Welcome to Capital Power's Second Quarter 2021 Results Conference Call. As a reminder, all participants are in listen only mode and the conference call is being recorded today, July 30, 2021. I will now turn the call over to Mr. Randy Maas, the Director of Investor Relations. Please go ahead.
Good morning and thank you for joining us today to review Capital Power's Q2 2021 results, which we released earlier this morning. Our Q2 report and the presentation for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vaageault, President and CEO and Sandra Haskins, Senior Vice President, Finance and CFO. We will start with opening comments and then open the lines to take your questions. Before we start, I would like to remind everyone that certain statements about future events made on 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 as noted on Slide 3. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective.
Reconciliations of these non GAAP financial measures to their nearest GAAP measures can be found in our Q2 2021 MD and A. I will now turn the call over to Brian for his remarks starting on Slide 4.
Thanks, Randy, and good morning. I'll start off with the highlights of the Q2 and comment on our 2021 outlook. We delivered strong second quarter results that significantly exceeded our expectations, largely driven by our performance in Alberta, where the Alberta Power market continues to be robust with a positive outlook. Accordingly, we've updated our 2021 financial guidance, which ranges above the top end of our original targets for adjusted EBITDA and AFFO. Despite the impacts from the Genesee II force outage that started in mid July that I'll comment on shortly.
In line with our dividend growth guidance, we've announced an approximate 7% dividend increase that is effective with the Q3 2021 dividend. We also continue to make solid progress on our approximately $1,700,000,000 in growth projects. As part of our goal to be net carbon neutral by 2,050, we continue to advance our CO2 reduction initiatives. This includes carbon capture and storage at Genesee, where there is significant government support and the development is going very well. For the Genesee Carbon Conversion Center, we continue to investigate the commercial opportunities for carbon nanotubes and board approval for the project facility is expected later this year.
Turning to Slide 5, Genesee II experienced a forced outage in mid July caused by a generator failure. The outage is expected to last 6 weeks with return to operations anticipated in the Q3 of this year. We plan to utilize our Cloverbair peaking facility to partially mitigate the Genesee II impact. The 3 week planned outage for Genesee scheduled for October will be advanced and completed during this outage. Moving to Slide 6, this chart shows our solid track record of dividend growth with 8 consecutive years of dividend increases averaging 7% per year.
As mentioned, we've increased the common share dividend by approximately 7% to $0.219 per year or $2.19 per year starting in the 3rd quarter. We're also maintaining our dividend guidance for a 5% annual increase in 2022. As you can see, the AFFO payout ratio continues to track below our long term payout target of 45% to 55%. Turning to Slide 7. Last month, BC Hydro released its draft integrated resource plan.
In that draft IRP, it stated that BC Hydro is not currently intending to renew the long term electricity purchase agreement Core Island Generation Facility that expires in April of 2022. We are actively participating in the P review process, including retaining technical experts familiar with BC Hydro's utility resource planning and transmission systems operations to support the review of the draft IRP. Comments are due at the end of this month with the final IRP expected to be filed by the end of this year. We are also engaging with BC and local government officials and other stakeholders. We continue to believe Island Generation's dispatchable generation remains critical to the reliability of the BC system, particularly on Vancouver Island, as again shown by recent weather and system events.
With the current transmission difficulties they're experiencing on Vancouver Island, Highland Generation has been Contingorlessly dispatched since July 9. I'll now turn the call over to Sandra.
Thanks, Brian. In the Q2, we completed a successful equity offering of approximately 7,500,000 common shares, including the overallotments that raised gross proceeds of $288,000,000 Following the closing on June 2, share price rebounded from the issue price of $38.45 and is currently trading approximately 9% above the issue price. On the debt side, we executed a US150 $1,000,000 private placement of 12 year senior notes. Notes have a coupon rate of 3.24 percent, which with the inclusion of a forward starting swap settlement that was put in place for the issuance equates to an effective interest rate closer to 2.5%. 12 year notes demonstrates investors' continued confidence in our long term outlook.
Transaction is scheduled to fund in late October to better align with the cash flow profile of our growth projects. We've also had recent affirmations of our investment grade credit ratings and stable outlook by both S and P and DBRS. Earlier this month, we announced the closing of our inaugural $1,000,000,000 sustainability linked credit facilities or SLC. This involved amending our existing credit facilities, including a 2 year extension to transition them into 5 year SLC. Pricing is in line with our pre COVID pricing grid.
