Q3 2021 Capital Power Corp Earnings Call
Thank you for standing by this is the conference operator, welcome to capital Power's third quarter at 2021 results conference call.
As a reminder, all participants are in listen only mode and the conference call is being recorded today October 27 years 2021.
I'll now turn the call over to Mr. Randy Mah, the director of Investor Relations. Please go ahead.
Good morning, and thank you for joining us today. So we can either capital Power's third quarter 2021 results, which we released earlier. This morning, our third quarter report and the presentation for this conference call are posted on our website at capital power Dot com.
Joining me on the call are Brian <unk>, President and CEO, and Sandra Haskins Senior Vice President Finance and CFO will start with opening comments and then open up 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 two.
In today's discussion, we will be referring to various non-GAAP financial measures as noted on slide three these measures are not defined financial measures. According to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measure.
Yours, 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 third quarter 2021, MD&A with that I'll turn the call over to Brian <unk> for his remarks, starting on slide four.
Thanks, Randy and good morning, I'll start off with the highlights of the third quarter and comment on our 2021 outlook. The third quarter results were generally in line with our expectations. The unplanned outage at the Genesee two facility.
We will be longer than originally anticipated with a return to service now expected at the end of November 2021, we continue to make progress on our seven renewable development projects that I'll comment on in greater detail later, but briefly we're seeing cost pressures on our two Alberta solar projects also the completion date.
For our three North Carolina projects has been extended due to delays in the interconnection process.
<unk> financial.
<unk> performance and our positive outlook, we are suspending our dividend reinvestment plan or drip effective with the fourth quarter 2021 dividend.
In the second quarter, we provided higher 2021 financial guidance, largely driven by the positive Alberta power outlook that outlook has not changed as the market continues to be robust.
The extended Genesee two outage, we continue to be on track to achieve annual financial results consistent with our revised higher guidance.
Turning to slide five as you may recall Genesee two experienced a forced outage in mid July that was caused by a generator failure and the physical damage is covered by insurance. The unit is undergoing repairs to replace the generator and as I mentioned, it's expected to return to operations at the end of next.
Last month, we continue to utilize our Clover bar, it's peaking facility to backstop Genesee two when it's appropriate but lots of Ryan or Avenue qualifiers for business interruption insurance after 60 days and Sandra will cover the accounting impacts of the Genesee two outage in her comments I'll now turn the call over to.
Sandra.
Thanks, Brian I'll start with a review of the Alberta power market on slide six.
We continue to see strong prices with an average power price of $100 per megawatt hour in the third quarter due to hot temperatures facility outages and year over year weather adjusted demand grows up approximately 4% in the third quarter.
The strong average power price more than doubled the average price of $44 per megawatt hour in the third quarter of 2020.
In the third quarter, our trading desk captured an average realized price of $75 per megawatt hour that was 27% higher than the $59 per megawatt hour a year ago.
The market outlook for the balance of this year continues to be strong with a $99 per megawatt hour forward price for the fourth quarter.
With the strengthening of the forward prices, we've increased our hedge positions for 2022 to 2024 since the second quarter.
Our Alberta base load generation is now 67% hedged in 2022 at an average contract price in the mid $60 per megawatt hour range.
For 2023 were 38% hedged at a contract price in the mid $50 per megawatt hours and for 2024 or 21% hedged in the mid $50 per megawatt hour.
This compares to current forward prices of $91 per megawatt hour for 2020 to $73 for 2023 and $62 in 2024.
In addition to the base load assets, we have approximately 500 megawatts of gas, peaking and wind facilities available to capture upside from higher power prices and price volatility in 2022.
On slide seven I'll review, our financial results for the third quarter.
As Brian mentioned financial results were in line with our expectations.
Consolidated revenues and other income were 377 million in the third quarter down 17% from a year ago, largely due to unrealized changes in fair value of commodity derivatives and emission credits.
Excluding the mark to market impacts consolidated revenue and other income were up 7% due to strong performance from the Alberta commercial facility.
Adjusted EBITDA was 286 million in the third quarter, a slight increase of 1% compared to a year ago.
We generated $206 million, so that was 7% lower than a year ago. The decrease in <unk> was due to the lower contribution from the U S contracted facilities and higher sustaining capex due to maintenance work performed for the Genesee two outage that was originally scheduled for the fourth quarter.
Yeah.
On slide eight I'll discuss the accounting treatment of the Genesee two outage and associated insurance recovery.
Approximately 25 million of capital costs were incurred in the third quarter of which 23 million net of 2 million deductible was accrued to be recovered through insurance.
