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Capital Power Corp
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Welcome to the Capital Power's Second Quarter 2018 Results Conference Call. [Operator Instructions] This call is being recorded today, July 30, 2018. I will now turn the call over to Mr. Randy Mah, Director of Investor Relations. Please go ahead.
Good morning, and thank you for joining us today to review Capital Power's second quarter 2018 results, which were released earlier this morning. The financial results and the presentation for this conference call were posted on our website at capitalpower.com. On the call this morning is Brian Vaasjo, President and CEO; Bryan DeNeve, Senior Vice President and CFO. We'll start with opening comments and then open the lines to take your questions. Before we start, I would like to remind 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 could 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 #2. In today's presentation, we will be referring to various non-GAAP financial measures as noted on Slide 3. These measures are nondefined 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 GAAP measures in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures can be found in our second quarter 2018 MD&A. I will now turn the call over to Brian Vaasjo for his remarks starting on Slide 4.
Thanks, Randy, and good morning. We had a number of achievements in the second quarter, which are highlighted on this slide. This included a 7% increase to the dividend, which increased the annualized dividend from $1.67 to $1.79 per share. We executed a 12-year contract for 150-megawatt Cardinal Point Wind project, which is expected to be operational in 2020. We added approximately 78 megawatts to our U.S. growth pipeline with the acquisition of the Green Hills Wind project in Missouri. We acquired a 5% equity interest in C2CNT, a company that captures and transforms carbon dioxide into carbon nanotubes. And finally, we secured additional physical natural gas delivery capacity for the Genesee site. This allows for increased natural gas co-firing in 2019, and further natural gas conversion for the coal facility as early as 2020. Turning to Slide 5. The chart illustrates our dividend history and guidance. This year's dividend increase represents our fifth consecutive annual increase of 7%. Our current dividend guidance includes an annual 7% dividend increase out to 2020. Further dividend growth is supported by generating approximately $200 million per year in discretionary cash flow, which supports $400 million to $500 million of annual growth CapEx per year. Also supporting the dividend is an AFFO payout ratio target of 45% to 55%. Moving to Slide 6. In the second quarter, the average Alberta spot price was $56 per megawatt hour. This is clearly triple the $19 per megawatt hour in the second quarter of 2017. As you can see from the Alberta peak demand chart, there is an upward trend for both the winter and summer peak demand periods. The current demand growth of 3% to 4% resulted in a new summer peak demand record of 11,100 megawatts being set earlier this month. The Alberta power market has recovered, and Capital Power has the best fleet of assets in the province to capture value. Turning to Slide 7 with an update of the Alberta Capacity Market Design. AESO has now finalized its proposed market design. The design is constructive and provides an equal opportunity for existing and new assets to earn a return on and of capital. The key design elements, such as participation, market mitigation and term length are reasonable as expected. AESO's next step in the process is to seek additional consultation with stakeholders on the technical details and finalization of various design elements. AESO will then translate its design into market rules for submission to the AUC for approval. The final design is consistent with our view of a properly designed capacity market for Alberta and we're positioned under the market design to do very well.Slide 8 summarizes the progress made on our renewables growth strategy. We currently have 450 megawatts under construction and advanced development from 3 contracted wind projects that we'll add to our fleet over the next 2 years. We have 245 megawatts of potential wind development opportunities to develop in the Alberta's Renewable Electricity Program, and we have approximately 1,200 megawatts of potential wind development opportunities located throughout the U.S. I'll now turn the call turn the call over to Bryan DeNeve.
