Thank you for standing by. Welcome to Capital Power's Second Quarter twenty sixteen Results Conference Call. At this time, all participants are in listen only mode. Following the presentation, the conference will be opened for questions. This call is being recorded today, July 2536.
I will now turn the call over to Mr. Randy Ma, Senior Manager, Investor Relations. Please go ahead.
Good morning, and thank you for joining us today to review Capital Power's second 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 will start the call with opening comments from Brian Vageault, President and CEO and Brian Deniv, 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 second quarter twenty sixteen MD and A.
I will now turn the call over to Brian Vageau for his remarks starting on Slide four.
Thanks, Randy. I'll start off with a quick review of our highlights for the second quarter. Capital Power delivered strong financial performance in the second quarter that exceeded management's expectations. This included achieving normalized earnings per share of $0.30 and generating $106,000,000 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 discussions with the coal facilitator are ongoing. We expect the Alberta government to provide more details on the implementation of the Climate Leadership Plan in the third and fourth quarters of this year. Turning to Slide five, Capital Power's Board of Directors has approved a $0.10 per share increase in the annual dividend. Effective with the third quarter twenty sixteen dividend, the quarterly dividend will increase 6.8% to $0.39 or $1.56 per share on an annual basis.
This represents the third consecutive $0.10 per share annual increase. The annualized dividend has now grown 24% since 2013. Our current projected cash flow support the annual dividend growth guidance of 7% that we discussed at our Investor Day last December. Moving to Slide six, this slide summarizes the plant availability, operating performance of our plants for the second quarter of twenty sixteen compared to the same period a year ago. We had a strong operational performance in the second quarter with average plant availability of 90%, unchanged compared to the second quarter of twenty fifteen.
We completed a major scheduled outage at Genesee 2, which reduced overall plant availability. The Genesee 2 planned outage was completed in a shorter timeframe and with lower costs than anticipated. At Joffrey, we had reduced availability of 55% due to the planned and unplanned outages. We also saw improved performance at Shepherd this quarter of 82% compared to 73% in the second quarter of twenty fifteen. I'll now turn the call over to Brian Denis.
Thanks, Brian. Starting on Slide seven, I would like to review our second quarter financial performance. We generated $106,000,000 in funds from operations and normalized earnings per share of $0.30 both of which were better than our expectations. Due to excess supply, low natural gas prices and conservative offer strategies from market participants, Alberta power prices in the second quarter averaged $15 a megawatt hour compared to $57 a megawatt hour in the second quarter of twenty fifteen. Despite the 74% year over year decline in average power prices, our trading desk captured a 307% higher realized average price of $61 a megawatt hour on our Alberta commercial assets versus the average spot price.
We continue to see significant value from portfolio optimization activities as illustrated on Slide eight. The chart shows a strong track record of performance from our trading desk. The orange line in the chart represents Capital Power's realized price on our Alberta baseload assets for managing our exposure to commodity risk and reducing volatility. As you can see, Capital Power's average realized price on its baseload facilities has exceeded the spot price by 10% on average since the company's inception seven years ago. So we continue to see consistent material value creation from our portfolio optimization activities.
Turning to Slide nine, I'll review our second quarter financial results compared to the second quarter of twenty fifteen. Revenues were $229,000,000 up 176% from second quarter twenty fifteen, primarily due to strong portfolio optimization revenues. The portfolio was fully hedged, which contributed to a realized price of $61 a megawatt hour compared to an average realized price of $46 in the second quarter of last year. Adjusted EBITDA before unrealized changes in fair values was $123,000,000 up 31% from the second quarter of twenty fifteen, primarily due to strong portfolio optimization performance. Normalized earnings per share of $0.30 increased 200% compared to $0.10 a year ago.
As mentioned, we generated funds from operations of $106,000,000 in the second quarter, which is up 51% on a year over year basis. Turning to Slide 10, I'll quickly cover results for the first half of twenty sixteen compared to the same period in 2015. Overall, the financial results in the first half of the year show improvement across all measures. Revenues were $570,000,000 up 29% year over year, primarily due to unrealized changes in fair value of market commodity derivatives and emission credits. Adjusted EBITDA before unrealized changes in fair values was two fifty one million dollars up 20% from a year ago due to higher EBITDA contributions from the Alberta commercial plants and portfolio optimization segment and a full quarter from K2 Wind that began commercial operations in late May twenty fifteen.