The net recovery, it's reflected in the third quarter income statement in the gains on disposal and other transactions line and not as an offset to the capital cost.
In <unk>, we see the net impact of the $2 million deductible, while there is no impact to adjusted EBITDA.
From an operational perspective business interruption coverage is effective 60 days after the start of the outage, which would be as of mid September.
And accrual for business interruption was not recorded in the third quarter, primarily as the final amount of the claim which will take into consideration mitigation across the portfolio will not be fully known until the unit returns to service.
Slide nine shows our third quarter year to date performance.
Adjusted EBITDA of $830 million was up 13% compared to 735 million for the same period in 2020.
The main driver for the increase with higher Alberta power prices, where our realized power price was $75 per megawatt hour compared to $59 per megawatt hour a year ago.
Lower corporate expenses also contributed to the higher adjusted EBITDA, mainly due to the acceleration of coal compensation revenue.
E S S O with $456 million up 5% compared to 436 million a year ago.
Overall, we've seen strong year to date performance and our key financial metrics.
As Brian mentioned, we have suspended the drips due to our strong financial performance and outlook. We also assess access the capital markets. This year, raising 288 million in equity and 150 million U S and that will fund later this month.
These successful financing have reduced our financing risk and the need for additional equity for current growth projects.
I'll now turn the call back over to Brian.
Oh.
Thanks, Sandro turning to slide 10, I'll review our performance for the first nine months of the year compared to 2021 targets year to date, the average facility availability was 90%.
The extended Genesee two outage will impact our annual performance and we expect to be below our 93% availability target at year end.
Sustaining capex was $99 million in the first nine months compared to the 80 million to $90 million annual target we've exceeded the annual target largely due to the Genesee two outage and an unplanned roller purchase at the Arlington facility during a planned outage in the second quarter.
Of which the ladder will cause us to exceed our sustaining capex target for the full year.
After nine months, we reported $830 million and adjusted EBITDA based on our current outlook, we expect full year results to be in line with the midpoint of the revised guidance of approximately $1 1 billion, we generated $456 million of AFR full.
As far as.
As for this year.
And expect full year results to be modestly above the midpoint of the revised guidance range of $570 million to $620 million.
On slide 11.
To provide a status update on our growth projects, we continue to make progress on approximately $1 7 billion of growth projects under development. This includes developing and constructing seven renewable projects and the repowering of Genesee one and two.
Our whitlow win two and three projects in Alberta are on budget and on schedule for commercial operations later this year.
<unk> Chan solar projects in Alberta are expecting experiencing higher costs due to the significant increase in transportation costs and higher costs from supply chain pressures you revised project cost is estimated to be $57 million compared to $53 million budgeted for Strathmore solar.
While the project costs were in Chancellor is now a $119 million compared to the 102 million budget.
We have three solar projects in North Carolina with an original commercial operations date of Q4 2022.
However, due to delays in the interconnection process commercial operation is now expected to be Q4 2023 for Q1 2024.
Construction on the Repowering of Genesee, one and two commenced in the third quarter.
There are no changes to the budget or target operations date of late 2023 for Genesee, one and 2024 for Genesee two.
Four of $500 million committed capital growth target, we continue to explore opportunities with a potential growth announcements later this year.
To wrap up I'll comment on other activities that we have going on as outlined on slide 12.
COVID-19 continues to be well managed with no impact on our operations our plans to build the world's largest commercial scale production facility for carbon nanotubes at the Genesee carbon conversion center continues to be on a slower development path. We continue to work through the regulatory registration of our carbon nanotubes necessary for.
Commercial operation.
For island generation, we continue to believe the facility as needed to ensure a secure and reliable power supply for Vancouver Island and Metro Vancouver. We're currently negotiating on a medium term agreement with BC hydro before the current PPA expires in April of next year.
Finally, the Ccs pre feed study is nearing completion and overall the project looks increasingly promising we plan on providing more details on our de carbonization strategies at our Investor day.
I'll now turn the call back over to Randy.
Okay. Thanks, Brian before we take your questions I would like to announce that we will be hosting our annual Investor day event on the morning of December the second where we're hoping to hold a live event in Toronto, but it will be a virtual event again this year more details on that that will be announced shortly and we hope that youre able to join us virtually on December the second.
Alright, <unk>, we can start taking the 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 Maurice Choy with RBC capital markets.
Please go ahead.
Thank you and good morning. My first question is on the Repowering project I just wanted to get some updated thoughts on this project. Obviously you would have heard that one of your peers opted to suspend their project highlighting some of the potential regulatory and financial headwinds for new gas, including Repowering, how would you characterize.
