Welcome to Capital Power's Third Quarter twenty sixteen Results Conference Call. At this time, all participants are in listen only mode. Following the presentation, the conference call will be opened for questions. This call is being recorded today, October 2436. I would now like to turn the call over to Mr.
Randy Mah, Senior Manager, Investor Relations. Please go ahead.
Good morning, thank you for joining us today to review Capital Power's third quarter twenty sixteen results, which were released earlier this morning. The financial results and the presentation slides for this conference call are posted on our website at capitalpower.com. We'll start the call with opening comments from Brian Vagil, President and CEO and Brian Denis, Senior Vice President and CFO. After our opening remarks, we'll open up the line to take your questions. Before we start, I would like to remind listeners 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 may differ materially from the company's expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward looking information on Slide number two. In today's presentation, we will be referring to various non GAAP financial measures as noted on Slide number three. These measures are not defined financial measures according to GAAP and do not have standardized meanings described by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. Reconciliations of these non GAAP financial measures can be found in the third quarter twenty sixteen MD and A.
I will now turn the call over to Brian Vagil for his remarks starting on Slide four.
Thanks, Randy. I'll start off with a quick review of our highlights for the third quarter. Capital Power's financial performance in the third quarter was modestly ahead of management's expectations. This included achieving normalized earnings per share of $0.31 and generating $94,000,000 in funds from operations. Brian will provide more details in his financial review.
We continue to be engaged with the Alberta government to ensure fair compensation is received for the accelerated closure of coal fired units by 2030 under the Climate Leadership Plan. The coal phase out facilitator has provided his recommendations to the Alberta government and we expect the government to provide more details before the end of the year. A significant achievement for the company was a completion of two recent financings. This included a private placement of $160,000,000 ten year note during the quarter and a $200,000,000 preferred share offering in early October. Brian will provide more details on these transactions in his comments.
With these financings and the recent extension of our $1,000,000,000 in credit facilities, we have improved our liquidity and have strengthened our balance sheet and financing capabilities in the medium term. Turning to Slide five. For the Genesee four and five project, we have moved full notice to proceed decision from the fourth quarter of this year to the first quarter of twenty seventeen. As previously disclosed, a decision on whether or not to proceed with the project continues to be contingent on three factors. Specifically an announcement of fair compensation by the Alberta government, clarity that implementation of the climate leadership plan will have no adverse impacts on the market design of Alberta's electricity market, and adequate price signals from the wholesale electricity market.
Based on the current schedule, we would have substantial completion of Genesee 4 in 2020, if full notice to proceed is given in the first quarter of twenty seventeen. Moving to Slide six, this slide summarizes the plant availability operating performance of our plants for the third quarter of twenty sixteen compared to the same period a year ago. We had solid operating performance in the third quarter with average plant availability of 96%, which was slightly better than the 95% in the third quarter of twenty fifteen. Our third quarter year to date basis, we have achieved average availability of 94%. Our operations have exceeded expectations for the year to date and forecast for the end of the year.
Operations by others have not met expectations and accordingly, we expect to fall modestly short of our combined annual target of 94. I'll now turn the call over to
Brian Denis. Thanks, Brian. I'd like to start off by highlighting the recent financing transactions on Slide seven. In the third quarter, we completed a long term private placement debt financing with Prudential Capital Group. We raised $160,000,000 with a ten year term, and the debt is non amortizing.
The interest rate is an attractive 3.85%, payable semiannually. Subsequent to the end of the third quarter, we successfully closed the $200,000,000 offering of preferred shares. We now have four series of preferred shares, and these hybrid instruments fit well within our capital structure to enhance credit rating metrics. The proceeds from these financings were used to reduce our indebtedness on our credit facilities and resulted in a significant improvement in liquidity. We essentially have almost all of the 1,055,000,000 in committed credit facilities available.
As Brian mentioned, with these financings and the extension of the credit facilities, we have strengthened the balance sheet and our financing capabilities in the medium term. Turning to Slide eight, I'll review our third quarter financial performance. Overall, financial performance in the third quarter was modestly ahead of our expectations, but slightly lower on a year over year basis. We generated $94,000,000 in funds from operations, which was down 3% compared to $97,000,000 in the third quarter of twenty fifteen. We reported normalized earnings per share of $0.31 which was slightly below the $0.33 in the third quarter a year ago.
