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 Vaasjo, 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 are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP, and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures to their nearest GAAP measures are disclosed in our 2021 integrated annual report. I will now turn the call over to Brian for his remarks, starting on slide 4.
Thanks, Randy, and good morning. Capital 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 Genesee 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 5 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 MW 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 6-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. Whitla became the largest wind facility in Alberta at 353 MW when phases 2 and 3 were completed ahead of schedule in early December and below budget. We executed 15-year renewable contracts with both Labatt Breweries and Dow Chemical to help them reach their sustainability goals through customized renewable energy solutions.
Demand for renewable contracts for us continues to be very positive. Build-out of our Alberta renewable assets continues with our latest project, Halkirk 2, a 150MW wind farm that is adjacent to our existing Halkirk 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 our roadmap to decarbonization. Turning to slide 6. 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 7. We are committed to be carbon neutral by 2050 and have a clear pathway that includes setting targets along that pathway. We have 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 wellbeing.
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 CCUS 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 8.
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 CAD 1.8 billion-CAD 2.0 billion carbon capture project will come from both federal and provincial governments. We're in discussions with the Canada 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 CCUS.
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.
Thanks, Brian. On slide 9 , I'll touch on the financial highlights for 2021. As mentioned, we set an annual record for both adjusted EBITDA and AFFO 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 5-year average and exceeding our target TSR of 10%-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 CAD 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 flows. Slide 10 shows year-over-year financial performance for the fourth quarter and for the full year of 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 CAD 1.99 billion in 2021 compared to CAD 1.937 billion in 2020. Both adjusted EBITDA and AFFO exceeded the midpoints of our higher revised guidance. Adjusted EBITDA was CAD 1.124 billion, an 18% increase compared to CAD 955 million in 2020. AFFO was CAD 605 million in 2021, a 16% increase compared to CAD 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 CAD 102 per megawatt hour in the year.
Whitla 2 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 CAD 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 B.C. 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 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 4-year contract extension, a CAD 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 a 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 CAD 102 per MWh, compared to CAD 47 per MWh in 2020. The slide shows our hedge positions for power and natural gas.
You will note that we have increased our hedge positions for 2022-2024 since our disclosure at Investor Day on December 2. For 2022, we entered the year 72% hedged in the high CAD 60 per MWh range. In 2023, we are 47% hedged in the low CAD 60 per MWh range. For 2024, we are 32% hedged in the high CAD 50 per MWh . This compares to forward prices of CAD 94 per MWh, CAD 72 per MWh and CAD 61 per MWh for 2022-2024 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 1 year in term, many of which are 3-5 years or longer in duration. The long-term hedges have an average price in the low CAD 60 per MWh 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 CAD 2.00 and CAD 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 CAD 1.11 billion-CAD 1.16 billion in adjusted EBITDA and CAD 580 million-CAD 630 million in AFFO.
We have looked at the impact 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 for the Genesee Repowering. With the delayed COD of the North Carolina solar project 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 financings 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 CAD 105 million and CAD 115 million , which is well above the forecast of CAD 55 million to CAD 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. Finally, we continue to target CAD 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.
All right, thanks, Sandra. Thérèse, we're ready to take questions.
Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. The first question comes from Robert Hope with Scotiabank. Please go ahead.
Good afternoon, everyone. Just to maybe a longer-term strategic question. Just on the natural gas midlife generation side, you know, what are you seeing out there in terms of opportunities? As you evaluate these opportunities, how does the ability to kind of reduce carbon at the sites or, you know, co-locate renewables or batteries fit into the investment decision?
Good afternoon. 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. 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. 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. You know, that's sort of a first hurdle.
We look at it in terms of in part of, you know, our optimism around recontracting or lack thereof would depend on how it's strategically positioned. We've been looking at, you know, a number of assets that are just so-called simple generation assets and create energy, but those are readily displaced by renewables and would have a relatively shorter history. Those assets that are, you know, on the grid in 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 those storage capability, you know, realized at those sites.
There's a number of things that we look at, and certainly the carbon outlook for each facility is looked at very, very closely and how it impacts on our targets. You know, what we see is the long-term viability of that asset and that location. Each very much site or project specific. Yeah, 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.
I appreciate, color. Very helpful. Maybe moving over to the renewable side. In the prepared remarks, you mentioned that, you know, a number of the projects under development, you know, have enough kinda 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 PPAs still quite strong?