These risk and what plans do you have should these risks materialize.
So I.
I guess maybe.
Going too.
I guess the essence of your question.
When we look at the our outlook in terms of our regulatory stability and in particular.
The point $3 seven stringency is going we've been reassured again by the Alberta government.
From direction from the Premier that.
The <unk> seven will hold the province is very confident in their equivalency from a federal perspective, and so don't really see that element.
<unk> in terms of the.
All our peers decision to.
Basically.
So spend moving forward with one project in shutting down to other facilities.
It would have to admit the shutting down of the other two facilities is actually a little bit in advance of what we thought when they would actually be shut down.
And in terms of advancing on a new facility I think if you look back to when that.
Facility was announced initially whats happened since is that there has been.
The.
And if you think of the stack in the Alberta market it would've been.
One of the most efficient natural gas combined cycles in the province since then.
Genesee you wanted to Repowering and <unk>.
There's been a.
An additional announcement in Alberta, the Cascade project, that's going ahead, so all of a sudden there's.
2500 megawatts of capacity.
Much much more efficient.
That's been put in the queue. So.
That.
Of that.
Project ongoing forward was not a surprise to us whatsoever.
I didn't believe that with those other results that it was.
It would be economic even with our outlook.
So not a not a big surprise.
Again.
The face of Concho reassurance from the Alberta government that the 0.37 will hold.
Well, we continue to be positive.
Second part of your question is what happens if it changed or what happens if if if if if.
There was it.
Well the change in the 0.37.
We actually in our projections or.
The repowering.
<unk>, one and two we actually have it after 2030 declining.
At some point in time.
It will reach zero and it's fully within our economics that over a reasonable period of time post 2030 that it will get there so.
Worse.
So a timing difference.
The shorter term impact of course is that it will impact to a degree on power prices in the province, given the dominance of natural gas generation.
So.
The economics of Genesee, one and two would continue to be very solid.
Thanks, and maybe just a follow up to that.
You said a few cost pressures for some of your Alberta solar projects any any pressure so similar pressures to the $997 million budget for this project.
No.
We are seeing.
Some very very modest cost pressures.
But nothing nothing that is moving the needle on the costs for the project.
Thanks, and just a final question on guidance.
You've pointed to midpoint of EBITDA.
On a guidance range.
Also highlighted the sustaining capex is slightly likely to be above your $80 million to $90 million range.
So despite this higher sustaining capex.
Still expect it to be not just at the midpoint, but modestly above that.
Causing this for it to go higher.
So there's a few things in there we are seeing lower financing cost.
This year so some of the below the line items that you have seen strong performance in Alberta.
Driving up the the catch though so there are some timing difference in some below the line items that got that.
That impact that differential if you will.
Yeah.
Okay. Thank you very much.
The next question comes from Patrick Kenny with National Bank financial.
Please go ahead.
Thank you and good morning.
Brian just a follow up on the Genesee investment curious if theres any update on your carbon sequestration opportunity at the site.
When you might have more clarity on the level of government support.
Provincially and federally and I guess when do you think you might be in a position to sanction the opportunity.
So.
Where we are in respect of the Ccs opportunity as a.
We continue to be to be.
Pursuing it and actually with the increasing bullishness.
In terms of the development process.
Sure.
Close to finishing our pre feed study.
Results there have been.
On balance positive a slight increase in capital cost, but operating costs and and the.
And the degree to which.
It needs it needs power is declining so.
That's that on balance the economics of the project or improvement.
And so then of course, we moved to a feed study, which we expect to go through next year and I would say the the earliest that we would be sanctioning the project and given.
That we would require government support and a clear indication of government support before we would get into.
Approving the project and moving forward.
We would expect that to happen you know late next year or early in 2023 and in terms of the government activities, the Alberta government's moving forward.
On the hub concept and looking at different parties to provide.
Carbon sequestration hubs.
And from what we've seen in the parties, we've talked to that's moving along quite well.
The other front is with the federal government and disc.
Discussions continue to go from our perspective well.
With the Canadian infrastructure Bank.
The bringing.
Bringing into play something like 45 Q.
Before the election was identified by the federal government.
It's something that they would be doing and so we are looking forward to hearing are the next steps in terms of that development.
We have been receiving comments from many parties as to what it should look like but as we put all the pieces together.
We continue to believe that the Ccs is.
Definitely.
Uh huh.
Economic for capital power on the top of Genesee, one and two.
Great. Thanks for that color and then maybe also on CTO CNT.