Due to excess supply, low natural gas prices and conservative offer strategies from market participants, Alberta power prices in the third quarter averaged 18 a megawatt hour compared to $26 a megawatt hour in the third quarter of twenty fifteen. Despite the 31% year over year decline in average power prices, our trading gas performed well and captured a realized price of $70 a megawatt hour on our Alberta commercial assets. That is 289% higher than the average spot price in the quarter. Moving to Slide nine, I'll review our third quarter financial results compared to the third quarter of twenty fifteen. Revenues were $378,000,000 down 19% from the third quarter of twenty fifteen, primarily due to strong portfolio optimization results in the third quarter of last year.
In June 2015, the trading desk was able to secure a portion of commercial production for the third quarter of twenty fifteen when forward rates increased temporarily that month. Adjusted EBITDA before unrealized changes in fair values was $120,000,000 down 6% from the third quarter of twenty fifteen. That was primarily due to lower excess energy incentive revenues from lower Alberta pool prices and higher coal costs in the Alberta contracted plant segment. Normalized earnings of $0.31 per share decreased 6% compared to $0.33 a year ago. As mentioned, we generated funds from operations of $94,000,000 in the third quarter, which is down 3% on a year over year basis.
Turning to Slide 10, I'll quickly cover our financial results on a 2016 year to date basis compared to the same period in 2015. Overall, the financial results in the first nine months of the year show improvement across all measures. Revenues were $948,000,000 up 4% year over year. Adjusted EBITDA before unrealized changes in fair values was $371,000,000 up 10% from a year ago due to the termination of the Sundance CPA and strong portfolio optimization results. Normalized earnings per share were $0.95 on a year to date basis in 2016, up 30% compared to $0.73 a year ago.
Funds from operations were $3.00 $9,000,000 in 2016 year to date, which is up 12% on a year over year basis. I'll conclude my comments with a review of our Alberta commercial hedging profile on Slide 11. The termination of our buyer role under the Sundance CPPA, combined with additional sales in the forward market, has significantly increased our baseload hedging profile since the end of twenty fifteen. The table on the slide shows quarter over quarter change from Q2 twenty sixteen on a comparative basis. For 2017, there were no changes and we continue to be fully hedged at an average contracted price in the mid-forty dollars per megawatt hour range.
In 2018, we have increased our hedges from 49% to 52% at an average contracted price in the low $50 a megawatt hour range. And for 2019, we have slightly increased our hedges from 38% to 39% at an average contracted price in the low $50 per megawatt hour range. In summary, our baseload merchant exposure is fully hedged for remainder of the year and for 2017, and we continue to make progress in reducing our merchant exposure in 2018 and 2019. I'll now turn the call back to Brian Gajeau.
Thanks, Brian. On Slide 12, I'll quickly review our year to date operational and financial results at the end of the third quarter compared to the 2016 annual targets. After the first nine months of the year, average plant availability was 94% consistent with the annual 94% target. But as I explained earlier, we expect it to fall modestly below the 94%. Our sustaining CapEx was $38,000,000 versus the $65,000,000 annual target.
We reported $155,000,000 in plant operating and maintenance expenses versus the 200,000,000 to $220,000,000 target. Finally, we've generated $3.00 $9,000,000 in funds from operations so far this year and expect FFO to exceed the midpoint of the $380,000,000 to $430,000,000 annual target range. Turning to Slide 13, we have two development and construction growth targets in 2016. As mentioned previously, the full notice to proceed decision for Genesee 4 And 5 has been moved to the first quarter of twenty seventeen with construction contingent on receiving clarity regarding the impact of decisions from the climate leadership plan. The project is also dependent on receiving adequate price signals from the wholesale electricity market.
Finally, Slide 14 compares our growth outside of Alberta, which involves executing a contract with the output of new development. As announced in the first quarter, this was achieved with our Blum wind project. Blum has a ten year fixed price contract covering 100% of the output. Construction of the project has started with commercial operations expected to start in the third quarter of this year. In addition to Bloomwind, we are actively bidding into RFPs for the other U.
S. Projects. I'll now turn the call back over to Randy.
Thanks, Brian. Operator, we're ready to start the question and answer session.
We will now begin the question and answer session. The first question comes from Linda Ezergailis, TD Securities. Please go ahead.