The SLCs are structured with 1 KPI tied to our CO2 emission intensity based on annual performance against the target. These financings have reduced the financing risk of our capital program and the need for additional equity offering for current growth projects. Turning to slide 9, the Alberta power market continues to be very robust. Above average temperatures in June contributed to an average power price of $105 per megawatt hour in the second quarter that was 3.5 times higher than the $30 per megawatt hour in the Q2 of 2020. In the Q2, our trading desk captured an average realized price of $75 per megawatt hour or 42% higher than a year ago.
Positive market outlook is reflected in forward prices of approximately $94 per megawatt hour for the last half of the year. For our Alberta commercial portfolio, our base load generation is 42% hedged in 2022 at an average contract price in the high $50 per Megawatt hour range. 2023 2024 were 30% and 15% hedged respectively at an average contract price in the mid $50 per megawatt hour in both years. This compares to current forward prices of $72 per megawatt hour for 20.22 $61 for $2,075 in 2024. On slide 10, I'll review our financial results for the quarter.
As Brian mentioned, financial results compared to budget significantly exceeded our expectations. Adjusted EBITDA was $241,000,000 in the 2nd quarter, up 11% from a year ago. The increase was due to higher Alberta power prices that resulted in a 28% increase in adjusted EBITDA for the Alberta Commercial segment. However, this increase was partially offset by the impact of planned outages at our Decatur and Arlington facilities in the U. S, lower wind resource at most of our wind facilities and a stronger Canadian dollar.
Due to seasonality, the 2nd quarter is generally the lowest quarter for AFFO. This year we generated $91,000,000 in the 2nd quarter, down 6% from a year ago, as stronger plant performance was offset by $11,000,000 of higher sustaining CapEx scheduled in Q2 2021 and the milliner line loss AFFO impact of $7,000,000 in the quarter. AFFO per share of $0.83 was down 10% from the Q2 of 2020. Slide 11 shows our performance for the 1st 6 months. Adjusted EBITDA of $544,000,000 was up 21% compared to $451,000,000 for the same period in 2020.
The main driver for the increase was the higher Alberta power prices where our realized power price was $76 per megawatt hour compared to $58 a megawatt hour a year ago. Lower corporate expenses also contributed to the higher adjusted EBITDA, mainly due to the acceleration of coal compensation revenue. AFFO was $250,000,000 up 16% compared to $215,000,000 a year ago. Higher client performance from strong Alberta results were partially mitigated by higher sustaining CapEx in the 1st 6 months of 2021 $13,000,000 in line no more line loss ruling impacts to AFFO. Overall, we're seeing strong performance in our key financial metrics in the first half of the year.
I'll now turn the call back to Brian.
Thanks, Sandra. Turning to Slide 12, I'll review our performance for the first half of the year compared to 2021 targets. For the 1st 6 months, average availability was 90%, including outages at our Decatur, Arlington and Sheppard facilities. As mentioned, Genesee II is currently offline with a forced outage, but it's not expected to materially impact the 93% annual availability target as Genesee II had a major plant outage scheduled in the Q4 that will no longer be required. Sustaining CapEx was $47,000,000 in the first half of the year compared to the $80,000,000 to $90,000,000 annual target.
Based on our current outlook, we've increased our adjusted EBITDA and AFFO annual targets, largely due to the strength of the Alberta power market. Of note, the updated guidance range is higher than the top end of the original guidance ranges and reflects the estimated impacts from the Genesee II outage. In the 1st 6 months, we reported $544,000,000 in adjusted EBITDA compared to the revised annual target range of $1,090,000,000 to 1,140,000,000 Lastly, we generated $250,000,000 of AFFO compared to the revised $570,000,000 to 620,000,000 annual target range. To wrap up, I'll cover our growth targets as highlighted on Slide 13. We continue to make progress on all of our renewable projects.
This includes developing and constructing 7 renewable projects on budget and on time for commercial operations starting between the Q4 of this year and the Q4 of 2022. For the repowering of Genesee 1 and 2, all regulatory approvals have been received and construction is expected to begin in the Q3 of this year. Targeted operational dates are late 2023 for Genesee 1 and 2024 for Genesee 2. With our major projects underway and the strength of our balance sheet from recent financings and our performance, We are positioned very well to pursue our $500,000,000 committed capital target. This could be continuing to grow our renewable assets and or acquiring midlife contracted natural gas assets.