We expect to have.
We have board approval for the carbon conversion project by year end.
And maybe just.
An update on how the technology continues to prove out here since our last update.
So.
Given given the.
The timing opportunities for board approval of that project wouldn't see it happening before the end of this year in terms of the development of the technology. It continues the actual development of the technology continues to go very well.
The testing of the carbon nanotubes.
As it relates to cement has been moving along albeit slowly heal very much in a positive direction I'd characterize it that way.
Three quarters or two thirds of the way there.
The challenge that we run into and I think I've commented on it before is that there is actually a very long regulatory process to that.
Actually get each and every carbon nanotubes approved as a new material.
Which requires in depth.
Now assist in description of not only the process, but the but the mediums for example for distribution within our material et cetera. So we have to be almost complete say for example, with our cement exploration and development and then at that point, we start basically.
Minimum one year process to get it approved and we can clearly build.
The.
Genesee carbon conversion.
Facility within that timeframe so.
Until we have at the precise project.
<unk> nailed down yet.
<unk> is.
Is creating a delay for us in building the carbon conversion center. So that's the general outline of about.
What.
But what we're looking at and where we expect to be going with the project.
Got it that's helpful. Thanks, and then last one for me if I could maybe for Sandra on the suspension of the drip.
Do you view this as being more of a sustained suspension and that you know even if you were to secure.
The $500 million of committed capital projects.
Well for 2021 over the next couple of months.
You wouldn't need to turn the drip back on at that point or is this more of a temporary shut off until youre able to secure a couple of more developments.
I view this more as if this thing turn off the drip at the Pat So when you look at the capital that we raised the equity we raised this year as well as the contributions that we'll receive from the drip it does.
Equate to the amount of equity that we indicated we would need for the $1 7 billion of projects that are currently under development. So we've achieved that.
To the extent that we have growth.
<unk> strong cash flow is very strong credit metrics that we would be able to fund development. If there was an acquisition of any size that would would need equity we would probably look to approach the market with an offering for that go forward with that a bit of a story with respect to it.
At this point in time don't see the need for incremental funding or.
Incremental equity.
On that in that regard so see it has been at this game turn off the drip.
Okay, that's great I'll jump back in the queue. Thank you.
The next question comes from Rob Hope with Scotiabank. Please.
Please go ahead.
Hello, everyone.
Maybe just in terms of kind of your outlook for the gas market and how you're managing that exposure can you just remind us where you are in terms of gas procurement in how you're viewing kind of the right gas pricing in terms of operations for the rest of the year and into 2022.
Yeah for 2022 with the balance of this year 2022, and even out into 'twenty, three and well into 2024, we have hedged a large portion of our gas or substantially all of our GAAP and in the near term and I've seen a lot of knowledge.
As you've alluded to and I have sort of taken that risk off the table by by hedging hedging that out materially so looking at optimizing our fuel and the burn of Pall as we optimize the mine plan as we wind down in 2023, so look to sort of locked down those positions and close that Expo.
Sure.
Alright, thanks for that.
And then kind of just more perspective in nature. So we're seeing some cost pressures.
In terms of the renewable power development projects.
Are you looking at that next phase of growth, whether it's about $500 million how.
How are you bidding into those projects.
Given the potential that you could see additional or sustained cost pressures.
So.
As we look at.
Various projects.
Definitely weighs into it.
The greatest cost pressure that that exists today is on solar.
There is at the same cost pressures associated with with.
The wind business there is some but it's not a case again.
Solar production or production of solar panels, and so on is largely Asia at this point in time. So it gets hit with both increasing commodity prices plus transportation costs, which are dramatically higher than they were previously so.
As we approach projects and consider that the cycle time.
Do or are cautious on the solar side and definitely consider the.
Where the costs are going but I would say that what we see going on today.
We're starting to see that the curve is going down we're starting to see transportation costs.
Inching down we're starting to see some of the commodity costs or the forwards declining.
Declining so we are expecting this is a relatively short term.
<unk>.
Excursion and pricing in transportation cost so yes.
Depending on how far out a project.
Procurement is can have an impact on.
Definitely you know how cautious we are around the bidding process.
Excellent. Thank you.
The next question comes from Mark Jarvi with CIBC capital markets.
Please go ahead.
Thanks, Good morning, maybe just going back to the Genesee Repowering can you share anything in terms of how much of the costs have been locked in at this point.
Can't.
I'm just trying to.
A number it doesn't it doesn't come to mind, but we.
So we will be talking about it in.
In depth.