Thanks, Brian. I'll review our second quarter financial performance starting on Slide 9. Overall, financial results in the second quarter exceeded our expectations. This includes generating $76 million in adjusted funds from operations and adjusted EBITDA of $201 million. In the second quarter, we renegotiated the Bloom Wind tax equity agreement. A change in law provision was triggered in the agreement due to the reduction in the U.S. federal corporate tax rate that was effective on January 1, 2018. Under revised commercial terms, the Bloom partnership claimed bonus tax depreciation in 2017 to capture a larger portion of the tax depreciation at the 35% federal income tax rate versus a 21% rate that became effective January 1, 2018. This resulted in onetime noncash increase to adjusted EBITDA of $44 million.Additional information for modeling Bloom Wind is shown on Slide 10. On the chart, we showed the impact from the renegotiated tax equity agreement on EBITDA and pretax cash flow. The chart is intended to be illustrative in all other inputs, such as a generation, production tax credits and foreign exchange rates were held constant. Under the renegotiated tax equity agreement and considering the reduction in U.S. federal corporate tax rate, we have maintained our original expected returns for Bloom Wind. Slide 11 shows our second quarter financial performance compared to the second quarter of 2017. Revenues and other income were $363 million, up 81% year-over-year. Adjusted EBITDA before unrealized changes in fair values was $201 million, up 61% from the second quarter of 2017. The increase was due to the amended Bloom Wind tax equity agreement, a greater contribution from the Alberta contracted facilities and a full quarter of contributions from Decatur Energy and Bloom Wind. Normalized earnings of $0.22 per share were down 19% compared to $0.27 in the second quarter of 2017. As mentioned, we generated adjusted funds from operations of $76 million, which were 73% up year-over-year. AFFO on a per share basis was $0.74 compared to $0.45 in the second quarter of 2017. Slide 12 shows the financial results for the first half of the year compared to 2017. Revenues and other income were $670 million, up 24% from 2017. Adjusted EBITDA before unrealized changes in fair value was $374 million, up 44% for the same period of 2017, primarily due to the amended Bloom Wind tax equity agreement and a full 6 months of contributions from Bloom Wind, and additional assets acquired in 2017. Normalized earnings of $0.52 per share were down 15% compared to $0.61 in 2017. Adjusted funds from operations of $161 million was 22% higher than the $132 million in 2017. AFFO on a per share basis was $1.55, up 14% compared to $1.36 in the first 6 months of 2017.Turning to Slide 13. Our commercial hedging profile for 2019 to 2021 at the end of the second quarter of 2018 is shown on this slide. The hedge percentages in all 3 years have increased slightly compared to the percentages at the end of the first quarter of this year. For 2019, we're 49% hedged at an average contract price in the low $50 per megawatt hour range. For 2020, we're 25% hedged at an average contract price in the low $50 per megawatt hour range. And for 2021, we're 5% hedged at an average contract price in the mid-$50 per megawatt hour range. This compares to current average forward prices of $56 for 2019, $52 for 2020 and $48 for 2021. We continue to benefit from having nearly 500 megawatts of gas peaking and wind to capture upside from higher power prices and price volatility. I will now turn the call back to Brian.
Thanks, Bryan. The charts on Slide 14 show our 6-month operational and financial performance compared to our 2018 annual targets. In the first half of the year, average facility availability was 95%, which is consistent with our 95% annual target. Our sustaining CapEx was $41 million compared to the $85 million annual target. We reported $121 million in facility operating and maintenance expense versus the $230 million to $250 million annual target. We generated $161 million in adjusted funds from operations in the first 6 months compared to the $360 million to $400 million annual target range. We continue to expect our 2018 AFFO to be above the midpoint of the range.Slide 15 outlines our construction and development target for 2018. We currently have 2 wind projects under construction. The construction goal for New Frontier is completing the project within $182 million budget with COD in December 2018. The other construction project is completing Whitla Wind within its $315 million to $325 million budget with a COD in the fourth quarter of 2019. On the development side, our goal is to execute contracts for the output of 1 to 3 wind development projects. As highlighted earlier, we've executed a contract with the Cardinal Wind project. We have growth opportunities from the Alberta Renewable Electricity Program and from our 1,200 megawatts of potential wind development opportunities in the U.S. I will now turn the call back to Randy.
Okay, thanks, Brian. Operator, we're ready to start the question-and-answer session.
[Operator Instructions] Our first question comes from David Quezada of Raymond James.
This is my first question. Just on the outlook for development of wind in the U.S., I'm wondering what your thoughts are on, I guess, contractor availability and any potential for there to be a little bit of congestion in development, just given the huge overall pipeline in the country? And when you think kind of an effective deadline will be for a go-forward on projects just given the 2020 deadline for completion?