Well, 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, you know, what's the outlook gonna be for, you know, various credits, tax credits, et cetera. That's creating, I think, a significant slowdown in terms of elements being transacted, not necessarily, you know, slowing down, you know, some of the discussions. I think before you'll see an awful lot of triggers pulled. You know, there'll be a little bit more certainty, you know, come into the market.
From a pricing perspective, you know, get commitments around price out, you know, two or three years, which are tending to be a little bit lower than current pricing or today's pricing. We expect that will soften. As the market becomes clearer and clearer, I think you'll see again a tendency for there to be more contracting taking place. 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 the renewable projects.
In Alberta continues to be the same. We see it as an excellent place to continue to invest, and 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. You know, the contracting of even our remaining position with the renewables at this point is very positive. Things look very good from the renewable perspective.
Appreciate the color. Thank you.
The next question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
Thank you. Thank you, and good morning. My first question, just to pick up on the discussion on CCUS. In addition to First Nations, what are you hoping other potential partners bring to the table? A follow up to that, on timing, what could lead to an FID coming in earlier than mid-2023?
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. You know, you can see that from a technology perspective. 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, you know, do have capital that they'd like to deploy. There's also, you know, organizations who would be very interested in, you know, continuing down investments in CCUS. You know, 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.
Then of course, there's financial players who would look at it as a, you know, a positive investment given what it's achieving. Again, you know, that they would not necessarily bring anything to the table other than capital. I should be clear, we've had no discussions so far with anybody. That brings us maybe to your second question about, you know, timing and moving forward. We see as a major date, a major milestone for us being, you know, when the federal budget comes out and what it has in terms of, you know, 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.
That's when we'll start being, you know, getting into more and more discussions around, you know, specific partnerships, etc . 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 the government would be looking at a number of different hubs sort of at the same time. What's happened is that there's been an overwhelming response, and they anticipated a very much more significant response than they expected, you know, with the first tranche. They've had to
They just don't have the capacity to analyze these at the same time. They're putting them in an order in which the Enbridge project has not come forward yet for assessment or maybe probably more appropriately put, you know, any of those projects that are west of Edmonton have not been, you know, asked for by the government to be assessed. That's slowed things down by, you know, a few months. We could see that move ahead, you know, fairly quickly. We believe what Enbridge is putting forth extremely straightforward, extremely clean, 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.
You know, 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, but as we see it, and it is still even, you know, we could even with the extension of the planning, it's possible to, you know, be complete in 2026. It starts, you know, pushing off to being more like, you know, really reaching the completion in 2027.
Having said that's well in advance of you know achieving provincial and federal targets in advance of 2030. We actually have a lot of time at the back end. Don't want to do anything imprudent at the front end or get you know 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.
Thanks. 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 mid-life gas generation market. You have this CAD 2 billion project related to CCUS, 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 a DRIP last quarter?
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 has said, you know, we're sitting quite well right now, in terms of our capital requirements. But you know, all the time we look at, you know, turning over capital, you know, are there assets that we should be selling? And you know, creating, you know, liquidity events and utilizing those funds. That's always on the table. A lot of it is dependent on, you know, 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.
you know, that's always on the table, and that's always something that's actively discussed.
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, you know, 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 as having to look at that as an option, but as Brian mentioned, it's always on the table.
Yeah. I think one of the things maybe to bear in mind, and that's where the magnitude of this tax credit information that'll be coming out, you know, hopefully in March, that can have a very significant impact on the net capital cost of the CAD 1.8 billion-CAD 2.0 billion . Then if you take into consideration, you know, partners on top of that, you know, it's not as daunting as it looks from a headline perspective.
That makes sense. Thank you very much.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
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?
When you know, certainly there can be surprises from you know, from 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. From what we see and what we kind of understand, you know, from a financial perspective and a pure financial perspective, you know, we are anticipating that between the support from the Canada 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.
You know, whether that be in the form of contract for difference, 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. You know, as I indicated, you know, it seems like the governments are very much aware of it. They understand. I think as you know, the banking community also represents that that's a very significant and a bit of an extraordinary risk for the magnitude of the investments that are being made. Believe the governments are sympathetic.
You know, what that translates into and whether it's at the federal, provincial, from the federal perspective or from the provincial perspective, you know, we're talking to both governments about, you know, the need for something and talked a little bit about, you know, some mechanisms that we think, you know, might work and, you know, 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, you know, if it's in regulation and you're hoping that it stays pat for 20 years, that's not necessarily the case. We'd actually be looking for something that would be contractual as opposed to regulatory to provide that, you know, extra degree of comfort.