I'll now turn the call back over to Randy.
All right. Thanks, Brian. Anastasia, we're ready to take questions.
Certainly. We will now begin the question and answer session. We will pause for a moment as callers join the queue. The first question comes from Maurice Choi with RBC Capital Markets. Please go ahead.
Thank you and good morning. Maybe I'll
start off
with a follow-up to one of the points you made in the prepared remarks. You discussed the Genesee Carbon Conversion Center as well as the CUS. More broadly, can you discuss what you need to see in order to commit to these two projects, specifically what is within your control and what isn't? As well, if you could compare the returns from these projects that you expect versus the range of development assets that you currently have on the go that would be great.
Okay. Thank you for the question. In terms of the 2 projects, when we look at CCUS, I'll start with that one, It continues to go well and what we need to see in terms of proceeding It's firstly the government programs that we see and have not changed our view nor has the government changes view in terms of the kinds of support that would be available for this kind of a project. So obviously that needs to come to fruition. And I would say those on those fronts, things continue to be quite positive.
Secondly, obviously, The technology
needs
to work itself out in terms of both cost And in terms of flexibility, we are looking at relatively stable technologies at this point. And so we don't see that, that would necessarily be a difficulty. So from the CCUS standpoint, we continue to see it being very positive and moving forward. Now depending on the types of government support that we're looking at can have a significant impact on what we see as a hurdle rate. So for example, a part of a overall package of support given to these kinds of projects is say a guarantee of Carbon Price for 10 years, then that certainly takes an element of risk out of the project.
But having said that, When we look at what would be an appropriate hurdle rate for this kind of a project, we would start from a merchant perspective, that ended the spectrum and then adjusted depending on what we see as various lines of support for the project and in particular Commodity Risk Associated with CO2. So that's The general framework for CCUS. The other thing, sorry, in terms of CCUS that we'd have to see is obviously So the Alberta government is pursuing a track of carbon hub and spokes associated with So the pipeline access to what might be the spots to bury the carbon That means, of course, to move along and to come to fruition. We certainly wouldn't want to get ahead of that development. We would like to see that move along very quickly and be in place from a number of different perspectives before we would move too quickly to commit our dollars to CCUS Facilities.
In regards to GC3, The design work continues to go very well. And so we're not saying that there's any technical issues associated with moving forward with it. What we do, what we continue to be evaluating and more or less finding What are the different markets to be utilizing these carbon nanotubes in the short term And continue to explore that. The cement testing continues to be ongoing. In fact, there's a Significant cement testing that is being kicked off as we speak.
And so we're we'll continue to be bullish from that perspective. So we need to see some significant commercial step forward in terms of people actually signing up for carbon nanotubes or a clear identification Likewise, we look at that from probably a merchant plus hurdle rate, given that it is largely More speculative than merchant markets, so we'd be looking for some pretty robust long term returns associated with that project. I might also comment that just in terms of Just in terms of the way of looking at our development going forward, there is a fairly long process associated with getting carbon nanotubes and variations of carbon nanotubes approved from Both Canadian and U. S. Regulatory perspective has a new material And that takes about 12 months to say 15 months.
And we're in a situation now that when we find the carbon nanotubes to start putting through this process, that gives us more than enough time to finish, polish up the design parameters associated with GC3 and to complete it, so that we'll have regulatory approvals and completion of the project happening simultaneously.
Thanks. To be clear, whilst we start at a merchant return level or merchant plus, Is the ideal end goal to have more than 50% or maybe even 70% contracted? Or are you happy to have it merchant and then backfill the contracted bits with other developments that you may
Well, the nature of the market and this is the same with any sort of material It is not typical for there to be long term contracts associated with the supply of materials. So It would be good to have long term contracts, but we don't believe that that is practical. There may be shorter term contracts for a year or 2 or something of that nature, but Yes, we don't believe the nature of the market is such that long term supply contracts would be available.
Thanks. And on my final question, keeping the theme of contracting, amidst your discussions with BC Hydro With regards to island generation, maybe more broadly, how do you view your current recontracting profile? And more specifically, does it change your desire to acquire midlife natural gas generation assets?