So in response to your first question, we're not seeing much evidence of shortage of either turbines or contractors in the U.S. to -- or Canada to execute on projects. There continues to be significant amount of capacity that's available to us. In terms of the deadline -- or the completion by the end of 2020, a lot depends on the particulars of a project. Certainly, some of the smaller projects can certainly be done within a calendar year from start to finish, especially in the U.S., where as you go south, it's easier from a construction, i.e., no winter construction. But, again, very much depending -- dependent on the particular project and where it is on permitting, et cetera. So when we look across our projects, we see a number of projects that we could potentially move to actually starting construction or advance development within 2019 for completion in 2020.
Okay, great. That's very helpful. And my only other question. Just on the increased capacity for natural gas delivery at Genesee, I noticed an early -- since you said as early as 2020 for potential conversion, I'm wondering if you have -- any color you can provide on your thoughts as to what would govern your decision on the timing for that?
So our timing decisions continues to be the same as it relates to the clarity around carbon pricing as well as the outlook for natural gas. What we've been doing over the last couple of years is maximizing our optionality and shortening up the time frame in which we can react. And obviously, one of the significant elements around that ability to react quickly is having natural gas to the site. So we've dealt with that so to speak long lead-time item. In addition to that, and what's very significant to our outlook over the next few years is the fact that, that moves us to a position where we can co-fire more and more natural gas in the coal units. And as we move forward and through the back part of 2019 and into 2020, we expect to be co-firing and have the capacity to co-fire significantly greater than it is today. So there's a number of reasons to get natural -- significant volumes of natural gas to the site, well, sooner rather than later. But certainly does facilitate a timely decisions around the conversion of natural gas of those coal units. Now we haven't changed our fundamental outlook from what we've had before, but until you see some significant increases in carbon prices or -- we don't see conversion to natural gas until at least 2020 or beyond.
Our next question comes from Mark Jarvi of CIBC World Markets.
I wanted to touch on the hedging. I think it says in the disclosures that we're 93% hedged in the quarter and 87% overall for the year. I think you were close to 100% in Q1. So maybe just give us some context for Q3 and Q4? Do you position yourself to be quite open for the summer and the peak pricing?
We've continued to manage our position for the balance of the year. Can't really get into specific percentages of hedging for those 2 quarters. But it would be in the ballpark of what you'd seen just going into the year.
Okay. And then maybe you can just provide some context with the optimization revenue in the quarter and your realized pricing? Is that just all related to the hedging book? Or is there some other things that happened in terms of not being able to realize as a high price as what the market provided in the quarter?
Yes, so one of the things to look at is, our capture price includes a number of elements. So it would include the weighted average price of all the hedges we would have entered into for the quarter over the past 2 to 3 years, depending on the timing when those hedges were entered into. Certainly, Q2 typically is a lower-priced quarter relative to the rest of the year. So you can expect that our portfolio that was locked-in was locked-in in prices more on the lower side. Then on top of that, we would look at what did we realize with our peaking facilities in the small amount of length that we didn't hedge forward. So all that gets rolled together. Basically, the fact that our captured price came in below the settled price for the quarter, primarily, is just a reflection of the fact that we had some long-term hedges that we entered into a number of years ago.
Okay. And then I just wanted to move -- there is a comment in the press release about you guys where it says, actively participates in competitive opportunities to acquire contracted wind assets. I wonder if you can provide more context? I think that's a new comment whether or not that includes operating assets? Whether or not operating renewable assets or something you guys are pursuing right now?
So we continue to look across in the broad spectrum of opportunities whether they be natural gas or wind and acquiring fully contracted operational assets. On the renewable side, occasionally, we see one where we think we may be able to bring some expertise or manage some risks around those operations. But again, those are relatively few. What we do see a lot of now is the increasing number of opportunities to buy sites or acquire interest in sites that have a high potential for becoming a fully contracted assets in the relatively near term.
Just following on that comment, maybe you can provide a bit of color on the Green Hills project in terms of the stage it's at? How you guys came to get your hands on that project?
So there's a number of projects on actually both sides of the border that come to light. Probably, every quarter, we're looking at 10 to a dozen of those sites and assessing their potential and the -- their ability to actually come to fruition, again, in the relatively near term. As it relates to that specific project, we do expect that certainly it will come to fruition within the -- or it'd be complete by the end of 2020. It does have a high potential for contracting, and we're continuing -- or we're going through, and looking at this point in time in terms of actually marketing that project in Missouri and in surrounding areas.