Much like, you know, what was our insistence with the provincial Alberta government in negotiating the off-coal arrangements, we're satisfied with it being in regulation. It needed to be by contract. We see the same sort of approach from the greater assurance from the carbon risk perspective.
Okay, great. Thanks for that. That's helpful. Maybe for Sandra, the 72% hedged position for this year, you know, in the high $60 per MWh range versus, I guess, forward prices still in the mid-$90 per MWh. Is that relatively higher percentage of base load 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 know, you think the forward curve doesn't reflect reality and that, you know, as we get into the peak summer months, you would expect spot prices to settle much lower?
It's sort of a combination of things. Firstly, when you're looking at that 72%, over 40%, so over 40% in total of the 100% of base load are long duration contracts. 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 years, we expect those prices to come down. 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 long- term contracts and lock in that length.
When you're looking at just the hedging for 2022 only contracts, we're only 32% hedged, and that's in the low CAD 80 per MWh range. You have to appreciate that as we step into hedge side, our LTSAs are quite insulated from the impacts of inflation. We are seeing that we don't have a lot of risk from that perspective. All in all, we see a fairly mitigated exposure to inflation overall.
Yeah, I was gonna add that, you know, how we see, you know, the maintenance operating maintenance costs line up for this year and beyond is, you know, 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. We see that as being positive, and I think we went through that, you know, during our investor day. In terms of inflation, a lot of the activities associated with outages and just ongoing maintenance activity is labor related.
You know, it more is driven by, you know, what are the union contracts and also the availability of labor, as we move forward in various regions. 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 have, you know, gone up quite a bit. Of course, you know, they're coming down right now as we speak. You know, do not expect inflation to have a significant impact on our costs going forward.
Okay. That's great. Thank you.
The next question comes from John Mould with TD Securities. Please go ahead.
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 the federal backstop as it's currently constituted. How you're thinking about the clean electricity standard more broadly. I appreciate, you know, we don't have that policy yet, but I think we've got the contours at least. Including in Ontario, you know, outside of the assets where Genesee specifically, I guess, where you're looking at significant carbon abatement.
Can you maybe just tackle those two bigger picture topics?
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. You know, as it moves forward with negotiating those agreements with the federal government, of course, needs to be aware of and so on, of the whatever changing federal policies there may be around carbon and, you know, various standards. We do believe that the Alberta government sees that, you know, the current intensity, the 0.37, is where it should be and would endeavor to be maintaining that through to 2030. Again, we'll see when it comes to discussions and negotiations.
You know, 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. That's one element of negotiation and what we would see in Alberta. The biggest issue, of course, is you know what happens in regards to you know the oil and gas industry. From that perspective, not sure what's gonna happen there. Again, that's where there'll be, we believe the focus of discussions. From an Ontario perspective, you know, in Ontario, you know, our assets generally the implications of carbon tend to be borne by the IESO, who is the counterparty on the contract.
It's not perfect, but in terms of being, you know, perfectly covered. 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 more dispatch more. You know, what we see in Alberta and what we would expect in other jurisdictions and that as, you know, there may be, you know, escalating carbon prices, generally, our assets are called on more as opposed to less. You know, we don't necessarily see escalating carbon prices as being negative as we move forward.
Okay. I will leave it there. Thanks very much for that detail.
The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thanks. Good morning. I think in your slide deck you had language around Island 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 Hydro's behaved in relation to Island that, you know, the bigger issue is really their Powerex or marketing license. If there's not a functional market within British Columbia, doesn't that create a bigger problem? Is the question really you ultimately probably wind up with some fair resolution of this?
Not really fully aware of, you know, all of BC Hydro's motivations and you know, how much Powerex plays into it and Powerex considerations. Right now they do have a definitive need for a greater security on the island because of the work they're gonna be doing on the transmission lines. The work they do is not actually gonna increase the capacity, it's just gonna be increasing the reliability. Again, not sure if you know, it's actually gonna solve the island problems.
You know, 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. There's been no increase in capacity. There's an increase in demand on the island. You know, everything points to not only the historical need being there, but an enhanced need going forward.
It's that 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, you know, through information requests and so on. We should be able to get at that data and determine, you know, whether or not, you know, 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. Obviously they're not disclosing that, you know, publicly to any great degree.
Okay. That's very helpful context on things. Then the second question is really around, you know, historically your construction activity has been, you know, quite favorable, and you've managed to deliver a number of projects, you know, within these tight timelines and within budget, in part because of the construction expertise. How do you look at that as a competitive advantage going forward? Can you scale it if you wanted to deploy more capital into the market? Or do you feel you're in the right kind of spot right now for building new things?