Thank you. Congratulations on a strong quarter. With respect to the Sundance PPA cancellation, I appreciate disclosure in your notes that you expect it not to be materially adverse to your financial position in terms of the outcome. But can you talk a little bit about what the possible ranges of timing of resolution might be? I know that the court hearing would be later in 2017, but is there a chance it might get settled out of court sooner?
And can you comment on what some of the various arguments might be in this process?
Linda, good morning. Obviously, the whole issue is under litigation right now. The government has indicated some willingness to enter into conversations. And again, any conversations would be extremely confidential as well. So unfortunately, can't really provide any helpful comments at this point.
And just as a follow-up, and I appreciate there's some confidentiality, but does this affect how Capital Power views future investments in the province? Or would you see this kind of as an isolated situation?
Well, I think we've said even at the outset that we didn't see that both the PPAs going back and the government action as being actually indicators of the market itself. It's more anomalies associated with the completion of the transition instruments. So again, not although it has implications in the market, it's not really market related.
Okay. Thank you. And just further to some of the big picture decisions you're looking at over the next couple of years. Are you looking at coal to gas conversion in any way still? And do you see that as one of the preferred options to avoid stranded capital and minimize increases in customer costs in Alberta?
Or is that something that is not a priority right now?
Certainly, given that they are existing assets, we continually look at ways in which to optimize the assets going through the next fourteen years, but as well looking at trying to optimize or maximize any value that might be available to us after 02/1930. So ongoing activities from that perspective.
Thank you. And just final cleanup question. And maybe this is a question for the other Brian. Sustaining capital in 2016 might be below target. Will that be deferred to 2017?
And should we think of sustaining capital activity being higher in 2017 or continue with the $65,000,000 run rate?
No, I would suggest that the $65,000,000 run rate is appropriate. Certainly, the reduction you're seeing this year has been gains and areas of scope reduction that aren't deferred, but just improvements this year.
Okay. So can we use year to date as trend for Q4? Or is there some higher activity in Q4 that we might want to think about?
No, there isn't any higher activity in Q4. Great. Thank you.
The next question comes from Rob Hope, Scotiabank. Please go ahead.
Yes. Thank you for taking my question today. Just another question just regarding the climate leadership plan in Alberta. Your presentation notes that you continue to be engaged with the government. Just want to get a sense of whether or not you are still negotiating after Mr.
Boston had put in his report and whether or not you can talk about any specifics there?
So as you can appreciate, although Mr. Boston's work was complete on schedule. It moves it from his work into the government itself. So we are continually talking to the government, providing our views, providing what we think, etcetera. So it's an ongoing process until, of course, the government comes out with its decisions.
It's major for us. We can't just simply let his report go forward and us to sit back and wait for an outcome. We have to engage the government as much as we can to impact on whatever their decision may be.
All right. That's helpful. And as a follow-up, the majority of your comments on the carbon side have been at the provincial level. Just want to see if you have any thoughts on the potential implications for the federal plan that would see the carbon price move up to $50 per megawatt hour and potentially not baseline power generators costs on an equivalent gas unit, but rather on an absolute level.
Yes. The certainly, we're monitoring that very closely. It's a little bit uncertain at this point in time, the scope and the magnitude of implementation that would occur. And certainly there's avenues for actual regulatory or structural exemptions. For example, would think that the oil sands and the cap associated with it may potentially create an exemption for that industry.
And again, expect those to happen throughout and it may well be with the truncation of coal lives in 2030 that may provide capital power with, I'll call it, a structural exemption from those significantly higher carbon costs.
That's helpful. Thank you.
The next question comes from Jeremy Rosenfield with Industrial Alliance Securities.
Just a couple of questions. Just first on the hedging. There's a note there just in the presentation about the change in the reporting. And I'm just wondering if this is really just how you're calculated it and how you're displaying it in your disclosure? Or if there's actually a strategy change in terms of how you're thinking about the Shepherd plant going forward and how you expect to be hedging relative to expected output from the plant?
