Welcome to Capital Power's third quarter 2016 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 24, 2016. 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 2016 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 will start the call with opening comments from Brian Vaasjo, President and CEO, and Bryan DeNeve, Senior Vice President and CFO. After our opening remarks, we will open up the lines to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this conference 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 2016 MD&A. I will now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
Thanks, Randy. I will 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 CAD 0.31 and generating CAD 94 million 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. We expect the government to provide more details before the end of the year. A significant achievement for the company was the completion of two recent financings. This included a private placement of CAD 160 million 10-year note during the quarter, a CAD 200 million 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 CAD 1 billion 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 2017. 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 Four in 2020 if full notice to proceed is given in the first quarter of 2017. Moving to slide six. This slide summarizes the planned availability operating performance of our plants for the third quarter of 2016 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 2015. 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 Bryan DeNeve.
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 CAD 160 million with a 10-year term, and the debt is non-amortizing. The interest rate is an attractive 3.85%, payable semi-annually. Subsequent to the end of the third quarter, we successfully closed a CAD 200 million 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 CAD 1.055 billion 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 CAD 94 million in funds from operations, which was down 3% compared to CAD 97 million in the third quarter of 2015. We reported normalized earnings per share of CAD 0.31, which was slightly below the CAD 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 CAD 18 a megawatt hour compared to CAD 26 a megawatt hour in the third quarter of 2015.
Despite the 31% year-over-year decline in average power prices, our trading desk performed well and captured a realized price of CAD 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 2015. Revenues were CAD 378 million, down 19% from the third quarter of 2015, 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 2015 when forward rates increased temporarily that month. adjusted EBITDA before unrealized changes in fair values was CAD 120 million, down 6% from the third quarter of 2015.
That was primarily due to lower excess energy and incentive revenues from lower Alberta pool prices and higher coal costs in the Alberta contracted plant segment. normalized earnings of CAD 0.31 per share decreased 6% compared to CAD 0.33 a year ago. As mentioned, we generated funds from operations of CAD 94 million 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 CAD 948 million, up 4% year-over-year. adjusted EBITDA before unrealized changes in fair values was CAD 371 million, up 10% from a year ago due to the termination of the Sundance PPA and strong portfolio optimization results.
normalized earnings per share were CAD 0.95 on a year-to-date basis in 2016, up 30% compared to CAD 0.73 a year ago. funds from operations were CAD 309 million 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 PPA, combined with additional sales in the forward market, has significantly increased our baseload hedging profile since the end of 2015. The table in the slide shows quarter-over-quarter change from Q2 2016 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-CAD 40 per megawatt hour range.
In 2018, we have increased our hedges from 49%-52% at an average contracted price in the low CAD 50 a megawatt hour range. For 2019, we have slightly increased our hedges from 38%-39% at an average contracted price in the low CAD 50 per megawatt hour range. In summary, our baseload merchant exposure is fully hedged for the remainder of the year and for 2017. We continue to make progress in reducing our merchant exposure in 2018 and 2019. I'll now turn the call back to Brian Vaasjo.
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. As I explained earlier, we expect it to fall modestly below the 94%. Our sustaining CapEx was CAD 38 million versus the CAD 65 million annual target. We reported CAD 155 million in plant operating and maintenance expenses versus the CAD 200 million-CAD 220 million target. Finally, we've generated CAD 309 million in funds from operations so far this year and expect FFO to exceed the midpoint of the CAD 380 million-CAD 430 million 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 Four and Five has been moved to the first quarter of 2017, 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 for the output of new development. As announced in the first quarter, this was achieved with our Bloom wind project. Bloom has a 10-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 Bloom wind, 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. 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're 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 Linda Ezergailis, TD Securities. Please go ahead.
Thank you. Congratulations on a strong quarter. With respect to the Sundance PPA cancellation, I appreciate the disclosure in your notes that you expect it not to be materially adverse to your financial position in terms of the outcome. 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, is there a chance it might get settled out of court sooner? 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. Again, any conversations would be extremely confidential as well. Unfortunately, can't really provide any helpful comments at this point.
Just as a follow-up, I appreciate there's some confidentiality, 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. Again, although it has implications in the market, it's not really market-related.