Normalized earnings per share were $0.63 on a year to date basis in 2016, up 58% compared to $0.40 a year ago. Funds from operations were $215,000,000 for the first half of twenty sixteen, which is up 21% 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 2015 year end. The table on the slide shows a quarter over quarter comparison from Q1 twenty sixteen.
For 2017, there were no changes and we continue to be fully hedged at an average contracted price in the mid $40 per megawatt hour range. In 2018, we have increased our hedges to 54% from 50% at an average contracted price in the low $50 a megawatt hour. And for 2019, we have increased our hedges to 44% compared to 34% last quarter at an average contracted price in the low $50 per megawatt hour. In summary, our baseload merchant exposure is fully hedged for this 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 Baggio.
Thanks, Brian. The charts on Slide 12 show our operational and financial results for the first half of this year versus the 2016 annual targets. In the first six months, average plant availability was 93% compared to our 94% target. Our sustaining CapEx was $33,000,000 versus the $65,000,000 annual target. We reported $108,000,000 in plant operating and maintenance expense versus the 200,000,000 to $220,000,000 target.
Finally, we have generated $218,000,000 in funds from operations in the first half of the year versus the $380,000,000 to $430,000,000 annual target. Overall, we are on track to meet our 2016 annual operating financial targets. Turning to Slide 13, we have two development and construction growth targets in 2016. For the Genesee 4 and five project, the construction may proceed once there is clarity on the impact of decisions from the climate leadership plan and the resulting impacts have been assessed. Genesee 4 And 5 is also dependent on receiving adequate price signals from the energy only market.
As previously mentioned, we have restructured the construction execution of the Genesee 4 And 5 project, which has delayed the decision point for proceeding to the fourth quarter of twenty sixteen. On Slide 14, we have growth targets 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 Blum Wind project. Blum Wind has a ten year fixed price contract having 100% of the output. Construction of the project is expected to start in the third quarter of this year with commercial operations targeted one year later.
In addition to Bloom Wind, we are actively bidding into RFPs for other U. S. Projects. I'll now turn the call back over to Randy.
Thanks, Brian. Operator, we're ready for the question and answer session.
We will now begin the question and answer session. The first question today is from Linda Ezergailis of TD Securities. Please go ahead. Thank
you. Congratulations on a strong quarter. I'm wondering and I realize there's probably some competitive sensitivities, but I'm wondering if you could perhaps describe kind of the nature of the optimization leading to the outperformance, whether those factors continue to be in play for the beginning part of Q3 and how that might look going forward in terms of variability?
So the performance in Q2, a lot of that is driven by our view of where fundamental power prices will settle in the province relative to where they're trading on a forward basis. As we look forward to Q3 and the balance of the year, we continue to see opportunities that we're looking to execute on. However, part of the outcome will depend on where prices ultimately settle.
Okay, that's helpful context. And then maybe on an operational note, your faster turnaround at G2, can you describe maybe how much below budget it was? How much faster it was than planned? The nature of that kind of surprise benefits that you realized in that turnaround and might it be applied to other outages going forward? Or is there something unique that was there?
Well, the elements on the Genesee II planned outage was the impact of low pool prices. So under the power purchase arrangement, we make availability incentive payments while the plants out. So the low pool price environment was beneficial relative to what we had budgeted from that perspective. But in addition, the company was able to materially reduce the expenditures during the outage and also shorten the outage duration by about two point five days. So it was all those factors combined.
On a go forward basis, our operations side of the company is looking to continually update and optimize around those planned outages.
Thank you. And just I'm just wondering with the renewable energy plan, the recommendations to the ASO have not or by the ASO to the government have not been made public. But has the government shared anything with industry stakeholders? And have they given you anything in terms of updated timing or any context around even maybe when the CCR regulation consultation might begin?