Investor Day, So we'll be sure to comment on on that element of it as well unless you'd like us to follow up with us a number.
I would assume at this point from the large unique items, you've kind of locked annually.
$10 million in the quarter or is it just.
Ongoing labor cost and balance of plant just curious on where you would maybe you still have some exposure to variable costs or things that are not fully priced in yet.
Well there'd still be definitely some some material are being procured.
Definitely there isn't a major elements have been procured and and and the cost for those.
Ben had been established so.
Don't see a lot of forward cost pressures on.
Those materials.
Got it and then coming back to the solar projects in Alberta with the cost increases.
Any comment in terms of obviously, there would be some return erosion now whether or not there's still meeting your hurdle and whether or not they become I think when you think about the sell down strategy. If you feel like the returns have been compromised a little bit.
So we always you know as we as we go through projects and consider projects. We always have in mind, you know the potential sell down strategy.
Associated with them so.
But when we looked at those two projects.
We had.
And both of them are.
Some headroom in terms of returns above our hurdle rates.
As there are developing now and where we expect them to come in from a cost perspective.
They would be coming in.
I would say modestly below.
Our.
Our hurdles, but definitely above our whack so they're not.
There isn't any erosion of shareholder value associated with those projects as they sit today.
Got it that's helpful. Brian and then one more on island generation.
The commentary around the medium term, but also sort of highlighting I think in the MD&A and the book value and carry that in some of the policy changes and PCI, who is looking for and hearing the same thing is gas fired generation.
There are some things that are now you can get a little bit.
Three four year contract and at that point Island, probably has to be decommissioned and taken offline is that what you're trying to kind of outline to us there.
So.
You know a lot of this depends on.
Obviously, where the a b C or.
BC hydro goes in and where.
Things go generally in respect of a power supply or capacity on Vancouver Island.
We still are extremely.
Convinced and Theres nothing that has been brought forward or anything that would suggest that.
Our position is not correct in terms of the meeting.
Island generation to support.
Capacity requirements.
How Vancouver Island.
Our our view and this is actually supported in the.
It's been produced by BC Hydro they have no plans on increasing their capacity to the island or on the island.
Until 2033.
So you know that that longer term need is still there so not much has changed.
In terms of in terms of bar perspective.
<unk>.
Recent.
The indications from the BC government about phasing out natural gas and so on and so forth.
That is.
That's a position open.
Open for comment and we think just us as we go through the.
Our resource plan.
D C hydro.
It'll become clear and we are convinced that in the plans they are expecting for there to be brown outs.
In D C or on Vancouver Island, because they don't have capacity and that's not good planning and.
That's not apparent to me.
The citizens are on Vancouver Island so.
We think.
We think that our position of having ultimately a 10 year contract, although there are different.
Perspectives of the government that are coming out we still think that good.
Planning.
We will ultimately prevail and there will be a.
And your country, even with the latest.
Indications from the BC government in terms of <unk>.
Moving off natural gas.
In terms of.
Power generation that would that would provide for an eight year contract. So we're still very optimistic on the back half.
And certainly what we're seeing in terms of the.
The lack of reliability associated with these undersea.
Lines.
I think is becoming extremely evident and one other things Thats I guess, not a well known as the work that BC hydro is doing on the lines is not increasing the capacity at all it's just ink.
Improving our reliability.
So again.
The need for additional capacity or the capacity of island generation.
He used to be the same as it always has.
That's helpful color. Thanks, Brian maybe just one quick follow up on that then.
Yes.
That that Iot or the updated fire final IP over <unk> 5 billion. This year at that point would you be in a position we hope.
Hope you'll come to the table and that can have an agreement or <unk>.
I couldnt be there'd be negotiations that would take us into mid 2019 before you actually had a regulation on generation.
So in terms of the.
Medium term contracts.
Again that ends up being a process of negotiation that will take.
Into a mini well take into next year.
A lot of it just depends on.
Hum negotiation goes and.
I would say.
The discussions are positive, but they are infrequent right now so again, we will see.
How that how that develops it's as you can appreciate.
Now, we're ready to move and negotiated.
Whatever pace, we're not setting that pace.
When it comes to if they're if theres any further extension or that won't be until the IRT is.
Our proved or modified by the BC, UC, which isn't expected until probably.
Probably at least a year from now so that's where there might be.
Our that's where our further expansion to be negotiated would commence happening.
Got it that's all I had thanks for taking my question.
The next question comes from John Mould with TD Securities.
Please go ahead.
Thanks, Good morning, everybody.