Okay, thank you. 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? Do you see that as one of the preferred options to avoid stranded capital and minimize increases in customer costs in Alberta? Is that something that is not a priority right now?
Well, certainly, given that they are existing assets, we continually look at ways in which to optimize the assets going through the next 14 years, but as well, looking at trying to optimize or maximize any value that might be available to us after 2030. Ongoing activities from that perspective.
Thank you. 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? Should we think of sustaining capital activity being higher in 2017 or continue with a CAD 65 million run rate?
No, I would suggest that the CAD 65 million run rate's appropriate. Certainly, the reduction you're seeing this year has been gains in areas of scope reduction that aren't deferred, but just improvements this year.
Okay, can we use year-to-date as a 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 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.
As you can appreciate, although Mr. Boston's work was complete on schedule, it moves it from his work into the government itself. We are continually talking to the government, providing our views, providing what we think, et cetera. 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. 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 CAD 50 per megawatt hour and potentially not baseline power generators costs on an equivalent gas unit, but rather on an absolute level.
Yeah. Certainly, we're monitoring that very closely. It's a little bit uncertain at this point in time, the scope and the magnitude of the implementation that would occur. 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. 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 significantly higher carbon costs.
That's helpful. Thank you.
The next question comes from Jeremy Rosenfield with Industrial Alliance Securities. Please go ahead.
Yeah, great morning, everybody. 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. I'm just wondering if this is really just how you've 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 Shepard plant going forward and how you expect to be hedging relative to expected output from the plant.
Yeah. The answer is yes to both of those. What we've seen with Shepard 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 Shepard operate at a much higher capacity factor than initially anticipated. As a result of that, we are looking at the full output from that plant as more from a base load generation perspective, which means we're looking to hedge in on a seven by 24 basis. As a result, what we've done from the base load hedging percentage is the full output from Shepard that we control, it's now reflected in there, as opposed to the minimum stable generation. It's about double the capacity.
Right. Looking forward, just following on that, 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 you can operate Shepard more reliably.
That's correct. Yes.
Okay, perfect. Just turning to G4 and 5 for a second. Assuming that you do move forward with the full notice to proceed in Q1, would that imply a late 2020 completion date? Is it sort of a late-year type of completion?
Well, 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 for month movement. Having said that, we'll continually try to move it back further, or the opportunity to move back further into 2020. It is now in the latter part of 2020.
Okay. 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. 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 close review might result in a bit of a reduction in cost. These escalations, I 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 CAD 9 million on an approximately CAD 1.5 billion project. It's relatively modest. Again, that's because the contracts have been established from that perspective.
Right. 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 what's 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. Wouldn't expect there to be a significant reduction in cost if there were one.
Okay. Just maybe a release of pressure on costs.
Yep.
Okay. Okay, great. Those are my questions, thanks.
The next question comes from David Kaszuf with Raymond James. Please go ahead.
Thanks. Morning, guys. Just a follow-up on G4 and five. 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 2017 or one Q17 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. That's helpful. Thank you. Then, apologies if you've given color on this before, but could 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 for it to satisfy that element of the decision?
Well, certainly you'd have to see the forwards in the range of CAD 60 plus. I won't get too specific there. You'd have to be comfortable with that. Also, our own internal forecast would have to be very much aligned with that kind of pricing going forward. As you may know, the forwards for 2021 at this point are, or in 2020, pushing up towards the CAD 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 that you achieved, CAD 70. I mean, is the difference mostly related to the Sundance PPA driving that outperformance in commercial, or is it the retaking of the hedging profile throughout the year?
It's a combination of both. With under the Sundance C PPA, we have costs probably in the CAD 38 a megawatt hour range. When we pushed back the Sundance C 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. 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. It's that in combination with a trading strategy we already were executing in place. It's a combination of the two.
Okay, that calculation of CAD 70, you're including the difference between the spot price and what would cost to operate to produce that megawatts, your denominator doesn't include any of the Sundance production hypothetically?
That's correct.
Thanks for that. On the Sundance 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 just being run independently from the government perspective?
Our understanding is the government is looking at electricity sort of in its totality and is looking in ensuring that there aren't any market implications or unintended consequences across the whole spectrum of decisions that they're making. Whether they're combined or in consideration or not, that's not really clear. I would say that, again, the government is looking at things as comprehensively as practical.