So there's various rumors and comments moving around the industry. They saw it has been confirmed has made its recommendation to government. The government has been on a schedule of making their decision in that area public near the end of the summer, whether that's late August or early September. So we do expect decisions to be forthcoming from that perspective or at least if it results in next steps, at least know where those would be, but do expect again decisions. When it comes to setting carbon standards, that has been a little bit less clear in terms of timing and direction and really don't have any new information from that perspective.
Thank you. The next question today is from Rob Hope of Scotiabank. Please go ahead.
Yes, thank you. Thank you for taking my questions. Just on the same topic regarding your conversations with the government. Can you comment on the types of discussions you're having with the facilitator? Is it a two way discussion or is the facilitator mainly searching for information requests at this point?
It's certainly a combination of both. The government is looking for information or the facilitator and the coal secretariat are looking for information that's particular to the various units that are involved in positioning of the companies. On the other hand, certainly the discussions that we've had with the facilitator have been two way in terms of hearing some of the views of the facilitator and the secretary and what the final product would be looking like. So it's been it has been definitely a two way dialogue.
All right. Thank you for that color. And maybe just as a follow-up, are you having discussions with the ministry or the government outside of the pass through the facilitator?
No. We are in contact with the government on a number of other files. So we do connect with the government fairly frequently. But part of the understanding is that the discussions that are taking place with the facilitator are relatively self contained. So there's an effort by industry to not engage the decision makers at this point in time.
All right. That's helpful. Thank you.
The next question is from David Quezada of Raymond James. Please go ahead.
Yes, thanks. Good morning, guys. Maybe just a high level kind of strategic question. I know you guys have seems like a fair number of attractive opportunities in The U. S.
And I realize that this event is probably somewhat unlikely, but in the event that you didn't go ahead with G4 and G5, how have you kind of done any work on how you would adjust your strategy there?
Yes. Obviously, we keep that in mind. And I think as we've described before, we've got a number of opportunities in The U. S. And we're actually developing opportunities right now in Ontario to respond to the Ontario, the next two calls in Ontario.
So in the event that Genesee four and five didn't proceed, actually what it translates into for the company is more capital to spend outside of Alberta. So we are prepared to continue to ramp up those activities and still be able to deploy significant amounts of capital to in totally contracted projects, again, Alberta.
Okay, great. That's helpful. Thank you. And then maybe just a broader industry question. There are reports out of Germany, I believe Germany is about a third renewable power and they're having to spend money to keep coal fired plants online and have, I guess, phased out some of the open ended subsidies that they had for renewable power.
Do you see any similarities between where Alberta could be headed under the climate leadership plan and where Germany is now and how that might affect things?
I think part of the situation in Germany is a little bit of whipsawing in terms of bouncing from different fuel types to different fuel types quite rapidly and in response to other events taking place. I think that's quite a bit different than Alberta. And the level of aggressiveness that Germany was taken versus Alberta is quite different as well. So I think what we have in front of us is climate leadership plan as it relates to power generation that is aggressive yet definitely doable. And I think that's the exercise of the government's going through now.
And as we've said fairly openly, if they implement in the directions that they seem to be moving, I. E. REX for renewables matching roughly coal retirements with the bringing in of renewables and avoiding oversupply and of course compensation, which suggests a reasonable level of a risk for investors in Alberta. Climate leadership plan can definitely be implemented in a very reasonable way without there being significant cost to consumers or and with very positive environmental outcome. So it's all capable of being implemented properly without any substantive disconnects in the marketplace.
Okay, great. That's very helpful.
Thank you. That's all I had.
The next question is from Andrew Kuske of Credit Suisse. Please go ahead.
Thank you. Good morning. Guess I the question is just around the negotiations when you're entering into more duration for contracts and new contracts looking out in the next few years. Has there been any fundamental change in buyer behavior or just the nature of the conversations given some of the uncertainty that exists just from a regulatory standpoint in Alberta?
So in Alberta, there certainly is a different tone in terms of where industrials tend to be at this point in time. The uncertainty that they face has been very similar to the uncertainty we face in terms of where power prices are going, carbon tax and so on. And of course, you're in an environment today of very low power prices. So there's a number of things that have kept the, I'll call it, industrial and C and I side probably a little bit slower than you'd otherwise like to see.