Maybe just starting with the $500 million target for community growth, we're 10 months into the year and I know you.
Noted you can have an announcement.
Before year end, what has made it challenging to to I.
I guess get closer to this target is it that you're holding really tied to your your return targets and opportunities have been maybe more competitive than you'd hoped.
Have you seen some gas fired deals that might make sense, but had some type of hesitation just given ESG considerations.
Can you provide some color on the growth target.
So John.
Are we sort of hold tight to our hurdle rates we don't.
Because we're coming to the end of the year and so on we don't relax.
I think as we've always said.
That's a target that's out there you know if we hit it tremendous.
If we don't that just means that we didn't see any opportunities that were right for four for capital power.
That has happened before where we have not hit the $500 million target.
And from our perspective, that's fine and the longer term our average has been.
$700 million a year, having set the $500 million target. So it averages out in the lungs of last year was.
Well over $1 billion, well, one $7 billion almost in in terms of achieving that $500 million target. So we're not fussed and we feel no pressure to actually we have to do something now in terms of what we've seen we've been in second round on both.
Our renewables and on our.
And on.
Natural gas opportunities. So the market is there, but certainly the traffic isn't on.
On the natural gas side, there's there's been you know definitely if you were opportunities than we've seen historically in a calendar year and likewise from a renewable.
M&A perspective, there has been fewer opportunities.
And from a development perspective, we continue to be very active from from that perspective and.
Really frankly, see where that'll be a lot of our growth coming from.
In terms of the future is from actual development opportunities as opposed to M&A type opportunities just simply the way the market's developing and where we're able to create that.
<unk> is on the development side.
And especially on from a wind perspective, or a solar perspective, not on the M&A side.
Okay. That's great. Thanks for that context, and then maybe just circling back to the Genesee Repowering and <unk> plans.
The federal government brand on net zero electricity by 2035 so.
If that moves ahead that implies there most likely will need to be <unk> in place of Genesee for it to run beyond that and you've pointed out that the <unk> initiative without any debt.
Project needs government support so if that support isn't of the magnitude that you're hoping for do you see a path to recovering.
Some of those costs in the power market over the long term given the lack of any real technological alternative to gas absence, some revolution in long term storage or <unk>.
Commercialize small nuclear how are you thinking about the Repowering project overall.
Case, where the <unk> funding picture doesn't pan out the way you and really the industry overall in Alberta is holding.
I mean the.
If you take <unk> <unk> off the table. The fact of the matter is technology is not here.
Nor is.
Nor are they.
Policies outside of Alberta here that would.
Make it even possible technically possible to eliminate natural gas by 2035, I mean, you've seen the reason.
By the.
ISO in Ontario that saying that.
Being off natural gas by 2030 is just not in any way shape or form practical and now think as to you know what what might it look like when might you know you'd be off natural gas.
I think you'll find that that work will show.
Probably beyond 2035 as is feasible in Ontario, where natural gas is as a much smaller component of the overall mix of energy. So in Alberta, just it's just not practical in when you see government pronouncements.
Being.
They'll even off coal by 2030.
In Canada through the equivalency agreements there are exceptions to that there are going to be coal plants operating in Canada beyond 2030. So.
Gain.
The there is a practical element associated with with any of these pronouncements.
And there seems to have been good.
Discussions are not only in Alberta, but our cross Canada in terms of what's really a practical solution aggressive solutions you know moving forward from a carbon mitigation perspective, but now what's makes sense in each province is different and thus far the federal government is.
We respected that again, that's why there's a b agreement.
For the tier program in Alberta to stand.
And you know continue to be there because it meets the federal objectives in a way that is different for Alberta and suits, Alberta, just like there are equivalents he agreements in most of the other provinces.
Okay. Thanks, very much for all that context, and then just maybe one accounting clarification for for standard on the on the Genesee two outage.
Just as far as the business interruption insurance timing I know you won't.
Know what the final claim is until that returns to service are you expecting to be able to reflect that figure in your.
2021 assets or is it possible, though that doesn't get resolved by the by the time you reported your Q4 results.
Yeah, our expectation is that we would be able to reflect it from an accounting perspective, there has to be reasonable certainty around around the amounts.
If that's the case then you can accrue.
All of that expected or a portion of it but at this point, we have confirmation from the insurers that it is that.
Recoverable.
Events. So that's the first step and then the second part of that is get landing on the amount and the complexity with that is just looking at modeling what your results would have been if there hadn't been an outage and compare that to what you actually achieved and it does look at it from a portfolio perspective I'm not sure.
