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spk01: Welcome to Capital Power's fourth quarter 2021 results conference call. As a reminder, all participants are in a listen-only mode, and the conference call is being recorded today, February 24, 2022. I will now turn the call over to Mr. Randy Ma, the Director of Investor Relations. Please go ahead.
spk05: Good morning, and thank you for joining us today to review Capital Power's fourth quarter and year-end 2021 results, which we released earlier this morning. Our 2021 integrated annual report and the presentation for this conference call are posted on our website at CapitalPower.com. Joining me this morning are Brian Vazio, President and CEO, and Sandra Haskins, Senior Vice President, Finance and CFO. We'll 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 this 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 and ratios as noted on slide 3. These measures do not define 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 are disclosed in our 2021 Integrated Annual Report. I will now turn the call over to Brian for his remarks starting on slide four.
spk07: Thanks, Randy, and good morning. Capitol Power's head office in Edmonton is located within the 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 continue to learn more about the Indigenous history of the lands on which we live and work. 2021 was an excellent year in advancing our strategy and commitment to being off coal in 2023, where we saw strong progress from strategic, sustainability, and financial perspectives. At a high level, we escalated our renewables and storage footprint. We had success on long-term contracting of our renewable projects. And we made progress in repositioning Genesee 1 and 2 to be the most efficient combined cycle units in Alberta once the repowering project is completed. Sustainability continues to be integral to our business, where we have incorporated broad compensation that is linked to our ESG targets. We have also advanced our decarbonization strategy through strategic partnerships, such as collaborating with Enbridge on a CCUS project. Sandra will provide more details on our financial highlights. These highlights include delivering record financial performance and maintaining a strong balance sheet and access to capital to fund our growth. We have also significantly managed down several short-term and medium-term risks to capital power. And based on the stability of our cash flows, we have extended our annual dividend guidance to 2025. On slide five is a list of strategic highlights and accomplishments for 2021. We've enhanced the Genesee 1 and 2 repowering project with the integration of a 210 megawatt battery energy storage system, the largest in Canada. Once repositioned, Genesee 1 and 2 will have the dominant baseload position in the Alberta power market. We executed a six-year tolling agreement extension for Arlington Valley, that reaffirms our strategy of investing in strategically positioned natural gas assets. We completed the combustion turbine upgrade at Decatur that increases our contracted capacity and efficiency, which enhanced economics consistent with the contract extension we executed in 2020. WIDLAW became the largest wind facility in Alberta at 353 megawatts when phases two and three were completed ahead of schedule in early December and below budget. We executed 15-year renewable contracts with both Labatt's Breweries and Dow Chemicals to help them reach their sustainability goals through customized renewable energy solutions. And demand for renewable contracts for us continues to be very positive. Growth in our Alberta renewable assets continues with our latest project, Helcurt II, a 150 megawatt wind farm that is adjacent to our existing Helcurt wind facility in central Alberta. Lastly, we expanded our solar and storage development pipeline with the acquisition of a portfolio of solar sites with battery potential in the United States, providing us with a platform for significant renewable growth. Overall, these strategic advances support growth, and a roadmap to decarbonization. Turning to slide six, this chart shows our growth in renewables from 2016 to 2024. Based on current growth projects, we have achieved a compound annual growth rate of 18%. As the chart illustrates, we've delivered constant annual growth where new contracted renewable projects are added every year, except for 2023, when the original completion dates for the North Carolina projects have been delayed to 2024 due to the delays in the interconnection process. We are hoping to have at least one additional renewable project to be announced this year. Moving to slide seven, We are committed to be carbon neutral by 2050 and have a clear pathway that includes setting targets along that pathway. We've compensation elements for executives and capital power leaders that are directly linked to ESG targets. These include targets on diversity, a 30% carbon reduction by 2024, and employee well-being. In 2021, we achieved our sustainability targets to develop company-wide water management and sustainability sourcing strategies that are designed around ESG principles to positively contribute to society and ensuring our environment can thrive over the long term. We are moving to implement these strategies in 2022. Our Genesee 1 and 2 repowering project continues to be on track, supporting our commitment to be off-coal in 2023. We've also incorporated sustainability into our financing by transitioning existing credit facilities to sustainability-linked credit facilities that are tied to emission intensity targets. We're advancing our Genesee 1 and 2 CCS project by collaborating with Enbridge that I'll elaborate on shortly. Through our achievements in 2021, we've increased our velocity to meet our sustainability targets and positions the company to deliver long-term value for our stakeholders and the environment. Turning to slide eight, we have made substantial progress on the advancement of CCUS. The CO2 hub development process is moving forward in Alberta with the Enbridge project fitting our needs very well. We're in the process of finalizing our pre-feed study aimed at solidifying project definition technology licensing, scoping, preliminary engineering deliverables, and costing details. We're optimistic that sufficient financial support for the $1.8 to $2 billion carbon capture project will come from both federal and provincial governments. We're in discussions with the Canadian Infrastructure Bank on the framework for financing. We also expect First Nations participation as well as other potential partnerships for the project. One of the key issues for this project to proceed is de-risking carbon policy. There's a general appreciation by governments that long-term policy uncertainty presents unique risks to investments in CCS. Our discussions with governments has focused on potential mechanisms and approaches to mitigate adverse impacts in the event of carbon policy related changes. The final investment decision is now expected in mid-2023 and is subject to satisfactory hub progress, government support, and policy risk mitigation. I'll now turn the call over to Sandra.