Yes. So it's the answer is yes to both of those. So what we've seen with Shepherd is that with natural gas prices actually coming in lower than was initially anticipated, coupled with increases in the carbon tax and the implications for variable costs on coal fired units, we're seeing Shepherd operate at a much higher capacity factor than initially anticipated. So as a result of that, we are looking at the full output from that plant is more from a base load generation perspective, which means we're looking to hedge in on a seventwenty four basis. So as a result, what we've done in the from the base load hedging percentages, the full output from Shepherd that we control are to now reflected in there as opposed to the minimum stable generation.
So it's about double the capacity.
Right. So then looking forward, just following on that. So looking forward, in theory, you would look to acquire, let's say, more hedges going forward than you had previously envisioned based on the change in that strategy, recognizing that can operate Shepard more reliably?
That's correct. Yes.
Okay, perfect. And then just turning to G4 and G5 for a second. Assuming that you do move forward with the full notice to proceed in Q1, would that imply a late twenty twenty completion date? Is that sort of a late year type of completion?
We're continually looking at the profile of construction and completion dates. With the shift, it was pretty much initially a recognition of a month month for month movement. Having said that, we'll continually try to move it back further or the opportunity to move back further into 2020. So it is now in the latter part of 2020.
Okay. And then would you expect that you would need to do a capital cost estimate or complete an updated capital cost examination before you actually declare full NTP?
No. And the reason being is because we have both the equipment lined up and committed to as well as contractors in the Alberta environment. If anything, a review might a close review might result in a bit of a reduction in costs. But these escalations, think as we've commented all along, we've put these contracts in place such that we would have the flexibility to move them. This recent move that we've undertaken actually costs the project through these escalation fees about $9,000,000 on approximately 1,000,000,000 point dollars project.
So it's relatively modest. And again, that's because the contracts have been established from that perspective.
Right. And you're saying that the costs could be lower and your thinking there is basically that labor costs have come off in the Alberta work environment. Is that is that what's the guiding that?
Well, I wouldn't say necessarily at this point the cost has gone down in terms of, I'll call it, an hourly cost per labor. It's becoming clearer and clearer that labor will be available and there won't necessarily be those kinds of constraints. So I wouldn't expect there to be a significant reduction in cost if there were one.
Okay. But just maybe some pressure on costs.
So Yes.
Okay. Great. Those are my questions. Thanks.
The next question comes from David Quezada with Raymond James. Please go ahead.
Thanks. Good morning, guys. Just a follow-up on G4 and G5. Can you provide any color on whether or not you could defer that again or if you think you'll need to? Or is the early twenty seventeen or 1Q 'seventeen date, is that kind of the final deadline?
We continue to have, again, significant flexibility with these arrangements. So we could definitely defer it again. However, the next deferral would likely result in moving the schedule significantly in terms of its completion date.
Okay. Okay. That's helpful. Thank you. And then apologies if you've given color on this before, but you remind us what kind of price signals in the wholesale electricity market?
Any kind of color you can provide on what you'd want to see in order to satisfy that element of the decision?
Well, you'd have to see the forwards in the range of $60 plus. I won't get too specific there. And you'd have to be comfortable with that. But also our own internal forecast would have to be very much aligned with that kind of pricing going forward. And as you may know, the forwards for 2021 at this point or in 2020 pushing up towards the $60 range.
Right, of course. Okay, that's great. That's all I had. Thank you.
The next question comes from Ben Pham with BMO Capital Markets. Please go ahead.
Okay, thanks. Good morning. I wanted to go to the quarter and specifically on Alberta commercial and looking at your realized pricing, you achieved $70 When you look at, I guess, your position coming to the year, I believe it was about $50 type of hedges or a little bit higher than that. So I mean is the difference mostly related to the Sundance PPA driving that outperformance in commercial? Or is it the reaching of the hedging profile throughout the year?
So it's a combination of both. So with under the Sundance Sea PPA, we have costs probably in the $38 a megawatt hour range. So when we push back the Sundance Sea PPA, that certainly made us shorter in our position. Our decision was looking at where our view was on forward prices versus fundamental prices. We didn't replace all that power right away.
And so as we've gone through the year, we've been able to buy that power back at a price much below what the cost was under the PPA. So it's that in combination with a trading strategy we already were executing in place. So it's a combination of the two.
Okay. So that calculation of $70 it's you're including the difference between your the spot price and what would cost to operate to produce that megawatts, but then your denominator doesn't include any of the Sundance production hypothetically?
That's correct.
