with us and whether there's anything in there from your perspective that's of note or concern as it pertains to power market structure.
spk04: No, there actually isn't. A lot of that has been obviously discussed and reflects the background of consultations that we've been involved in. So A lot of it you could characterize as enabling and adjustments to the market to, again, put in place elements that help different kinds of technologies and things, obviously, like batteries and behind-the-fence generation, those things that have been under discussion for a you know, a considerable period of time. So no, we see it as enabling and positive from our perspective, particularly on the battery side.
spk09: Okay, great. I'll leave it there. Thanks for your time.
spk06: The next question comes from Ben Palm with BMO. Please go ahead.
spk03: Hi, thanks. Good morning. I had a couple questions on the hedging percentages and on the gas and the power system. And also, you mentioned also the energy trading results and the benefit you had. My question is, was there any opportunities for you guys in March when spot prices were low and you were buying spot and looking at higher hedge price?
spk05: Sorry, Ben. Didn't quite catch your question. Was there opportunities in March for you could repeat it?
spk03: Yeah, sure. Was there any opportunities for you to instead of physically produce power? We've seen this in the past where you got a hedge percentage at a hedge price at say $65 and then Sometimes spot goes on a 20, and sometimes you buy spot, not produce, and you just deliver to the hedge, just capture the spread.
spk05: Yeah, so the buys and sells. So, yeah, certainly that would be part of an ongoing strategy that we would look at as part of our portfolio optimization.
spk03: Okay, and you can't confirm if there were some of that in March?
spk05: We typically don't discuss sort of monthly results or any kind of strategic decisions we make around the portfolio at that level of details, but it is an ongoing strategy for sure.
spk03: Okay. And what about on a gas side, then, Sandra? Is there a certain price, $6, $7, where you're not producing gas or you're not your gas plants, you're not producing, you're just basically capturing a spread on a gas price?
spk05: So on the gas side, what we've procured is on our expected generation, and what we generate to a large extent is based on what we have to deliver. So, you know, we do look at all of those moving pieces and the ability to have financial settles and to buy and sell power. So you are seeing a lot of opportunity with the volatility of both power and natural gas to optimize around that. So that is something that certainly the desk does look to. to do in terms of creating value.
spk03: And can you clarify, when you calculate over 90% and there's a footnote on base load, are you taking basically a third of Genesee, half of Shepherd, and then you exclude Clover and all the peaking plants? Is that generally how you calculate that percentage?
spk05: Yeah, so it would exclude the peaking facilities, but as far as the base load, we would be looking at what our dispatch expectations are for the year on those facilities and coming up with what we are seeing. And so to the extent you can burn gas at Genesee, that would be factored into those percentages, but it would be very much aligned with a forecast view on how we're going to be running those facilities.
spk03: Okay, that's great. And then maybe one last question. Is there any outcome of the Texas dispute at all?
spk05: Not at this point in time. So we've been continuing to go through the various stages required under the litigation with the counterparty on that facility and expect that It is something that would be resolved this year based on how it's been proceeding and moving along through the various stages, but at this point, there's not a resolution.
spk03: Okay, that's great. Thank you.
spk06: Once again, if you have a question, please press star, then 1. The next question comes from Najee Baitoon of IA Capital Markets. Please go ahead.
spk10: Hi, good morning. Just wanted to go back to the topic of M&A. I'm wondering if you can give us a bit more details on the pipeline and the opportunities. It seems like there's a lot in the hopper. Just wanted to get a bit more color on that, if you can.
spk04: Well, I think it's a little bit difficult to be talking about potential transactions out there because there's also counterparties and there's also in competitive bidding processes. People wonder whether you're in or out of different processes. But I can characterize it that everything that we are looking at is down the fairway. They are contracted on both sides, contracted natural gas assets, midlife, well-positioned, everything according to strategy per se. Likewise, when there are some renewable opportunities, likewise, generally contracted, but also more and more you're seeing renewables pop up that have some significant or near-term expiration of contracts. So the portfolios there tend to be a little bit more mixed than when you're looking at natural gas assets, either as singles or in small groups of assets. So that's the general framework. More of what you've seen historically is somewhat what we're looking at today.
spk10: Okay, that's helpful. So similar to what's been done in the past, same strategy. And just to maybe take it a step further, do you have any specific strategic or financial targets that you want to achieve with M&A this year, be it diversification or accretion?
spk04: So, you know, when we look at things from the M&A perspective, you know, we certainly look for, particularly if it's natural gas, that they are, you know, significantly accretive. You know, unlike the renewables, which, you know, tend to obviously have... better multiples and likewise a higher cost, we see less accretion coming from those opportunities in general. We do look for accretions, but again, we don't have targets. I mean, we have the $500 million out there as a signal that we are looking for investments and have conversations like this. But as I think we've demonstrated in the past, we'll only pull the trigger on those projects that make sense to capital powers shareholders. And again, although we're extremely bullish right now, if it turns out that nothing that we're looking at through the year makes sense for us, we're not driven to grow just for growth's sake. We have a discipline, and we'll continue with that discipline.
spk10: That's helpful. Just maybe one last question to go back to CCUS. You talked about starting to potentially engage with partners on the Gen-SC project. In your discussions, or maybe current or future discussions, are there any partners that you think you can work with initially on the Gen-SC project, but maybe eventually on other similar projects in North America?
spk04: You know, as we look at it, and if you think of just, you know, CCUS, you know, it's the very high probability that it could move forward at Shepard. But outside of that, don't really see a lot of CCUS-type opportunities for us. There's such things as direct air capture, et cetera. But I think the partners that we're looking at in terms of the CCUS at Genesee tend to be, I would say, more specific to the opportunities that we might have in Alberta as opposed to more broad ones. I mean, we are not, just to be clear, we're really not looking for you know, investment capital. We're looking for somebody that actually brings value beyond capital.
spk10: Got it. Understood. Thank you.
spk06: This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Ma for any closing remarks.
spk07: Okay. If there are no more questions, we will conclude our conference call. Thank you for joining us today and for your interest in capital power. Have a good day, everyone.
spk06: This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
Disclaimer