spk06: Thanks, Brian. On slide nine, I'll touch on the financial highlights for 2021. As mentioned, we set an annual record for both adjusted EBITDA and AFSO in 2021 and our financial performance in 2022 is expected to be equivalent. We delivered on our eighth consecutive annual dividend increase and extended the annual dividend guidance of 5% to 2025 based on the support of predictable cash flows. In 2021, Capital Power delivered a total shareholder return of 19%, which is consistent with the five-year average and exceeding our target TSR of 10% to 12% over the long term. We have been de-risking our cash flows by securing low-cost carbon offsets, increasing commodity hedging, and executing on longer-term contracts to manage medium-term risks. In June of last year, we completed a successful $288 million equity offering to pre-fund our existing growth capex. We have just renewed our NCIB program for another year that provides a capital allocation option during periods of limited growth and when the shares are undervalued. We have also extended our debt maturity profile and reduced refinancing risk. Our investment-grade credit rating remains a top priority, and the strength of our balance sheet and resilient cash flow secures our credit rating. FFO to debt in 2021 is 23% compared to S&P's target of 17%. Overall, we are well-positioned to finance our growth CapEx using internally generated cash flow. Slide 10 shows year-over-year financial performance for the fourth quarter and for the full year 2021. We delivered year-over-year increases on all key financial metrics, both in the fourth quarter and for the full year. This includes generating revenues and other income of $1.99 billion in 2021 compared to $1.937 billion in 2020. Both adjusted EBITDA and AFFO exceeded the midpoints of our higher revised guidance. Adjusted EBITDA was $1.124 billion, an 18% increase compared to $955 million in 2020. And AFFO was $605 million in 2021, a 16% increase compared to $522 million in 2020. The positive factors that led to record performance in the year include strong performance from the Alberta commercial segment due to high Alberta power prices that averaged $102 per megawatt hour in the year. Witla II began commercial operations a month earlier than scheduled in 2021, and we received full-year contributions from the additions in 2020 of Buckthorn Wind and Cardinal Point. We accelerated the recognition of coal compensation with the Genesee 1 and 2 repowering project where we expect to be off coal by the end of 2023, six years earlier than required. We also had lower net finance expense of $23 million, largely a result of lower interest due to decreased loans and borrowings outstanding. Offsetting the positive factors were a weaker U.S. dollar, lower wind resources at most of our wind facilities, and higher current tax expense with 2021 being our first cash taxable year in Canada. Turning to slide 11, I'll provide a status update on the recontracting of our island generation facility. Island generation has provided reliable power to Vancouver Island in the lower mainland of BC for almost 20 years. Although the facility runs infrequently, it is there and available when needed to provide reliable generation. When BC Hydro faced significant challenges in 2019 and 2021, island generation offered at high capacity factors and helped to keep the lights on. Recall that in September of 2021, BC Hydro indicated to BCUC that it needed the island generation facility to operate during transmission repairs. In December 2021, BC Hydro released its final IRP where it affirmed its view that the long-term EPA for island generation is not required. Based on these developments and an assumption of a four-year contract extension, a $52 million impairment was recorded in the fourth quarter. We continue to expect the need for island generation beyond four years and are aggressively intervening in the BCUC IRP process. Moving to slide 12, I'll touch on the Alberta power market and our hedge position. In 2021, we saw full recovery in power demand from the COVID-related and low oil price load decreases in 2020. In fact, the Alberta market saw new record summer and winter peak demands. Despite not fully reopening, load remains strong today and is expected to increase modestly year over year. With the expiry of the balancing pool PPAs at the end of 2020, we saw a robust power market in 2021 with an average power price of $102 per megawatt hour compared to $47 per megawatt hour in 2020. The slide shows our hedge positions for power and natural gas. You will note that we have increased our hedge positions for 2022 to 2024 since our disclosure at Investor Day on December 2nd. For 2022, we entered the year 72% hedged in the high $60 per megawatt hour range. In 2023, we are 47% hedged in the low $60 range. And for 2024, we are 32% hedged in the high $50 range. This compares to forward prices of $94, $72, and $61 per megawatt for 2022 to 2024, respectively. The hedge position includes longer-term origination contracts as another mechanism to manage price risk and volatility. The contracts capture a lower price relative to the forwards in 2022, but reduce price risk in future years when we see prices moving down. For example, in 2022, we are 72% hedged in total and more than 40% hedged with contracts that are greater than one year in term, 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, whereas the balance of the hedge contracts are at an average price that is more in line with 2022 forwards. In 2023 and 2024, the hedges currently in place are predominantly longer-term contracts. 