The loss from the asset but to the extent other other assets in your portfolio are able to pick up some of that that upsetting benefits from having that outage that that comes into play so it.
Is that I get the cult modeling exercise, but we've already started that on our side as has the insurers see that progress progressing quite well so.
Expectation is that when we get to the end of the year will be in a position to to a toilet.
What we did with the with the property side this quarter.
Okay, Great I'll leave it there thank you very much.
The next question comes from Ben Pham with BMO capital markets. Please.
Please go ahead.
Alright, Thanks, Good morning, Adam a couple of follow up questions.
On a gas price you mentioned that you had just opened up in the near term I'm wondering what changed here your gas price assumptions long term modeling.
Gen, One and two right and then you've got other facilities in the province.
Yeah, so when we're modeling out.
Power prices and gas prices.
We do continually update though that the fundamental change that's similar to other third parties, we do see sustained higher natural gas prices over the next year.
A year or two before they started to come down but you can see that it is probably higher than it would have been at the beginning of the year, even when you get out to the back end of the plan but.
It's something we continually refreshing our modeling.
Okay.
We're assuming $2.
One point of time in your models.
At one point in time, yes, we would have been that the natural gas and get over $2 I think coming into this year yeah.
Okay.
You would say then.
Ray you project the gas you tend to lean on on third parties when when you deem that I would assume.
We do look at third party multiple third party forecasts as well as coming up with our own internal view on on that as well, but primarily looking at forward another fundamental forecast from third party.
Okay.
On Sunday Brenna source.
Couple of questions from.
But our folks are.
And then on a project like <unk>.
Extract more I mean, you spent a lot of capex on it already but on sounds like any chance.
You only spent about $6 million or so but you got to contract Labatt and then can you actually walk in shelf that project or is that pretty much Q2 like given the contract.
Well you definitely can walk.
There are.
Penalties associated with walking so.
And even even without walking or even without those penalties.
It would be a tough decision for us to shelf that project.
Just simply as I said.
It's still.
It's still above our whack.
Yeah.
It could be delayed you could do other things to mitigate some of the cost exposure, but.
No.
It's still in our mind.
Remains.
Liable project.
Okay.
Alright, Okay. Thank you very much.
The next question comes from Andrew <unk> with Credit Suisse.
Please go ahead.
Thanks, Good morning, I guess the question really focuses on the power market in Alberta.
Broken up on 11 months since we've had the new market structure.
Could you give us some color on just how the dialogues have changed with counterparties sort of existing in our perspective.
On just their understanding of the market maybe the things you were telling them a year ago, which they were not so sure about what has been the flavor from customers in.
Just the or the willingness to lock into contracts on a longer term basis within the province or to take more spot exposure.
So Andrew it's a very interesting dynamic and the reason why it's a it's an interesting dynamic is when you look at parties, who have been in Alberta for a long time really the on the in the what's new.
What's going on today this takes us back to the power market that existed before 2014.
Into 2015 so.
People, who again were comfortable hedging out positions and so on and so forth and looking at supply demand balance in the future and anticipating where power prices are going up.
This is this is sort of back to normal as opposed to you know the last few years.
So those people continue to look at hedging.
Hedging and they continue to look at the the forward market, but as well you know again their views as you know supply demand is as I think everyone knows there's significant supply that's going to be coming into the market.
In the mid part of this decade, and so again looking forward they come up with their own expectations new people in the market people, who are hard or just recently looking for power supply in Alberta.
I would say there is still.
<unk> to be fairly hesitant.
Our higher power prices.
Particularly in light of more recent quite quite a bit lower power prices and trying to sort out a little bit more of what's going on but those people who are experienced again do do do recognize this is a relatively simple markets based on supply and demand.
Economics, plus inputs, such as things like our natural gas price and.
Increasing carbon tax.
Okay. Thank you for that and then maybe just on the carbon tax and really the credit market in general and any insights you have or market flavor by jurisdiction would be appreciated but just.
The desire for certain customers or even yourselves to effectively byproducts in the market or.
We engaged in activities that are and give you more offsets versus paying carbon taxes outright I know it gets very technical on all of us, but any flavor you can provide there would be helpful.
[laughter].
You know if you went back.
A couple of years and talking about Alberta, you know in particular, you know there was a very active market.
A lot of trading taking place a lot of projects.
And developers who are looking for people to support longer term carbon sales contracts.
A lot of that has slowed down significantly just simply because there is a little bit more uncertainty.
And there ends up being.
You take the posted price of carbon today versus what the market prices there tends to be you know.
And the discount that ranges from 10% to 25% depending on you know.