Actually, no. And the reason is, as I indicated in the comments So thus far, we see that facility is definitely needed on Vancouver Island. And I would say the IRP that was put out by BC Hydro doesn't have the same level of diligence or analysis behind it that IRPs in previous years have had. So it's very much, I would say, incomplete from that perspective. And I think as their work is complete and as Parties like ourselves have input.
I think we'll see a different answer, if not in the IRP P itself when it's out in December, ultimately as it goes through the process with BC Hydro or BCUC. So We definitely continue to believe that that facility will be recontracted. When we look across the other re contracting situations and in the near term, the next one is Arlington, which comes up, I think in 2024 or 2025. The outlook for that has been recently strengthened significantly. And that's because we're seeing significantly high prices in the Arizona market.
We're seeing new supply constraints starting to evolve and the niche that we feel is particularly strained. So The outlook for recontracting in Arlington Valley, which is the next one, is very, very strong. When we look at what's The next series of re contracts, which is at the end of this decade, 2029 in Ontario, the recent outlook that was published by the ISO There is a significant demand for generation or new generation in Ontario And even under scenarios where everything gets re contracted, there's still a very significant demand And there are increasing constraints on the system and our 3 facilities are on the right side of those constraints. So they continue to be extremely well situated for being needed in the Ontario market. So our outlook for Recontracting existing assets is very is actually stronger now than it had been before.
When we look at new assets, obviously, we continue to have to scrutinize not only The current contracts and current circumstances, but definitely continue to Ensure that anything that we bring forward has a very valuable market positioning, either physically or a particular niche that it fills. So we continue to be very bullish on that market.
Great. Thank you very much.
The next question comes from Mark Jarvi with CIBC Capital Markets. Please go ahead.
Yes, thanks. Good morning, everyone. You mentioned, Brian, that budgets and timelines I think for projects are going as Plan. Can you just maybe give us a bit of a rundown in terms of exposure to some of these inflationary pressures we're all hearing about in terms of Genesee repowering and And the little projects in terms of how much of the build costs are locked in and equipment costs are locked in at this point for those different projects.
So it very much varies obviously by project. A lot of the repowering is locked in. I don't have a The general sourcing of it, materials and so on is largely The elements of the project that they're working on. So, I'd say, very major components are from a cost perspective. The other thing that when we what the pressures are up today, There's 2 components.
1 is the actual cost of material and supply demand balance. But Where we're seeing the major pressure on cost is on transportation. And the general perception is that there Right now, there is a has been a significant increase in terms of a couple of 100% in terms of transportation costs, But that will subside and a lot of the deliveries associated with the Genesee repowering would be on the other side of that delivery. And a lot of that project is actually being sourced out of the United States. So Don't really expect that element of pressure to impact on that project.
When we look at the Renewable Projects, the ones in Alberta, a lot of the contracting per se was done prior to cost pressures. So we do see some delivery cost pressures impacting on the Alberta projects. We think that those are more manageable than expected that the impact would be relatively modest on the project. We don't see Costs going sort of out of control and continue to be pretty bullish on those. When we look at the U.
S. Renewable Projects. The contracting for those is still somewhat open. We do have some Supply Elements in Place. And as we move forward, we do expect that the Particularly, again, as I had mentioned earlier, the costs associated with transportation to be declining, which is where we're seeing the greatest cost pressure in terms of the supply chain associated with our facilities.
And then with those solar projects in the Carolinas, do you have some flex in terms of start date or COD, if you do kind of move away from some of these Or transient effects that you're talking about?
Yes, we do. And we've been even with the Alberta project Within the construction schedule, we're able to move around some dates and change the way in which we're executing on the project to Minimize the impact of some of these pressures.
Got it. Now I wanted to come back to the Alberta market and Talk about hedges and the forwards. Maybe just on the forwards, 2022 has come up nicely as of obviously this year. 2023 starting to move up a little bit, but not nearly as much as 2022. And I guess the view would be that there's new supply coming.
But when you look at your repowering market more late 2023. Is your assumption that there's still a chance that 2023 forwards have room to move higher when you think about supply demand?