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. We have hedged 100% and 99% of our expected natural gas volumes in 2022 and 2023, and have hedged 85% of our expected natural gas volumes in 2024. The average hedge price for all three years is between $2 and $2.50 per gigajoule, which is much lower than forward gas prices as shown in the table. Turning to slide 13, I'll conclude our remarks by reviewing our 2022 targets and comment on the various sensitivities on these targets. As highlighted, 2021 was our strongest year for financial results, and 2022 results will build on the strong momentum. For 2022, we are targeting $1.11 billion to $1.16 billion in adjusted EBITDA and $580 to $630 million in AFSO. We have looked at the impacts from rising inflation rates and have a modest unmitigated exposure on our operating results. For our growth projects, we are managing our construction exposure, which includes having over 84% of our procurement costs locked in to the Genesee repowering, Also, with the delayed COD of the North Carolina solar projects to Q4 2024 and Halkirk 2 scheduled for late 2024, the timing will allow us to take advantage of more normal commodity and shipping costs. To manage the expectation of higher interest rates, we have fixed rate debt in place. We have also been actively hedging the underlying GOC rates for all financing into early 2026 in anticipation of increasing rates. Financing in 2022 is limited to the refinancing of preferred shares. 2022 will be a year with significant planned outages, including outages for Genesee 1 and 3. The sustaining CapEx is expected to be between $105 and $115 million, which is well above the forecast of $55 to $70 million in the next few years. Our 2022 targets also reflect our cash taxable position in Canada. We expect continued strong internally generated cash flow based on a strong Alberta price outlook. And finally, we continue to target $500 million per year of committed capital for growth. We expect 2022 to be another very strong year, both financially and strategically. I'll now turn the call back over to Randy.
spk05: All right. Thanks, Sandra. 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 Robert Hope with Scotiabank. Please go ahead.
spk11: Good afternoon, everyone. Just maybe a longer-term strategic question. Just on the natural gas midlife generation side, what are you seeing out there in terms of opportunities? And as you evaluate these opportunities, how does the ability to kind of reduce carbon at the sites or co-locate renewables or batteries fit into the investment decisions?
spk07: Good afternoon. So in terms of what we're seeing on the midlife natural gas assets in terms of activity these days, it has increased significantly over the last couple of months. So we're seeing a fair amount of traffic, not the same degree of traffic that we saw pre-pandemic, but definitely more than we've seen in the last couple of years. So that's looking encouraging. When we actually are looking at a particular proposal, obviously there's a contracting side comfort that, you know, for its economic life, it can be, you know, recontracted, you know, out into the future or has sufficient current long-term contract to carry us well into the 2030s. So, you know, that's sort of a first hurdle there. Then we look at it in terms of in part of our optimism around recontracting or lack thereof would depend on how it's strategically positioned. We've been looking at a number of assets that are just I'll call it simply generation assets and create energy, but those are readily displaced by renewables and would have a relatively shorter history. Those assets that are on the grid in terms strategic locations or, you know, for example, you know, those facilities that are peaking facilities would tend to have the longest enduring value. The other thing because of their positioning is it's a relatively straightforward transition to start including batteries on those sites and then eventually retiring the natural gas facilities and having, you know, storage capability, you know, realized at those sites. So there's a number of things that we look at and certainly, you The carbon outlook for each facility is looked at very, very closely and how it impacts on our targets. And what we see is the long-term viability of that asset and that location. So each very much site or project specific, but now we hit on all of those points when we look at the evaluation as to whether we even go forward in looking at an asset.