Is it possible that you could get a contract before year-end for that project?
Yes, it is.
Our next question comes from Ben Pham of BMO.
I had a question on Alberta -- RFP for this year. Can you comment on the [ queue ] you're seeing in terms of potential bidders versus the first iteration?
So I'm trying -- I don't believe, Ben, and I could be mistaken. I don't believe the [ queue ] has been identified at this point. You can correct me if I'm wrong, but I can say that we do expect that it will be highly competitive and probably not a lot different in terms of numbers than last year.
Okay. All right. And can I ask you on the slide on the Bloom Wind's EBITDA cash flow [ movement around ]? So on the cash flow, it looks like the trend is modestly lower from before. So I'm just wondering why the returns aren't different? Is there a change in the denominator portion?
Yes. Where we make it up, Ben, which isn't shown on this graph, is the fact that after the flip in the contract period, we benefit from the lower corporate tax rate in the U.S.
Okay. All right. And can I follow-up on the hedging question? It seems like it's -- maybe, I wanted to clarify the -- if the realized price includes your peaking facilities, which run very well, it suggests that your hedge price looks like it's probably more in the $45 range. And so if you're hedged high $40s coming into the year, would you say that you're closer to the forward curve in the second half than maybe the high 40s?
Yes, as I mentioned earlier, Ben, Q2 typically is lowest trading quarter in the forward market. So hedges we would have entered into for that quarter would typically be less than the other quarters in the year.
Our next question comes from Andrew Kuske of Crédit Suisse.
I think it's a question for either of the Brians really on the issuer bid. And how do you think about just the constraints on buying back stock versus other forms of capital return, like dividends? And then also just ongoing reinvestments in the business?
So we have 2 primary considerations when we look at purchasing back stock. First is, of course, where our stock price is trading relative to our view of value of the corporation. At current levels, we're trading at, we still believe we're undervalued. So, -- but having said that we also are very mindful of the growth pipeline that we have and how close we are to having new growth projects materialize. And one of the things we just want to be careful of is that we're not buying back stock and then following on that having to access the equity market and the costs associated with that. So that's a balance we try to maintain. So really our activity in buying back stock, a lot of it, hinges on the status of our development portfolio.
And then maybe just an extension on that. When you think about the development portfolio and you balance opportunities outside of Alberta versus those in Alberta where you've, obviously, got a very big position as an incumbent. How do you think about the internal development capability within the province of Alberta? And then just the demand that you're seeing, which is, obviously, robust, but how much of the demand in the near term has really been driven by weather versus normalized view of things?
Your question is around weather driving demand growth in Alberta?
Yes, on the near term [indiscernible]
Yes. So, when we speak to 3% to 4% demand growth on an annualized basis, that is weather normalized. So certainly, there's some periods where we've had some very hot weather that has exceeded historical norms and actually has pushed demand growth above 4%, but we've normalized that out. And generally, we're seeing in that 3% to 4% range.
And then finally, if I may, as it just relates to the last point. If you've got normal -- weather normalized 3% or 4% growth, but you had spiky weather behavior that peaked power prices in the quarter. Is that really what got the optimization offside in the quarter?
Well, again, I don't think we -- our optimization was offside on the quarter. When you look at our captured price of -- I think, it was around $51 a megawatt hour, it definitely was lower than where the settled price was for the quarter. But, again, you have to keep in mind that embedded in our captured price is the historical hedging that we've undertaken over the past 2 to 3 years. And Q2 typically, in the forward-base market, trades at the lowest price for the entire year. So Q2 is really robust. It had high-settled prices. We captured a lot of that with our peaking facilities, but we also came into the quarter with most of our baseload hedged, and it was hedged in mid- to high 40s. So that's why our captured price came in lower.
Our next question comes from Robert Kwan of RBC Capital Markets.
Maybe I'll just start with guidance. And so there's no change in the statement, but you also noted that Q2 results exceeded your expectations. So are you expecting AFFO for 2018 to exceed the high-end of the range at this point?
Not at this point. Certainly, there's still some uncertainties out there as we roll through the balance of the year. We're not ready to make a statement that we'll be closer to the upper end of the range, but we're still very confident we'll exceed the midpoint at this stage.