Okay. Thanks, Brad. And then on the Sundance sorry, the PPA termination consultation that's going to start to come to next year and then the stranded coal compensation. Do you guys get the sense that, that consultation and decision making is being run independently from the government perspective?
Our understanding is the government is looking at electricity sort of in its totality and is looking and ensuring that there aren't any market implications or unintended consequences across the whole spectrum of decisions that they're making. So whether they're combined or in consideration or not, that's not really clear. But I would say that, again, the government is looking at things as comprehensively as practical.
Okay. And last one for you guys is just when you on the Genesee four and five, you mentioned one of the three conditions is no change in or sorry, no adverse change in market design rules. Are you assuming that the government would maintain the energy only market design? Certainly,
that's been our position that the energy only market, left alone provides a tremendous environment for us to continue to build and so on. But that isn't necessarily the only answer. And we'll see it at the end of the day, what market structure ultimately might prevail in Alberta. But certainly, we've been very strong and believe that the best answer is the energy only market.
Okay. So it seems like you're open to maybe capacity type of market assuming the return profile for prospective projects aren't changing. So it's not necessarily an energy only market as a base case.
Well, think we'd be foolish not to consider any healthy, properly balanced, reasonably economically positioned market. So we'd certainly consider anything that evolves or develops. The
next question comes from Patrick Kenny with National Bank Financial. Just
on the higher coal costs for G1 and G2. Wondering if you can give us some color on what's driving the increase there and if you expect those cost pressures to continue into 2017 or if you're looking to bring those costs down somehow?
Yes. So in terms of Genesee at Mine, as we look forward, we are seeing opportunities to bring those costs down. So that's something that we're taking into consideration as we look at 2017 and beyond.
Okay. And then just with respect to your financial targets, can you remind us what your target balance sheet ratios are? And perhaps dovetail a comment on how you're thinking about your NCIB now that you've locked in $1,000,000,000 or so of liquidity?
Yes. So in terms of our debt ratio, we would like to move towards pushing that above the 40% range at some point. Certainly, we're very mindful, though, of our FFO to debt metric, which is probably the metric that's most important at this point in time to S and P and DBRS. So we look to balance those two. In terms of with the recent financings that have been done, it does create a much stronger balance sheet.
But we believe that will play into the fact that we're going to see additional growth opportunities crystallizing. So we're bidding in on two to three wind RFPs at any point in time. So fully expect as we move through the balance of this year and next year, we'll see one to two additional wind projects moving forward. And that's where our discretionary cash flow will be flowing to, but also the prospect of final notice to proceed potentially on Genesee four and five. So given that growth opportunity that we expect to materialize, we won't be looking to do any share buybacks under the NCIB at this point.
Okay. And sorry, Brian, just because your FFO is trending slightly above your midpoint of your target range for the year. Can you just remind us what the target FFO to debt range would look like going forward?
Yes. So we look to maintain our FFO to debt metric sort of no lower than 16%, 17%. This year with a stronger cash flow, we're coming in more in the 20% range, which is obviously very positive from the rating agencies' perspective.
Got it. Maybe just lastly, again, to clarify a little bit on G4 and G5 here. So would a positive FID in Q1 sanction both G4 and G5? Or do you have the flexibility to lag the in service date of G5?
We certainly have the flexibility to separate those projects and bring them in at different points in time. So definitely that ability is there.
The next question comes from Robert Kwan with RBC Capital Markets.
Recognizing you don't want to disclose any specifics, but do you know what is in Terry Boston's report?
No, we have not seen Terry Boston's report. Obviously, in discussions with Terry and so on, we've got a reasonable sense of what he might have been providing to the government. But again, have not had not seen his report.
Got it. So I guess just to be completely clear that the discussions or the negotiations did not result in a kind of settled path forward that's going be put in front of the government for approval?
So I characterize it as we and can't really speak for the other coal companies, we had some definitive input into his thinking and into the process. Some of it, we believe, had some traction. But what he ultimately provided to the government the recommendations that he made, again, we never saw that.
Got it. And I guess last on that, what do you see as the process forward? So the government is going to come out with something based on his report. Do you see that as kind of a final decision? Or do you think then there's going to be a consultation process?
I guess just ultimately, how do you see the timeline and the path forward here?