It depends. That all depends on the new things that you're referring to. You know, when it comes to, 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 are, you know, meeting our milestones. I think, you know, it creates that ability to move quite quickly, you know, through construction.
You know, that 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, you know, and continue to do things a bit differently than many others. 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. Our ability to build a significant number of wind or solar facilities is definitely there. You know, we can greatly expand from a couple a year to a handful to, you know, again, in time, you know, much beyond that.
I think from a renewable perspective, you know, I think we have great capacity to build, you know, at the same time, a number of facilities.
Thanks, Brian. That's very helpful.
The next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead.
Thanks, everyone. Just coming back to the carbon capture storage project. You talked about Canada Infrastructure Bank, First Nations involvement, strategics. Just wondering how low a percentage could you be? Is there a minimum that you wanna be in terms of economic participation? Or, and at the same time, is there sort of a sweet spot in terms of a specific target you're looking for in terms of ownership?
I would say we would, you know, unless there's extraordinary circumstances, I think we'd want to retain, you know, at least 50% of the project. That's the line that we would start off looking at partners and, you know, out of that, of course, would come First Nations. 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. Somewhere around 50% would probably be the sweet spot.
When you're saying 50%, are you thinking the Canada Infrastructure Bank is providing sort of a loan, and therefore it's sort of a net ex the loan from Canada Infrastructure Bank? Or how do we think of that part of the capital contribution?
No, I'm speaking more in terms of just, you know, if you look at what, you know, our ownership interest, you know, of capital partners would be in the order of, you know, somewhere in the zone of, say, 50%. In terms of the, in terms of the Canada Infrastructure Bank, you know, they have, you know, guidelines and direction and, you know, what they would be, you know, potentially willing to support or fund, which, you know, would not be, you know, the entire, I'll call it debt check for the project. Of course, any funding associated with First Nations would be coming out of other areas of the federal or provincial government. There'd 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 Canada Infrastructure Bank support plus more traditional debt.
Then just coming back to the Enbridge hub, it seems like you still think that's gonna go through, but if for some reason it didn't, what's plan B then in terms of that component?
You know, the issue is finding, you know, the appropriate geological site. 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 CCUS investment that we're looking at. We'd 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 again, you know, do it ourselves.
If it was a technical reason, and that technical reason being more geological, it'd 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 would be necessarily a huge problem.
Okay. 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, like 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? Is there any risks around being highly hedged on the gas side?
Yeah, we would be able to sell the gas or redeploy it. Very minimal risk there given the contract price that we have for those contracts.
Did you do that in the past year during the Genesee 2 outage?
We would have had at times there would have been some shape to it. Yeah, there would have been some opportunity to lay some of that off for sure. Yeah.
Generally, do you net out positive on those?
Correct.
Yeah. Okay, perfect. Thanks, everyone.
Once again, if you have a question, please press star then one. The next question comes from Naji Baydoun with iA Capital Markets. Please go ahead.
Hi. Just a couple of questions. Starting with the Genesee CCUS 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.
As we look at that project, obviously, you know, if it moved forward, it would have a bit of an impact of, you know, limiting, you know, what else, you know, Capital Power could do. I mean, we still could, you know, have a significant growth in renewables and, you know, acquisitions over that time period. Certainly, you know, would decrease the overall appetite. What I'd say is that we would continue to look at, you know, growth in renewables. We'd see, you know, potentially some additional, you know, natural gas acquisitions, although, you know, we're seeing a lot of activity now and, you know, we expect a lot of activity next year.
We do expect that, you know, in time those opportunities and when you think of them, you know, mid-life natural gas assets with, you know, significant contracts associated with them, you know, those are gonna become fewer and farther between. Don't anticipate, say, in the last part of this decade you'd see a lot of activity on that front. More so, you know, in the early part of this decade. We would see a lot of the growth, if not in some years, all the growth coming from renewables.
Okay, that's very helpful. Just maybe tied to your previous comments on competitive edge with the Genesee Repowerings. 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.
You know, that's certainly something to think about in the future. I would say a couple of years from now, with some success with Genesee or at least moving well down the road, that may be something to look at. Certainly in the United States, there's a growing recognition of the need for CCUS. We'd see there may be some of those kinds of opportunities that might open up for us, where we might apply expertise to a relatively new natural gas facility. Again, in the U.S.
You know, 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. 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 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.
This concludes the question and answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.
Okay. 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.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.