spk11: I appreciate that, Geller. Very helpful. And then maybe moving over to the renewable side, in the prepared remarks, you mentioned that a number of the projects under development have enough time left until they're commissioned to miss some of the challenges we're seeing in the supply chains right now. Is this, for the next tranche of renewable projects, is this slowing down discussions with customers, or is the backlog of counterparties willing to backstop EPAs still quite strong?
spk07: Well, it's caused, there is a bit of a pause right now, and it's a combination of things. One, of course, is, you know, what's happening with the Biden administration, you know, in the United States. and what's the outlook going to be for various credits, tax credits, et cetera. So that's creating, I think, a significant slowdown in terms of elements being transacted. Not necessarily slowing down some of the discussions, but I think before you'll see an awful lot of triggers pulled, there'll be a little bit more certainty come into the market. From a pricing perspective, you can acquire or get commitments around price out two or three years, which are tending to be a little bit lower than current pricing or today's pricing. We expect that that will soften. And as the market becomes clearer and clearer, I think you'll see, again, a tendency for there to be more contracting taking place. So I'd suggest there's a bit of a slowdown for a couple of months, but certainly by mid-year and thereafter, you'll see some acceleration in renewable opportunities in the U.S. In Canada, it's more on a province-by-province basis in terms of what's being offered by the utilities or by the provinces in terms of renewable projects. Alberta continues to be the same. We see it as an excellent place to continue to invest in. We've been very successful on gaining contracts on our renewable projects, even though, as we've said over and over, we're comfortable with them in a merchant perspective. But, you know, the contracting of even our remaining position with the renewables at this point is very positive. So things look very good from the renewable perspective.
spk11: Appreciate that, Clark. Thank you.
spk01: The next question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
spk10: Maurice Choi Thank you. Thank you, and good morning. My first question, just to pick up on the discussion on CCS. In addition to First Nations, what are you hoping other potential partners bring to the table? And a follow-up to that, on timing, what could lead to an FID coming in earlier than mid-2023?
spk07: So in terms of what would we see in a partner, I mean, we would look firstly to a strategic partner, somebody who brings more to the table than simply capital. And, you know, you can see that from a technology perspective, you know, Mitsubishi, for example, would be one or, you know, there's a number of engineering firms who are very much committed to this line of development and in fact, do have capital that they'd like to deploy. There's also organizations who would be very interested in continuing down investments in CCS. Enbridge, for example, would be one organization. But there's other organizations out there who are very interested in being part of, I'll call it part of the action. And then, of course, there's financial players who would look at it as a positive investment given what it's achieving. But again, they would not necessarily bring anything to the table other than capital. And I should be clear, we've had no discussions so far with anybody. And that brings us maybe to your second question about timing and moving forward. we see as a major date, a major milestone for us being when the federal budget comes out and what it has in terms of magnitude and parameters around the investment tax credit. Everything we are understanding and there's nothing set in stone or committed or anything, but it seems like that will be a positive outcome from our perspective. And that's when we'll start getting into more and more discussions around specific partnerships, et cetera. In terms of advancing the date in which we move forward on it, the major issue that we have right now is more around the hub process is not advancing as quickly as we had anticipated. you know, initially the expectation, and it was a broad expectation is that, you know, there'd be, uh, the government would be looking at a number of different hubs sort of at the same time. And, um, what's happened is that there's been an overwhelming response and they anticipated a very, uh, much more significant of a response than they expected, you know, with, with the first tranche. And so they've had to, they, they just don't have the capacity. to analyze these at the same time. So they're putting them in an order in which the Enbridge project has not come forward yet for assessment, or more appropriately put, any of those projects that are west of Edmonton have not been asked for by the government to be assessed. That's slow things down by you know a few months we could see that move ahead, you know fairly quickly. We believe the with the bridge is putting forth extremely straightforward extremely clean excellent excellent project. The other thing though that enters into the hub side of it is there are some fairly significant geological expenditures to be made. and it would be prudent that those expenditures take place once there's a greater degree of certainty in terms of processes going forward. So a lot of that work we see now probably being pushed into next year and potentially being complete by mid-year next year. Now, all of that could be advanced if there was a drive to, As we see it and there's still even you know we could even with the extension of the plan and it's possible to you know be complete in 2026 it starts you know pushing off to be more like you know reading reaching completion in 2027 having said that That's well in advance of achieving provincial and federal targets in advance of 2030. We actually have a lot of time at the back end, so don't want to do anything imprudent at the front end or get over our skis as we move forward. Pretty firm on what we need to be seeing and Things are lining up, albeit with a slight delay, with those things coming to fruition.