Yes. I think, Mark, with respect to looking out as far as 'twenty three and 'twenty four, there's less liquidity out And certainly as we get closer to that date, you'll start to see more reflective forwards of where they will. You're correct with respect to increase supply during those periods of time, but we also expect higher carbon taxes as well. So I do think there is upside to those years, but we won't see that until we get another year out or so, sort of similar to what you're seeing in 2022. It's starting to be more representative currently, but the other years need to see more liquidity before it will start to fully reflect where where we would see it settling in those years.
Okay. And then when you look at the 2022 hedge position, you've taken it up, the average Price seems to have gone a little higher implies you're now sort of locking some forwards in the $60 range at least. That's still below where the forwards are. Like Would you still want to keep adding more forwards here into 2022 or like could you start to slow down here as you approach 50 percent hedging because obviously prices on the forward curve are north of $70 right now.
Yes. If you've seen prices go up, it does inform our view as to incremental hedges. So we would be very opportunistic in terms of adding positions at a price that we See being in line with where we think things will settle. So we have locked in. You'd like to get hedges in place to protect The downside, if you will, but certainly our strategy has been to be less hedged and be very opportunistic at only hedging at prices that we think are more representative of forward.
So
If you didn't see any more really good opportunities to lock in pricing, you'd still be comfortable if you ended this year at 50% hedged going into next year?
Yes. No, absolutely. I think historically, we've been somewhere between 50% to 100% hedged under The previous market dynamics and we're very comfortable to be less hedge in the current market environment. So no expectation of having to reset hedge position if we don't feel we're going to be seeing prices that are competitive.
Got it. And I just wanted to ask a question about the updated guidance in terms of the changes and the midpoints of the EBITDA and AFFO. If I take the new midpoints and what you've done year to date and kind of look between the cascade from EBITDA to AFFO, so the cash outflows for the second half implied between the two midpoints about $226,000,000 and it was $294,000,000 when you think of Interest expense and prep dividends and whatnot in the first half. So it's sort of a $70,000,000 lower sort of cash outflow between EBITDA and AFFO in the back half. Aside from maybe lower interest expense and I guess the line loss not being there.
What else would contribute to that? Or maybe it's just the ranges and usually midpoint maybe not the most appropriate thing to do. So Any sort of commentary around that sort of thinking between the below the EBITDA line cash expenses in the back half of the year?
Yes. I think if you're looking at the difference between Adjusted EBITDA and AFFO, is that correct?
Yes.
Yes. So in adjusted EBITDA, We have the coal compensation acceleration and that's about $20,000,000 a quarter of incremental year over year recognition, where in AFFO, it's still on a cash basis, which is $50,000,000 a year, and that's all in Q3. 3. So there is some distortion in the timing as well as the amount of that component. And that's about the biggest difference between those two metrics.
Okay. That's helpful. Thanks for clarifying.
And I guess, Mark, just the other thing to is below the line is the impact of taxes as well. So on EBITDA to the extent that we're Seeing higher plant performance, you're just seeing the margin there, where in AFFO, that's tax affected as well. So that would be another difference between the 2.
The next question comes from John Mould with TD Securities. Please go ahead.
Yes. Hi, good morning everybody. Maybe just starting with the forced outage at Genesee Meaningful force outages at Genesee in general are pretty unusual. And I know it's still ongoing and is reflected in your guidance. I'm just wondering if there are any lessons learned there from the generator failure.
So I'm sorry, John, I didn't catch the last part of the question.
Just I'm just wondering if there are any lessons learned from the failure of the generator there. Could this maybe have been mitigated if you hadn't had to defer? I think the outage was originally scheduled for 2020, but I think it was delayed For COVID understandable reasons, are there any takeaways from the others there?
So, actually, I mean, we're the way that Things have come about, although obviously it's an outage. We've been very pleased with the way that we've been managing those assets. So there is a major rewind expected that even at a normal course continuing coal operations, existing facilities, There was a major rewind expected around the mid decade this year or this decade. There was an expectation that the rotor itself was going to be in in need of major, major refit. In expectation that that's sort of signaling to you that you may be running And to troubles, even earlier than that, we actually have packages on-site, strategic spares that will significantly reduce what would otherwise been The outage experienced with this kind of a failure.