My expectations is that anything that comes out will be final. There may be obviously a little bit of verification or fine tuning or something of that nature. But don't see I mean from a materiality standpoint, I think it will be somewhat final when it comes out.
Okay. Just thinking about contracted power, your goal to increase that in acquisitions, there's a number of asset packages up for sale. But just without getting into specifics, it's likely based on what those will go for, probably not going to be particularly accretive to cash flow and EPS, and you've talked about valuations being high. I'm just wondering, though, how do you think about that trade off of it not necessarily being particularly accretive to cash flow or EPS, but do you see value in accelerating the mix of contracted power and diversifying geographies, especially away from the uncertainty that we have in Alberta?
Yes, absolutely. So when we look at those opportunities and it probably also goes for developing contracted assets. We're looking for growth in that area to really bolster the stability and growth in our dividend. So there's a very good fit there, but also the benefits of diversification. You're absolutely right.
I think the acquisition or development of contracted assets isn't necessarily going to be highly accretive to our metrics, but certainly fit very well to those other strategic objectives.
Okay. And maybe I can just ask a quick cleanup here on the quarter. On the Alberta contracted side, we had a small tick up in the spot price sequentially. So versus Q2, availability was stronger than Q2, yet the EBITDA was down about $5,000,000 Was that all coal costs? Or is there something else that's going on in that segment?
Yes. What's happening in the Alberta contracted segment with Genesee one and two is the balancing pool pays us the thirty day rolling average for to the extent we beat the availability target that's embedded in the power purchase arrangement. So given the strong availability of our coal assets, we systematically exceed that target availability and receive that thirty day rolling averages and availability incentive payment. The very low pool price environment, of of course, is resulting in that being less than what we would have anticipated at the start of the year.
So sorry, were you accruing something differently in the results in Q2 and therefore you had to true it up in Q3?
No, not at all.
Because price is up, availability is up, yet financial performance is down in Q3 versus Q2.
Are you referring just to Genesee one and two or overall?
Correct. No, just the contracted segment.
Right. So yes, there's a lot of other parts moving there. So sorry, I was speaking more generally to what we're seeing in 2016 for Genesee one and two. But specifically between Q2 and Q3, we had an outage at Genesee in Q2. And that outage actually, I think as we commented last quarter, was shorter than anticipated and came in much lower cost.
So that actually gave us a lift relative to expectations for Q2.
The next question comes from Robert Ketalev with CIBC. Please go ahead.
Sure. Just a follow-up on Ben Pham's line of questioning here. Can you share with us a view on what type of market structure for renewables would be most supportive for moving forward to G4 and G5? In other words, is there any type of market structure they might come out with that would give you cause for concern about what prices might be achieved in the wholesale market?
So from our perspective and again, we've been long time supporters of the energy only market. And there's basically two market structures that are, I'll say, in play right now. One is a REX structure, which is basically topping off above pool price. We see that one being the most supportive of the energy only market just because you end up with more participants. You end up with all of the renewable interests aligned with the events and what's happening in the energy only market.
The other one, which is a contract for differences approach, we see as not having necessarily people as aligned as the energy only market, but we don't see that as a negative as it relates to the market structure. The one thing though that we are very focused on and very concerned on is the rate in which the renewables come into the market and the degree to which they match coal retirements. Our big concern, our big issue as it relates to renewables is whether or not the government policy drives for an overbuild either at periods in time or systematically, which of course has an impact of artificially reducing prices.
Understood on the overbuilt, but even with some of those other structures you mentioned, are you not worried that there'd be an incentive for the renewable producers to bid into the pool to make sure that they're either getting maximum value out of their subsidies or that sort of impact and therefore changing the power stack and limiting the energy price?
Odds are they'll all be bidding in at zero in any event. They'll be price takers. So whether that's under a rec process or whether that's under a contract with differences, probably doesn't make a difference under today's market structure.
There
are no other questions at this time. I will turn the call over to Mr. Randy Ma. Please go ahead.
Okay. Thank you, operator. Please mark your calendars for Capital Power's eighth Annual Investor Day event, which will take place on December 7 in Toronto. More details will be announced closer to the date. Thank you for joining us today and for your interest in Capital Power.
Have a good day, everyone.
Ladies and gentlemen, this concludes Capital Power's third quarter earnings conference call. You may disconnect your lines. Thank you for your participation, and have a
nice day.