When trades may have taken place so.
There's the market is I would say a little bit more uncertain now and again because of that we're seeing.
A little less activity in terms of people developing.
Carbon credits.
But also in terms of people willing to necessarily buy them because.
Because they arent at you know nobody today is going to pay.
$120 for carbon credits out a couple of years, they're just that's just not sort of in.
And where are people are feeling comfortable in terms of.
Paying for carbon credits. So again, there's discounts in the market and has time gets moves on.
And.
Higher prices are being realized.
I think youll start seeing the market coming back and more and more activities associated with trying to find ways to.
Produce carbon credits and capitalize on them.
Okay. Thank you that's very helpful.
Once again, if you have a question. Please press Star then one.
The next question comes from Nike by doing with I E capital markets.
Please go ahead.
Hi, Good morning, just wanted to go back to a couple of points starting with the drip.
If you can give us just a bit more color on why it made sense to suspend it not long after it was turned on I guess the question is.
Is this really a reflection of a slowing development, maybe relative to where you're able to source last year or is it more that you expect maybe asset sales or other financing options to fill.
Our future funding needs.
Yeah. Thanks for that if you go back to when we turn the drip on and in.
The middle of 2020 at that point in time.
We weren't seeing the forward prices that we're seeing today we were.
Well moving forward with a number of renewable project as well as Repowering. So certainly wanted to be in a position, where we were raising equity in advance of.
Of that spend in order to maintain our credit metrics.
When youre looking at are at therefore, the gap with S&P. For example, there is a 17% threshold.
There are there is there.
The requirement to to achieve that even if you are in a period of prolonged construction like Repowering. Historically, you may have seen I look through period, when you're in construction, where they would allow you to go below your thresholds.
And take a view as to what the impact of the construction would be and that certainly is not not the case that they look for so we knew that maintaining our credit metrics was very important as we embarked on on that construction. So when.
When you were coming through the middle of last year still looking at power prices in Alberta for 2022, and 23 that are well below where we are today.
It was prudent for us to include the drip.
To build up that that equity and we had this Scott how else we would fund the equity side of those projects end and opted to do an offering at the point that the drip is turned off at all raised approximately $80 million.
Funding as well with a $288 million of offering that that's in the range of the amount of equity we felt that we needed and with them our cash flows and internally generated cash being much stronger than anticipated and we just don't have been got current episode that is well above 20.
So we're maintaining a lot of attrition so.
So at this point don't need anymore more equity for for the growth that we have and you can have enough balance sheet strength that if we could do it.
Mental funding not seen that that we would need to access equity to be able to do that.
Keeping the drip on like with just being dilutive.
At this point so.
There's just no reason to turn it on and has nothing to do with with the planned on asset sales or anything else. It it's more of the internally generated cash flow.
Yeah.
Takes away the need for us to maintain the gap.
Okay got it that's great detail. Thank you Sandra and maybe just going back to island generation for a for a minute.
Brian You said.
Besides there is not looking to build new capacity, but let's say the re contracting discussions don't really go the way you want them to or even if it's not.
Only on a shorter term contract have you had any discussions with them about installing new generation capacity sooner.
To replace our island generation.
So there.
The ire P is very clear that they're not looking at installing.
Whether it'd be batteries, whether it would be and by the way battery technology, obviously can.
Place.
The capability of island generation to run for six months. So you can possibly do that with her with a battery. So no there their plans are to just.
Remove island capacity I mean, they have some hopes around.
Reduced demand in the province, reduce our well across the province button, but conservation efforts on Vancouver Island, but on the other hand, they've got great expectations around electrification of vehicles and other things so.
Hum.
Don't see the demand on Vancouver Island going down yet.
The capacity that they needed historically, they are willing to a band.
And then that's why I'm, suggesting that.
In their detailed modeling, which hasn't seen the light of day yet. They are we would expect a fully are expecting to have.
Increased outages on on Vancouver Island, when there are no constraints or problems on our transmission system.
And periods of high heat or extreme cold or dry years from a from a hydro perspective, all create strains on Vancouver Island.
I mean, we do we just don't get it.
I just don't I.
Don't understand how you would be planning for a for a.
An increase in outages.
But in any event and there isn't.
There is no indicated path in any way shape or form to two two.
Replace island generation.
Until 2020 until 2033.
Okay understood I mean, it sounds like that something has to give a at some 0.1 way or another so we'll wait for more details on that.
In the next few months.
Okay.
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'll conclude our conference call. Thank you again 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.
You for participating and have a pleasant day.
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Yeah.
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