spk10: Thanks, and that dovetails quite nicely into my next question about capital allocation. You obviously mentioned earlier that you are encouraged by the level of activity you see in the midlife gas generation market. You have this $2 billion project related to CCS, and you also mentioned that you may move forward with one more renewable project this year. Have you considered revisiting the potential of selling a portion of your renewables to fund all of these, noting, too, that you also turned off your drip last quarter?
spk07: So maybe I'll start, and Sandra, you know, certainly follow up. You know, definitely when it comes to looking at new capital requirements, I think as Sandra said, you know, we're sitting quite well right now. in terms of our capital requirements. But all the time, we look at turning over capital. Are there assets that we should be selling and creating liquidity events and utilizing those funds? So that's always on the table. A lot of it is dependent on our outlook for growth and you know, the deployment of that capital versus and realization of that capital versus, you know, what our other alternatives are. But, you know, that's always on the table and that's always something that's actively discussed.
spk06: Yeah, I don't have anything really to add to that at this point when we're looking at funding our growth between internally generated cash flow and the strength of the balance sheet. We're really not in a position where we're looking at raising equity or doing a type of a sell-down, you'll remember that of our renewable growth, a portion of that is the U.S. solar. So part of that funding will come through investment tax credits as well. So at this point, we're not finding ourselves having to look at that as an option. But as Brian mentioned, it's always on the table.
spk07: And I think one of the things maybe to bear in mind, and that's where the magnitude of the tax credit information that will be coming out hopefully in March, that can have a very significant impact on the net capital cost of the $1.8 to $2 billion. And then if you take into consideration partners on top of that, you know, it's not as daunting as it looks from a headline perspective.
spk10: That makes sense. Thank you very much.
spk01: The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
spk04: Thank you. Good morning. Just with the Alberta budget coming out later today, Brian, can you just remind us what else you need to see in terms of provincial government support, you know, on top of Enbridge being awarded the sequestration rights, of course, but just more from an economic perspective, what provincial clarity or policy milestones should we be watching out for?
spk07: So, you know, certainly there can be surprises from, you know, whether it be federal or provincial governments that create problems for us moving forward. We don't anticipate any and we're not thinking of any, but that's always a possibility. But from what we see and what we kind of understand, from a financial perspective, a pure financial perspective, we are anticipating that between the support from the Canadian Infrastructure Bank the tax credit, the investment tax credit that we believe might be available to us. We don't think there's much more needed from a quote-unquote financial perspective. What is important, though, at this juncture and what we need to see is some de-risking of the carbon credit environment, whether that be in the form of contract for differences, whether that be in the form of, you know, other different kinds of instruments that create some higher degree of certainty around that cash flow. And, you know, as I indicated, you know, it seems like the governments are very much aware of it. They understand. And I think as, you know, the banking community also represents that's a That's a very, very significant and a bit of an extraordinary risk for the magnitude of the investments that are being made. So I believe the governments are sympathetic. What that translates into, and whether it's from the federal perspective or from the provincial perspective, we're talking to both governments about the need for something. and talked a little bit about some mechanisms that we think might work and do believe it's in active discussion, at least from a federal perspective. We don't see that it should come out in terms of regulation. We have a bit of a challenge with anything, if it's in regulation and you're hoping that it stays pat for 20 years, that's not necessarily the case. We would actually be looking for something that would be contractual as opposed to regulatory to provide that extra degree of comfort. So much like what was our insistence with the provincial, Alberta provincial government in negotiating the off-coal arrangements, we weren't satisfied with it being in regulation, needed to be by contract. And we see the same sort of from the greater assurance from the carbon risk perspective.
spk04: Okay, great. Thanks for that. That's helpful. Maybe for Sandra, the 72% hedged position for this year in the high $60 range versus, I guess, forward prices still in the mid-90s, is that relatively higher percentage of baseload sold forward more of a function of being able to lock in your natural gas requirements below market? Or is it perhaps more reflective of a view that you think the forward curve doesn't reflect reality and that as we get into the peak summer months, you would expect spot prices to settle much lower?