So the combination Being able to be somewhat conservative in ensuring that we have those kinds of spare materials around such that When we have these kinds of failures, if this failure happened and we weren't well positioned, it could have been 6 months. So we're again very pleased with how we are positioned to deal with this kind of situation. So It confirms
the need to ensure that
you have the right strategic spares That you when you're looking at major maintenance happening sometime in the future that again you should be prepared to move quickly and deal with it in a more timely manner than otherwise would have been the case.
Okay. Thanks. That's very helpful context. And then maybe just moving to your development outlook. I'm just wondering if you can give us a bit of an update On beyond the stuff that's in the construction pipeline, an update on your renewable power development activities in Canada and the U.
S. And whether you're seeing Interesting opportunities to either move forward with any new projects or to increase the size of your potential U. S. Development pipeline through additional early stage acquisitions.
So my answer to that is all of the above. We are seeing some positive developments from an Alberta and Canadian perspective and see some opportunities moving forward. We are also on the U. S. Side, have some opportunities that we believe may come to Coercion in the relatively near term.
But in addition to that, we are looking at opportunities to expand our pipelines on both sides of the border from a renewable perspective. And there's where we've been successful in the past is being aligned or acquiring, I'll call it smaller developers as one off or a series of Developments. That continues to be fruitful in terms of some opportunities out there. But we're also looking at the fundamental ground up development of our own projects. And we've been Quite successful with that where we've undertaken it.
So we're looking at markets where it makes sense for us actually from the ground up from securing the leases through to design and develop. So our pipeline will be getting built out from a number of different perspectives. But even without what we have today and what we're seeing, we continue to see some Some significant opportunities in the near term.
Okay. Thanks for that. And then maybe just one follow-up question on Island. Appreciate that you may not want to get too much into contract discussions and there's an active review process for the IRP. Have you had any follow-up from BC Hydro since transmission issues and cable bulging Problems started early in July that recognize the aspirations of the IRP just may not reflect The reality of the grid on Vancouver Island and its needs.
So we've been our discussions thus far have been with the government and the BC government, largely because for logistical reasons and timings. We haven't had a good opportunity to directly discuss it with BC Hydro, But that is being scheduled and those discussions will take place outside of the IRP process. So we do have a number of questions and we've informed BC Hydro these are the questions that we have and just I would announce don't understand their conclusion based on the facts, but again, we'll see where that gets to. We don't believe that when you look at the IRP, we don't believe that that is There will be no final any stretch of the imagination. We do believe that it is a work in progress and recent Information suggests that they still have work to do in terms of that assessment.
So, We don't believe that we're talking to deaf ears. We do believe that there will be a significant receptivity to having discussions around the recontracting of the Island Facility.
Okay. I'll leave it there. Thank you for taking my questions.
The next question comes from Rob Hope with Scotiabank. Please go ahead.
Yes. Hello, everyone. Just Kind of two follow-up questions. The first is that we have 6 months or I guess 7 months under the belt regarding the Alberta Power Market in the New World Order. Has your view of how market participants will act or what the And the long run sustainable pricing is changed over the last 6 months?
Yes. So I think the environment that you're seeing now in 2021 is reflective of the market going forward in in terms of the dynamics and setting price. I would temper that with in 2021 what we've seen so far is some extreme weather both in February June, which has driven prices above where I would say you would expect them to be longer run. And wind availability is something else that impacts on that volatility when you've got extreme weather. So I think generally speaking, the dynamics are what you will see going forward.
This is the supply demand sort of fundamentals, but artificially high, I would say, for 2021 when you're looking at $105 per megawatt hour. But when you look at the forwards Going into next year, I think that's a little more representative of where you would expect it to be given where the market tightness might be in any given year.
Okay, great. Then just as we take a look at your 2021 guidance, what kind of Range of power pricing are you assuming there? Or is it kind of relatively centered around where the forward curve is?
Yes. So it's based on both our position and the hedges we have on place as well as our outlook for forwards for the balance of the year on our open position.
Thank you.
The next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Thanks. Good morning. And I guess the question really revolves around the Alberta power market and just your trading desk philosophy. And Have things changed at all or is it really been the same? And maybe I'll give the dichotomy of are you focused on capturing returns that are really acceptable So the capital you've put in the business or is it really a focus on capturing close to market price?