So in the event that we actually saw more robust power pricing environment, would you anticipate greater ease in effectively lifting the forward numbers higher on a percentage basis and having thereby having more stability in your book?
Yes. We'd see greater opportunity for longer term contracts with industrials.
And then one final question just on the dividend increase. And so it's meaningful on a per share basis, small on a total cost to the overall organization. How do you think about just that dividend as really low cost but a meaningful return to shareholders and then comparing that versus capital deployment opportunities and building new things?
Well, think just as you've commented from in terms of our view of these dividend increases as we go forward relative to our free cash flow is relatively modest. And they'll certainly don't see it in any way shape or form precluding what we can do in terms of our growth perspective. But I think as we've said a number of times, we see dividend growth as being a very significant component of increasing shareholder value and we'll be continuing on that path.
Okay, that's great. Thank you.
The next question is from Ben Pham of BMO Capital Markets. Please go ahead.
Okay, thanks. Good morning, everybody. I wanted to go back to the question on the quarter and the portfolio optimization and the revenue generation that you've booked there for the quarter, the good result there. And I'm just wondering, are you able to perhaps break out in terms of the magnitude year over year, the benefit on your physical book on the hedges versus perhaps the Sundance being short on that coming into the quarter?
So we look at our Alberta commercial portfolio as one entire portfolio and our decisions are always interrelated. So certainly with the Sundance PPA moving back to the balancing pool that had a change and shifted our overall position. But certainly, we continue to look at optimizing from that perspective forward. So we don't delineate necessarily the Sundance effect separately from what we're doing in the rest of our portfolio. So I guess the short answer, Ben, is no, we don't break that out separately.
Okay. Maybe perhaps can you comment on your sensitivity to pricing? Is it still every $1,000,000 in EBITDA is about $1
Yes. So certainly, when you look over the medium term, that sensitivity to movement in forward prices is less without the Sundance Sea length in our portfolio. But also in addition to that, the fact that we've entered into a lot of forward sales over the first half of twenty sixteen, Obviously, that's also dramatically reduced our sensitivity to power prices in Alberta.
Okay. For that. I wanted to switch over and more a follow-up on the consultations you're having on the stranded costs. I'm wondering, is there any progress on what if there's any sort of agreement on how you and perhaps the government may be looking to calculate the book value?
Well, I mean, there's sort of ongoing discussions on all fronts and to get into the particulars would not be appropriate at this point. But I think it's safe to say we continue to be optimistic with the outcome. And there's nothing's happened that would shake our optimism as to where the government would and should end up.
Okay. Thanks, Brian. Thanks, everybody.
The next question is from Paul Lejem of CIBC World Markets. Please go ahead.
Thank you. Good morning. Just curious about your contracted prices for 2018 and 2019. On your current hedge position, it's in the low 50s for both those years. I'm just wondering how you think about that given the introduction of the carbon tax in 2018.
And is the low 50s sufficient enough for you to be able to recover all your costs and actually make a profit on your commercial coal units at that point? I guess I would have thought that you'd need actually a bit of a higher price come 2018, especially given on the commercial position, you'll be paying the carbon tax at that point.
So in terms of the carbon tax, in the case of Genesee 1 and Genesee 2, that's an obligation that flows through to the buyer, so the balancing pool. Our obligation then is limited to our interests on Keep Hills 3 and Genesee 3. When we look at forward prices in Alberta, it's anticipated that those forward prices build in the impact the carbon tax will have on power prices in the Alberta market. So as you can see on Slide 11 that we walked through, forward prices in 2018 are currently $47 in 2019 dollars 52. So certainly an increase over what we're seeing for forward prices in 2017.
We see that as a combination of two things, Paul. One is the fact that the impact of carbon prices will start to be reflected in bidding behavior, but also tightening in the Alberta market that will result in higher prices. For us, when we look at the overall profitability of our units with the higher at Keephills 3 and Genesee 3, we do want to keep in mind the fact that we have a large inventory of GHG offsets that we put together and procured over time. And certainly, we've been able to procure those offsets at prices a lot materially below where we see the carbon tax or carbon price sitting in 2018 and 2019.