spk06: It's sort of a combination of things. Firstly, when you're looking at that 72%, over 40% sold Over 40% in total of the 100% of baseload are long-duration contracts, so some of those are quite far out. That was done intentionally when we realized we were in a period of very high prices in 2021 and 2022, but with supply coming on in a couple of years, we expect those prices to come down. So given the amount of incremental length that we have with the Genesee 1 and 2, it was prudent in our perspective to take on those longer term contracts and lock in that length. So when you're looking at just the hedging for 2022 only contracts, we're only 32% hedged. And that's in the low $80 per megawatt hour range. So you have to appreciate that as we step into hedge positions, Over time, the forward price has sort of moved up to where it is now in the high 90s. And, you know, so we continue to look at hedges of the book. But what's really driving that relatively higher hedge position are the longer-term duration contracts that do have a lower price. So they would be contracted at a level that would be more representative of the long-term forwards versus the current year forwards.
spk04: Okay, that makes sense. Thank you. And last one for me, just curious if you're experiencing any inflationary pressures on your maintenance activities or if you've been able to mitigate the risk around your sustaining CapEx guidance for the year. And then also maybe you could just dovetail in a quick comment on how we should be thinking about your O&M in general, just across your entire contracted fleet elsewhere outside of Alberta.
spk06: Go ahead, Brian.
spk07: No, go ahead, Sandra.
spk06: So I was going to say on the maintenance side, our LTSAs are quite insulated from the impacts of inflation. So we are seeing that we don't have a lot of risk from that perspective. So all in all, we see a fairly mitigated exposure to inflation overall.
spk07: I was going to add that how we see the operating maintenance costs line up for this year and beyond is with a lot of the work that we've done last year and some of the work we're anticipating doing this year, it actually positions us for a lower spend. So we see that as being positive, and I think we went through that during our investor day. In terms of inflation, a lot of the activities associated with outages and just ongoing maintenance activity is labor related. And so it more is driven by what are the union contracts and also availability of labor as we move forward in the various regions. So that's a very significant component of our costs and We don't see that, although rising, we don't see it getting too far out of control. Not like what we've seen on steel prices and other things that have gone up quite a bit, but of course they're coming down right now as we speak. So do not expect inflation to have a significant impact on our costs going forward.
spk04: Okay, that's great. Thank you.
spk01: The next question comes from John Mould with TD Securities. Please go ahead.
spk03: Hi, everybody. Thanks for taking my question. You know, really just, I guess, one broad one on the carbon side as we're going through some fairly large policy reviews, I think, over the next few months. I'm just wondering what your current, you know, base case assumptions are for Alberta specifically. on the tier review and how you expect or how you think that might unfold in the context of, of the federal backstop as it's currently constituted. And then how you're thinking about the, the clean electricity standard more broadly. Um, and I appreciate we, you know, we don't have that policy yet, but I think we've got the contours at least, um, including in, in, uh, Ontario, you know, outside of, of the assets for long Genesee specifically, I guess, where you're looking at, uh, significant carbon abatement. Can you maybe just tackle those two bigger picture topics?
spk07: So I think from an Alberta perspective, you know, what we see is, you know, the Alberta government very much committed to continue with the tier process, i.e. having its own regime. and as it moves forward with negotiating those agreements with the federal government, of course, needs to be aware of and so on of whatever changing federal policies there may be around carbon and various standards. We do believe that the Alberta government sees that the current intensity, the 0.37, is where it should be and would endeavor to be maintaining that through to 2030. And again, we'll see when it comes to discussions and negotiations. But we see, and it goes to an earlier question, we do see that the Alberta price for carbon will keep lockstep with what happens from a federal perspective. So that's one element of negotiation and commonality between the federal backstop and what we would see in Alberta. The biggest issue, of course, is what happens in regards to the oil and gas industry. So from that perspective, not sure what's going to happen there. And again, that's where there'll be, we believe, the focus of discussions. And from an Ontario perspective, You know, in Ontario, you know, our assets, generally the implications of carbon tend to be borne by the ISO who holds, who is the counterparty on the contract. It's not perfect, but in terms of being, you know, perfectly covered, but, you know, I think in all material respects, it's generally covered there. The interesting thing about an escalating carbon price is that depending on where your asset is in the queue and how efficient it is, it generally drives less efficient assets or dispatch less, and more efficient assets, of course, are dispatched more. So what we see in Alberta and what we're expecting in other jurisdictions is that as there may be escalating carbon prices, generally our assets are called on more. as opposed to less. So we don't necessarily see escalating carbon prices as being negative as we move forward.