Okay, so directionally you were -- coming out of last quarter, you were above midpoint. Now, you're just further above the midpoint, but you're still within the range?
Yes. That's correct.
Okay. Just on the Genesee gas capacity side of things, is it your own pipe or have you contracted for -- from service on NGTL?
So, I guess, to be clear, it's a -- what's happening is that there is a large pipe that will be built to our station gate by 2019. And there was some portion of that, as you scroll forward in time, that we have committed to, and I'll say, generally, reasonably modest commitment. But it has brought a significant amount of natural gas to our station gate.
So sorry, is it a transmission pipe? Is it an LDC pipe? Or is it a third-party new pipe coming?
Oh, it's a NGTL.
Okay. So you've got -- I assume you got firm service, although you'll be subject to any rationing back that NGTL may have?
Yes.
Okay. Maybe just to finish -- small question looking at the segments, Ontario and BC contracted, looks like in the disclosure, revenues from the disclosed plants are up a few million dollars, York's up a couple of million, but the segment's down $1 million. Now I don't know if it's K2, because it looks like those revenues were down $3 million, although the generation was up. So I'm just wondering if you can give some extra color as to what happened in this segment?
So, in terms of Q2, for the BC-Ontario contracted segment, we did have the York facility did not quite come in at expectations for the quarter on an EBITDA basis. So that would be the primary driver.
Okay, but York was still $2 million higher year-over-year?
Right. I'm pretty sure we didn't close York in the first quarter. I think it was partway into Q2 of 2017.
Understood. It just -- it looks like all of your revenue drivers are up with the exception of K2, yet the segment was down. So were there some unusual costs in the quarter? And then even just as a kind of follow-on, why was K2 revenue down $3 million yet generation was higher year-over-year?
We'll have to get back to you on that question.
Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
Just a couple of questions. The Green Hills development project is the ideal agreement a long-term contract? Or is there an opportunity for a hedge? And what's the market maybe for RECs also in that area? Can you provide any color?
So as we're looking at it, although there's opportunities for RECs broadly speaking, primarily -- our primary driver is both ability to tap the market from a hedge perspective, but there's also a number of utility and co-op opportunities in the area. So we're looking at a broad array of opportunities in relatively short order.
Okay. And you've mentioned that it's close to an existing substation so that implies that there's not a significant risk or a need for transmission infrastructure. I know there's another -- there's a major transmission line that's -- a project that's a little bit controversial running through, I think, a little bit -- southern part of Missouri, but it's not related to that one at all?
That's correct.
Okay, good. Recently, one of your competitors, obviously, TransAlta completed off-coal financing. I'm just wondering if there's any attractiveness for Capital Power to do something similar in order to actualize the future payments from the government?
So there's a number of considerations that go into that. One element is the -- where that transaction was rated. Wasn't that strong in our view, so that the lift we would get in terms of the beneficial rates isn't as great as we thought it would be. We also have some tax considerations from our perspective that we're keeping in mind. So I think, at the end of the day, it's not something that's high on our priority list. And particularly, it would be something we would take a much closer look at if we had the need for a lot of cash at any point in time.
Great. Okay. And maybe just final commentary on a difficult subject. So obviously, in Ontario, there were some directives issued by the government recently in relation to projects that were preoperating, so not impacting your assets specifically. But I'm wondering if you have looked at the value of those assets and if you're bracing yourself or potentially in discussions with the government over the actual operations?
So as we've looked at it, we're not seeing any narrative and in fact narrative to the contrary around actually doing something with operating assets. That's -- there's quite a bit of difference between canceling projects providing some level of compensation to projects that haven't started versus those that are in actual operation. That's a significant step for any government to take in terms of saying the whole issues of sanctity of contracts, and so on. I think any developer is always exposed to the potential of a contract being canceled before realization whether that be -- there is a -- it's happened in British Columbia. It's happened in Ontario before. It'll continue to be happening in the -- and it happens in other countries. So that I think is I'll call it a risk that developers take. To actually change existing or eliminate existing contracts, again, is a very dramatic step for a government to take. So we don't expect that to happen in Ontario. And certainly, the narrative and the advice we received is that's something that's not on the table.
Our next question comes from Rob Hope of Scotia Capital.