Yes, Andrew, I think it's a combination of both. When you look at where prices are, it's expected to be a return of and a return on capital for our investments in the Turn on Capital for our investments in the market, but also in any given year, you know that There is volatility depending on supply demand dynamics. So you're looking to optimize the price in a given year based on where you're seeing prices settle. So, it's sort of a combination of both in terms of this strategy. You're always trying to realize the best price that you can and balancing that with volume as well.
So it's really Two pieces of that strategy, if you will. So, in theory, the market dynamics are allowing for appropriate level of returns on investment.
Okay. That's helpful. And then maybe putting aside weather anomalies and other things. If you just looked maybe from last year to where we are now and the evolution of dispatch behavior, Are there any major surprises that have happened in the market versus how you thought it
was going to pan out?
No, I think it's generally in line. There was certainly some uncertainty around how it would unfold. There was sort of a range, if you will, of prices that you could expect. And so you don't have a clear crystal ball, but Directionally, I think it is lining up with what we would expect in terms of market participants' behavior and The commercial being a much more rational market in terms of how assets are being dispatched.
Okay. That's very helpful. Thank you.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Thank you. Yes, good morning. Just on the natural gas price side of the equation and I guess thinking about the upward bias narrative that's out there right now, not only into this winter, but perhaps longer term.
Curious how
you're thinking about mitigating your margin exposure there, especially once Power prices eventually come back down to earth and the Genesee repowering comes online. Are you looking at strategic partnerships, Investments or long term supply agreements that could lock in the natural gas cost Side of the Alberta Merchant Margin Equation. And if so, what might those structures look like?
Patrick, I mean, we have for a considerable period of time Look at is there a strategic relationship out there in which we could You'll access natural gas supply at, let's say, something other than market and I'm getting some security of market in return. What we found is that Generally speaking, the natural gas market isn't very reasonable. What they'd like you to do is lock in a very high forecast price and guarantees that kind of a cost. So we haven't found the market that receptive. And certainly in that environment, Very difficult to establish a mechanism that is responsive to power With increasing natural gas and especially now when we'll be off coal, Natural gas price will have a significant impact on the margin.
So as natural gas prices go up, That would be a variable cost for increasingly more and more generation in the province and it would have an impact of increasing power prices as it goes up. So You're a little bit naturally hedged by the pricing mechanism in the marketplace for power. So Traditional wisdom is that unless you really have an ability to lock in both sides of the Natural gas price and the long term price of power, you're probably better off to let it float with the price of The electricity prices that you're seeing. So we continue to look at those opportunities and where we can find somebody that has the right sensitivity and there's some value shared between the power generation side and the natural gas side In terms of sensitivity to where power prices go, it likely doesn't make sense to just lock in one side, Again, unless you're locking in aside and the other side is longer term power price commitments.
Thanks, Brian. I appreciate all the color and how you're thinking about that. And then maybe just back to the island generation situation or I guess re contracting process. Can you maybe just provide a bit more color on how this experience has Changed your approach in looking at other mid merit acquisition opportunities either In terms of recalibrating your hurdle rates or perhaps taking certain jurisdictions right off the table?
It is I mean, we're definitely going Taking away some perspectives from this experience. Certainly, we often with investors and with you folks have utilized Island Generation as this is the one that This is the illustration of why something probably positioned makes a lot of sense. And so again, big surprise to us. And when we look at these, again, in the longer term, We do have to consider that there can be just out and out mistakes made in terms of assessments of utilization. Part of what's underlying some of the thinking from the in the IRP is they're going to have Very, very substantial and pretty quick reduction of power utilization through conservation methods and so on and so forth, which still are far away from regulatory approvals, etcetera.
So just There are things that can enter into the equation that aren't that are new or different. So it will probably broaden our perspective when we're looking at new natural gas acquisitions considering Perhaps maybe some of the more outlier possibilities. So I would say The hurdle rate per se, again, may adjust depending on the particular risk profile you See in an area may in some future possible acquisition have an impact on hurdle rate. I think though where it will have probably more of an impact is on the breadth of our assessment.
Got it. Okay. And then last one for me, if I could, just I guess to finish off on a positive here, but to follow-up on the new renewables opportunity set, we're of course seeing big demand from pipeline companies and other infrastructure players looking to electrify their systems. I know they're running very competitive bidding processes, but Just given your relationships with some of the larger players in Alberta, your development track record, How should we be thinking about the size of your backlog of opportunities today related to corporate PPAs, either Wind, solar or other relative to even say 6 months ago?