spk03: Okay. I will leave it there. Thanks very much for that detail.
spk01: The next question comes from Andrew Kuski with Credit Suisse. Please go ahead.
spk02: Thanks. Good morning. I think in your slide deck, you had language around islands and stating an intent to aggressively intervene in the BCUC process. I guess, is there just a bigger picture issue with the way that BC Hydra's behaved in relation to island that the bigger issue is really their PowerX's marketing license? If there's not a functional market within British Columbia, doesn't that create a bigger problem And so is the question really, you ultimately probably wind up with some fair resolution of this?
spk07: You know, not really fully aware of, you know, all of BC Hydro's motivations and, you know, how much PowerX plays into it and PowerX considerations. You know, right now they do have a definitive need for a greater security on the island because of the work they're going to be doing on the transmission lines. And again, the work they do is not actually going to increase the capacity. It's just going to be increasing the reliability. So again, not sure if it's actually going to solve the island problems. Our biggest challenge, I would say, has been that You know, what we have gone through and, you know, if you look back at the previous IRP and the one before that, there has tended to be a lot more information, a lot more disclosure around just the underlying data that, you know, transmission experts could look at and analyze and, you know, either agree or disagree. What we've substantially gone on is the fact that, you know, we've been dispatched pretty regularly and, There's been no increase in capacity. There's an increase in demand on the island. Everything points to not only the historical need being there, but an enhanced need going forward. And it's the lack of data, the lack of transparency that has been a problem thus far. Now, we expect to overcome that through the BCUC process, through information requests and so on. we should be able to get at that data and determine whether or not we think it's, well, bluntly right now, we think they're planning, they've got a degree of brownouts on the island that they believe is acceptable. We don't see that there's any other logical answer to that situation, but obviously they're not disclosing that publicly to any great degree.
spk02: Okay, that's very helpful context on things. And then the second question is really around, historically, your construction expertise has been quite favorable, and you've managed to deliver a number of projects within tight timelines and within budget, in part because of the construction expertise. How do you look at that as a competitive advantage going forward? And can you scale it if you wanted to deploy more capital into the market or feel you're in the right kind of spot right now for building new things?
spk07: So it depends. That all depends on the new things that you're referring to. You know, when it comes to, so for example, with the repowering that's taking place now, and, you know, we don't talk about it a lot, but, you know, for example, you know, where we are now on that project in one year is typically where organizations are in two years. you know, we compress the front end of that project considerably and we're, you know, and we are, you know, meeting our milestones. And I think, you know, it creates that ability to move quite quickly, you know, through construction. And so, you know, on a major project, that takes a lot of effort out of the organization, you know, with the repowering. If you're looking at a wind farm or a solar facility, we do and continue to do things a bit differently than many others. And what we learn or what we developed with one solar facility or one wind facility, we're able to apply that just as part of the way we do things. So our ability to build a significant number of wind or solar facilities is definitely there. You know, we can greatly expand from a couple of a year to, you know, to a handful to, you know, again, in time, you know, much beyond that. So from a renewable perspective, you know, I think we have great, great capacity to build, you know, at the same time, a number of facilities.
spk02: Thanks, Brian. That's very helpful.
spk01: The next question comes from Mark Jarvie with CIBC Capital Markets. Please go ahead.
spk09: Thanks, everyone. Just coming back to the carbon capture storage project, you talked about infrastructure bank, First Nations involvement, strategics. How low a percentage could you be? Is there a minimum that you want to be in terms of economic participation or at the same time, is there sort of a sweet spot in terms of specific target you're looking for in terms of ownership.
spk07: I would say we would you know unless there's extraordinary circumstances. I think we want to retain you know at least 50% of the of the project so that's I think that that would be kind of the line that we would start off looking at partners and you know of course would would come First Nations but For example, if there was a 10% interest by the First Nations, maybe the other two partners are 45, you know, ourselves and somebody else is 45% each. You know, a lot will just depend on governance and other issues that drive that. But somewhere around 50% would probably be the sweet spot.
spk09: So when you're saying 50%, are you thinking the King infrastructure bank is providing sort of a loan and therefore it's sort of that net X, the loan from King infrastructure bank, or how do we think about that part of the capital?