Along the same theme in terms of Ontario, when -- you're looking at the market renewal that the AESO is going to put forward. Can you give us some thoughts on how do you think that will play out? And whether or not that could be headwind or tailwind for your assets there?
Well, certainly, philosophically, we see that development of any market as being positive. When you look at our assets and even though our assets in Ontario, the contracts are [ up and ] well down the road, we see market development as fundamentally being a very positive element. The wind farms, of course, are one issue but when you look at the natural gas facilities, both of our facilities are situated to be very important from a transmission perspective and a grid securities perspective. So we see them as being a little bit different in terms of being very valuable, again, from obviously, the energy generation from time to time, but a bit more from a transmission perspective. In a developed market -- from a developed market perspective, they would have both of those attributes valued and would be very positive for us.
All right. And then just moving down south of the border. So you kind of -- you touched on this a little bit before. But the changes to the tax equity market that we've seen year-to-date, has that potentially cooled your expectations for wind farms moving forward? It wouldn't appear so, but could you add some color on the cost of tax equity there?
So we continue to look at projects. In particular, we're currently looking at, obviously, Cardinal Wind, but New Frontier as well. And with New Frontier, we've had positive reception. We continue to work on tax equity arrangements. We haven't seen a significant change in terms of the kinds of yields that we'd expect. In fact, New Frontier continues to be in the zone of yield that we were expecting even prior to the changes in tax laws in the U.S. So it continues to be a market that is open to us and open for our development.
[Operator Instructions] Our next question comes from Patrick Kenny of National Bank Financial.
Just back on potentially converting the Genesee units in a couple of years. Obviously, carbon prices and gas prices are a key drivers, but also wondering how the coal mine reclamation costs might factor into your decision there? And I'm just wondering if converting G1 and 2, but say leaving G3 on coal might allow you to push that full decommissioning liability out to 2030? And if that's a factor in your decision to leave at least 1 unit on coal for a while beyond 2020?
So in terms of kind of taking that question piece by piece, one of the things that when you look at the Genesee facility, and I think, you look at any grouping of facilities that utilize a mine, it's actually economically challenging to leave, say, 1 unit on coal [indiscernible] the reason being is that a lot of your fixed cost remain relatively the same, and yet you have basically a significant change to your denominator. So that makes it somewhat challenging, again, to leave 1 unit in coal and convert 2 units to natural gas. In terms of -- any changes in terms of our outlook and what we might do, one of the things that bringing more and more of natural gas does is when you think of an arbitrage case or being able to arbitrage natural gas more and more, which is certainly with bringing that the natural gas capacity to the plant, what it actually does is, it enhances the staying on coal case because you are able to utilize, again, greater portions of natural gas, which reduces the differentiation between the 2 cases. So as we continue to look forward, continue to see a lot of optionality around what we're able to do on the site and to optimize our ability to utilize coal and natural gas. In relation to the cost of reclamation, we've stayed relatively tight in terms of how much we have to reclaim relative to how much of the pit is open today. It's one -- basically, one mine. We're mining in 2 areas, but again, it's a relatively tight cost and cost of reclamation, especially, spread over a number of years, which is the nature of reclamation. We don't see as having a very dramatic impact on cash flow. So it doesn't enter into our considerations of converting to natural gas.
All right. That's great color. And then just lastly on credit rating. Now that power pricing has recovered and the final CMD looks to be constructive, are you having any discussions with S&P or DBRS on what else might be outstanding to perhaps achieve a one-notch upgrade to BBB (mid)? Or is that on the radar at all over the next year or so?
S&P and DBRS is certainly assessing the new market design and coming to conclusions on around what that means. We expect we'll see something from them potentially in the near future. For us, we're not really working towards one-notch upgrade. We feel BBB (low) is the right place for us. We certainly maintain our credit metrics in a way that provides cushion to the thresholds that the rating agencies have to maintain BBB (low). So certainly we're not riding right on the edge, but we're not looking to improve those credit metrics to the point of a one-notch upgrade. So I think, the expectation is more that we'll maintain that as we move forward.
[Operator Instructions] This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Mah for any closing remarks.
Okay. If there are no more questions, we'll conclude our conference call. Thank you, again, for your interest in Capital Power. Have a good day, everyone.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.