I got you. And what's your view come 2018, there are other units in the market which will become merchant. What's your view of economic of competitors potentially shutting down coal facilities for economic reasons, maybe not regulatory reasons, but given current forward prices of $46 it might not be sufficient to recover fully recover costs. Do you have a view on other retirements that might be happening in the market at that point in time?
We look at what we've seen happening in other older coal fired units in the Alberta market that have become merchant. So the recent examples would be the Battle River III and Battle River IV units. We have seen quite a material change in how those units are offered into the market and their operational profile. So when we look at other units that have the PPAs ending, we would expect probably similar changes to occur.
Okay. Last question, the bidding behavior of the balancing pool, do you expect them just to continue bidding in capacity on the PPAs somewhat indiscriminately through the balance of the year? Or do you anticipate any change in their actual dispatch behavior?
When we look at the PPAs that are held by the balancing pool, our expectations are that some of those PPAs, the balancing pool will make the decision to terminate the PPA. So economically, they to make a payment for the termination, in which case those PPAs will go back to the original owners. Once it's in the hands of the original owners, we expect that there'll be different economic decisions and bidding decisions made for those units.
And do you have any sense of when they might make those decisions?
No, not at this point.
So you might expect it to happen sometime this year?
Potentially later this year, early next year.
All right. Thanks, Brian.
The next question is from Robert Kwan of RBC Capital Markets. Please go ahead.
Good morning. You spoke about bidding on RFPs in The U. S. And then referenced earlier on the call Ontario. I'm just wondering outside of kind of greenfield growth.
Can you just comment on what you're seeing in the M and A market? We've seen pretty good valuations for renewables and contracted. And are you seeing any opportunities to acquire? And with those high valuations, are you actually looking at divesting anything?
So in terms of the what we're seeing out there, there is a there are a number of groups of assets and single assets that have come on and are coming and we anticipate coming onto the market that are substantially contracted in nature. Certainly a lot of them have a significant amount of appeal to us. On the other hand, we find our cost of capital a bit of challenge to compete. There's a lot of financial players in the market who with different strategies or have effectively a significantly lower cost of capital and are able to certainly outbid us. So again, we look at a number of them, don't pursue them very far simply because of again, cost of capital out there for again pristine projects is pretty darn low.
On the other hand, there are from time to time opportunities that come by that are a little potentially a little bit different in nature may have risks that we can manage, whereas others might not that somewhat level the playing field a little bit. So there are some opportunities out there. And again, look at a couple, but certainly not the large number of opportunities that are out there today.
And I guess just with what seems like cost of capital shootouts for high quality contracted assets, would you be looking to divest anything into those valuations?
No, because we don't see that necessarily some of those valuations would necessarily drop and, a, don't have a current significant need for capital. At points in time, as we've demonstrated in the past, when we are looking at large levels of capital investment, we'll look at as part of the decision on capital allocation whether or not it's appropriate or not to divest of an asset.
Understood. If I can just ask some questions here on your hedges. First, just specific on the quarter. Were there any hedges that were set to expire in future quarters that you monetized or settled and brought the gain back into this quarter? No.
Okay. And then as you look out to 2017, you've got 100% hedged for baseload. Are there any other Alberta hedges that you have not allocated to the baseload plants?
Yes. So the 100% is the percentage of length from our baseload plants that we've sold forward. You're correct that there's other forward sales that we have done that would be you could match up against our non baseload facilities.
Okay. Maybe specifically just with the hedges that would have been and I know you don't color code them, but let's for argument's sake say as allocated to the Sunsee PPA. Would those then get reflected in a number that's greater than 100% in terms of the baseload or does that essentially just migrate over to the trading book?
Yeah, effectively, when the Sundance CPPA moved back, what that did was removed or reduced the amount of base load length we had. So effectively, it would increase that percentage sold forward as a total number.
Okay. And then I guess the last question, as you look out to 2018, 2019, the hedges are up a bit. And I'm just wondering, is that because of any generation assumptions going down? Or is it just that you're seeing good value in the forward prices that you locked down?