We continue to have number of opportunities that we are pursuing and some I'll say are probably pretty close to fruition. And some of those to a degree are relationship based, but I would say when you look at the very large PPAs that are out there, Those tend not to be relationship based. There are certain advantages that we and other developers like us such as investment grade credit rating, track record of delivery. There's been a number of GPAs In the Alberta market that has failed where a commercial entity has signed up with an organization and The organization has got into the more detailed form planning find that they can't move forward on the project. We've seen a handful of failed projects in the province.
So the fact that when we say we're going to do something, Do it is very helpful. So there's a number of those kinds of elements that favor us and other Substantive Developers. So but relationship, I'm not so sure And the larger ones, whether they actually will make a difference, a lot of it is just what's the cost. One of the other things though that does help us in the market is we tend to be A lot more we can bring a lot more to the table in terms of people's load and being able to manage it. For example, we can provide both wind and solar combination right now.
We've got a lot of flexibility. We can actually round up somebody's overall power demands. So there's a lot to gain that we can do that a number of different developers You may not be able to do, we can bring in REX from other provinces because we've got quite a broad trading footprint, whereas A lot of the other developers don't. So there's more tools we can bring to the table depending on what The specific requirements are of an offtaker, but they're pretty they're getting increasingly sophisticated and It's becoming a very, very dynamic market. But again, we continue to be bullish in terms of our
The next question comes from Najee Baidu with IA Capital Markets. Please go ahead.
Hi, good morning. The first question is around, I guess, portfolio optimization and it's sort of related to the previous questions about oil and generation or your gas assets more broadly. You've talked in the past about potentially monetizing renewable assets if the right investment opportunities present themselves. I guess the question is, would you ever consider monetizing some of your gas assets at the right price, of course, instead of renewable ones?
We've certainly looking at assets And depending on the how much capital that we're looking for and so on and so forth, there are Certainly some of our natural gas assets that would be relatively easy to be monetized. Part of the challenge that we face is that when you monetize a renewable asset, long term contracted asset. What you receive in the AFFO you give up I have a particular relationship. When you look at a natural gas asset, typically you're getting less proceeds For the same level of AFFO that you are giving up in terms of the sale. So that's one of the things that comes into consideration.
But Absolutely, we'd have that reasonable pricing we'd consider selling natural gas assets as well.
I understand. It's the trade off that you're thinking about between immediate financial contributions versus the contracted profile and renewables profile and maybe Okay, that's helpful. Maybe just a couple of questions for Sandra. Can you provide any color on the sustainability linked Credit Facilities on either the terms or the incentives versus the previous structure of those facilities?
Yes. So most of the details around that aren't disclosed. What I can say is that it's, plus or minus 5 basis points for our performance relative to the targets. And the targets are based on our emissions intensity and align with our trajectory to be 65% below our 2,005 level by 2,030. So there's that It is an annual target, so it's not where we are at the end of the 5 years.
It is consistent with most other SLCs you've Seeing out there, there are annual targets that need to be met in order to keep the pricing or to have it move downwards or upwards in the case of not achieving that level of intensity. One other element of that The structure that I can share is just around the treatment of structural changes. So to the extent that we acquire an asset that was already in operations. We would have that adjustment made to the intensity targets in that you look at it very holistically in terms of overall emissions. So to the extent that asset was already in operations, it then impacts your targets.
And likewise, to your earlier question, if we were to divest of something that had an emissions profile, our targets would be adjusted to reflect that as well. So there is that rebaselining component in the structure.
Just last question on the private placement of the U. S. Notes. Do you see any other opportunities for similar favorable debt financings?
Yes, I think it's been very favorable like the market has been favorable in both the U. S. Private placement market and the Canadian market as well. At this point in time. Don't see ourselves going to the market absent any growth, but feel very confident that The market is there for us if we did have to raise capital.
Okay. Perfect. Thank you very much.
This concludes the question and answer session. I would like to turn the conference back over to sir, Randy Ma for any closing remarks.
Okay. If there are no more questions, we will conclude our conference call. Thanks again for joining us today and for your interest in Capital Power. Have a good long weekend everyone.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.