Okay. Thanks, Brian. My last one for you guys is, just on the Genesee 4 and 5, you mentioned one of the three conditions is no adverse change in market design rules. Are you assuming that the government would maintain the energy-only market design?
That's been our position that the energy-only market, if left alone, provides a tremendous environment for us to continue to build and so on. That isn't necessarily the only answer. We'll see at the end of the day what market structure ultimately might prevail in Alberta. Certainly, we've been very strong and believe that the best answer is the energy-only market.
Okay. It seems like you're open to make a capacity type of market, assuming the return profile for prospective projects aren't changing. It's not necessarily an energy-only market as a base case?
Well, I think we'd be foolish not to consider any healthy, properly balanced, reasonably economically positioned market. We'd certainly consider anything that evolves or develops.
Okay, great. Thanks for taking my questions.
The next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Yeah, good morning. Just on the higher coal costs for G1 and G2. I'm 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.
Yeah. In terms of Genesee Mine, as we look forward, we are seeing opportunities to bring those costs down. That's something that we're taking into consideration as we look at 2017 and beyond.
Okay, just with respect to your financial targets, can you remind us what your target balance sheet ratios are? Perhaps dovetail a comment on how you're thinking about your NCIB now that you've locked in CAD 1 billion or so of liquidity.
Yeah. 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&P and DBRS. 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. We believe that'll play into the fact that we're going to see additional growth opportunities crystallizing. We're bidding in on 2 to 3 wind RFPs at any point in time. Fully expect as we move through the balance of this year and next year, we'll see 1 to 2 additional wind projects moving forward, and that's where our discretionary cash flow will be flowing to.
Also the prospect of final notice to proceed potentially on Genesee Four and Five. 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?
Yeah. We look to maintain our FFO to debt metric sort of no lower than 16%-17%. This year, with the stronger cash flow, we're coming in more in the 20% range, which is obviously very positive from the rating agency's perspective.
Got it. Thanks. Maybe just lastly, again, to clarify a little bit on G4 and G5 here. 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. Definitely that ability is there.
Thanks, Brian. That's all I had.
The next question comes from Robert Kwan with RBC Capital Markets. Please go ahead.
Good morning. 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, had not seen his report.
Got it. 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 to be put in front of the government for approval?
I would 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. What he ultimately provided to the government and the recommendations that he made, again, we never saw that.
Got it. I guess last on that, what do you see as the process forward? The government's 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. Don't see, from a materiality standpoint, I think it'll 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. 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. 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, 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. When we look at those opportunities, 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. There's a very good fit there, 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, certainly fit very well to those other strategic objectives.
Maybe if 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. Versus Q2, availability was stronger than Q2, yet the EBITDA was down about CAD 5 million. Was that all coal costs or is there something else that's going on in that segment?
Yeah. What's happening in the Alberta contracted segment with Genesee 1 and 2 is the Balancing Pool pays us the 30-day rolling average for to the extent we beat the availability target that's embedded in the Power Purchase Arrangement. Given the strong availability of our coal assets, we systematically exceed that target availability and receive that 30-day rolling average as an availability incentive payment. The very low pool price environment, of course, is resulting in that being less than what we would have anticipated at the start of the year.
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.
Price is up, availability is up, yet financial performance is down in Q3 versus Q2.
Are you referring just to Genesee 1 and 2 or overall?
No, just the contracted segment.
Right. Yeah, there's a lot of other parts moving there. Sorry, I was speaking more generally to what we're seeing in 2016 for Genesee 1 and 2. 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. That actually gave us a lift relative to expectations for Q2.
Okay. That's fine. Thank you very much.
The next question comes from Robert Catellier 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?
From our perspective, again, we've been longtime supporters of the energy-only market. There's basically two market structures that are, I'll say, in play right now. One is a REC 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 in 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 or 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 overbuild. 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. Whether that's under a REC process or whether that's under a contract for differences, probably doesn't make a difference under today's market structure.
Right. Okay. Thank you.
There are no other questions at this time. I will turn the call over to Mr. Randy Mah. 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 the 7th 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.