spk07: No, no, I'm, I'm speaking more in terms of just, you know, if you look at what, what, uh, you know, uh, ownership interest, you know, of capital powers would be in the order of, you know, somewhere in the zone of, of say 50%, uh, in terms of the, um, into the canadian infrastructure bank you know they have you know guidelines and direction and and you know what they would be so potentially willing to to support or fund um which which you know would not be you know the entire uh i'll call debt check for the project and of course any funding associated with first nations would be would be coming out of other areas of the federal or provincial governments. So there would definitely be a need for public debt financing on the project. It may well be project financing associated with it. Again, depending on partners and approach, you'd probably see a combination of Canadian infrastructure bank support plus more traditional debt.
spk09: And then just coming back to the Enbridge hub, it seems that you still think that's going to go through, but if for some reason it didn't, what's plan B then in terms of that component?
spk07: You know, the issue is finding, you know, the appropriate geological site. And for example, I would say right now, if Enbridge decided for whatever strategic reason or whatever to not move forward and it was, you know, and there was no technical reason there was a problem with the site, we'd just take it over. It's relatively small compared to the CCS investment that we're looking at. So we just take it over and either look for somebody You know, one of the other you know pipeline organizations that would be happy to take it on or or again you know do it ourselves if it was a technical reason. That technical reason being more geological there just be we'd look quickly for an additional geological site that was relatively close at hand and. You know, the Alberta geology is blessed with a lot of potential pore space. So don't believe that that would be necessarily a huge problem.
spk09: Okay. And then one last question. Just on the gas hedges, you're highly hedged for your base load. If you did have something like an unplanned outage, like you saw at Genesee, what risk or how would you deal with that? Could you just use the gas at other sort of dispatchable facilities? Would you just resell the gas? Just being any risks around being highly hedged on the gas side?
spk06: Yeah, we would be able to sell the gas or redeploy it. So very, very minimal risk there, given the contract price that we have for those contracts.
spk09: And did you do that in the past year, given the Genesee 2 outage?
spk06: We would have had, at times, there would have been some shape to it. So yeah, there would have been some opportunity to lay some of that off, for sure.
spk09: And generally, do you? Net out positive on those? Correct. Yeah. Okay. Perfect. Thank you.
spk01: Once again, if you have a question, please press star, then one. The next question comes from Najee Beydoun with IA Capital Markets. Please go ahead. Hi.
spk08: Just a couple of questions. starting with the Genesee CCS project. I mean, it seems like clearly that the next phase of the evolution of capital power, I'm just wondering, you know, if that project doesn't move ahead or if it has to be materially altered, what are some different options that you're thinking about in terms of other capital allocation priorities? You touched a bit on M&A, but maybe a bit more color on that and more details on organic growth would be helpful.
spk07: So as we look at that project, obviously, if it moved forward, it would have a bit of an impact of limiting what else capital power could do. I mean, we still could have a significant growth in renewables and acquisitions over that time period, but certainly would decrease the overall appetite. So what I'd say is that we would um, continue to look at, um, you know, growth in renewables. Um, we'd see, you know, potentially some additional, you know, natural gas acquisitions, although, you know, although, you know, we're seeing a lot of activity now and, and, you know, we expect a lot of activity next year. Um, we do expect that, you know, in time, those opportunities. And when you think of them, you know, midlife natural gas assets with, you know, significant contracts associated with them, those are going to become fewer and farther between. So don't anticipate, say, in the last part of this decade, you'd see a lot of activity on that front, more so in the early part of this decade. So you would see a lot of the growth, if not, in some years, all the growth coming from renewables.
spk08: Okay, that's very helpful. And just maybe tied to your previous comments on, you know, competitive edge with the Gen S3 power rings, I suppose you're not really considering acquiring other thermal assets and applying that same experience and knowledge to transition them to more efficient or lower carbon assets.
spk07: You know, that's certainly something to, you know, think about, you know, in the future. And I would say, you know, a couple years from now, you know, with some success, you know, with Genesee or at least moving, you know, well down the road, you know, that may be something to look at. And certainly in the United States, there's a growing recognition of the need for CCUS. So, you know, we'd see, you know, there may be some of those kinds of opportunities that might open up for us where, you know, we might, you know, apply expertise to a relatively new natural gas facility. And again, in the U.S., even in Alberta, when we look at it and we look at Genesee 3, you know, we would anticipate at some time it would make sense to potentially repower it. and apply CCUS, particularly when the infrastructure's in place. So, you know, there are those kinds of opportunities that, you know, may be out there. We, at this point, aren't seeing that as, again, other than the Genesee 3, we're not seeing that as something that's kind of on the radar screen, but it definitely has some potential in the future. Okay, that's it. Thank you.
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.
spk05: 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.
spk01: This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.
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