Yes. That's all due to forward sales that we've entered into that we felt were, as you characterized, a good value relative to where we think the actual power prices will settle in Alberta.
The
next question is from Patrick Kenny of National Bank Financial.
Just on G4 and G5 with the decision point in Q4. If for some reason you don't get full clarity on the CLP by year end, can you remind us if there is flexibility within the contract to continue pushing out the FID date without seeing too much change on the capital cost front?
Yes, there continues to be flexibility on moving out the date. We're losing flexibility is on the completion date. We've sort of pushed compressed the front end pretty close to as far as we can go, again, without having a shift in the back end. In terms of cost, there ends up being modest escalation in the contract with Mitsubishi. So and again, not significant.
Okay. And so just to be clear on the in service date in order to reach 2020 in service date, when does the final FID date have to be reached by?
So without any significant further work, our expectation is that stuff that's around the fourth quarter of this year.
Okay. And then maybe just back on Ben's question related to the Sundance PPA termination. In the contingent liability section, does that estimated loss of $13,000,000 include any benefit that's been accrued by your trading desk here since March 24?
Yes, that number, what it reflects is, if the effective date of the termination or us pushing back to PPA, if that got delayed out past the end of the second quarter, that would be the projected impact on our financial results. And the bulk of that, of course, is related to Q2.
Okay. But again, does that sorry, include any benefit from your trading desk within Q2? No. Okay. Thanks.
That's all I had, guys.
The next question is from Steven Pajette of FirstEnergy Capital. Please go ahead.
Good morning and thank you. My first question is on Shepard. Do you have a target availability rate on Shepard? And is the operator liable to pay you penalties if that target is not met?
There is definitely a target availability number that's consistent for a new large scale combined cycle unit. And in terms of our offtake agreement with Enmax, there are targets and incentives built in.
Thank you. My second question is on Genesee one and two. On a directional basis, what do you expect free cash flows from these facilities to look like post the expiry of the PPA in 2020?
So the revenue we currently receive under the Genesee one and two PPA is roughly $37 a megawatt hour. So when we look at post 2020, once PPA expires, We'll be selling that output into the Alberta merchant market and we're seeing forward prices in that for that year in the $60 to $61 range. So we definitely see foresee a material increase in the revenue from the Genesee one and two units. Now part of that will be offset by the fact that at that point, we also take on the obligation of the carbon tax. So that will partially offset that revenue increase.
But even with the carbon tax, you expect higher cash flows?
That's correct.
Thank you. Those are my questions.
The next question is from Jeremy Rosenfield of Industrial Alliance Securities. Please go ahead.
Thanks. Good morning. Let me be brief. Just a couple of questions. First on the hedging, and I'm thinking here more about gas hedging than on power side of things.
Have you been able to take advantage of the low gas prices in the market to lock in any supply for longer periods of time, maybe to coincide with some of the hedging you're doing on the power side?
Yes, we look at for our gas fired units and length for those units, which would include Clover Bar and Shepherd. We're looking at hedging both the power component as well as the natural gas purchases. And part of the lift we've seen in this year is due to the ability of the desk to optimize around natural gas.
Okay, great. And then just a follow-up on sort of the capital allocation discussion. Since you renewed the NCIB hasn't been used, I'm just wondering if there's any particular reason or if you do expect that you will employ the NCIB now depending on where the stock price is as you move through the year?
So as we've communicated in the past, our priority for capital allocation is towards growth opportunities. So the fact that we are now moving forward with the Bloom project, that's our prime location for our capital. And also, as we look forward and see some of these questions get answered on the climate leadership plan and the prospect of G4 and five moving ahead, that also will be driving a need for capital. So given that growth that's underway, at this point, we don't anticipate any purchases under the NCIB.
This
concludes the question and answer session. I would now like to turn the call back over to Mr. Randy Ma for closing remarks.
Okay. Thank you for joining us today and for your interest in Capital Power. Have a good day, everyone.
This concludes today's conference call. You may now disconnect your lines. Thank you for participating, and have a pleasant day.