Welcome to Capital Power's Analyst Conference Call. At this time, all participants are in listen-only mode. Following the presentation, the conference call will open up for questions. This call is being recorded today, February 21st, 2017. I will now turn the conference over to Mr. Randy Mah, Senior Manager, Investor Relations. Please go ahead.
Good morning, thank you for joining us today. Earlier this morning, we announced the acquisition of 294 MW of contracted power facilities in Ontario and B.C. We also released Capital Power's fourth quarter and 2016 annual financial results and announced the appointment, effective April 3rd, of two new directors. These news releases and the presentation slides for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vaasjo, President and CEO, Bryan DeNeve, Senior Vice President and CFO, and Mark Zimmerman, Senior Vice President, Corporate Development and Commercial Services. We will start with an overview of the acquisition transaction, followed by a review of our fourth quarter and annual financial results. After our opening remarks, we'll open up the line to take your questions.
Before we start, I would like to remind listeners that certain statements about future events made on this 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 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. 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 the company's 2016 MD&A. I will now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
Thank you, Randy. Good morning. I'm pleased to announce that we have reached an agreement with Veresen for the acquisition of four fully contracted generation facilities. We are acquiring two natural gas-fired facilities and two waste heat assets. The CAD 500 million purchase price consists of CAD 225 million in cash, subject to working capital and other closing adjustments, and the assumption of CAD 275 million of project-level debt. The cash portion of the transaction will be financed through existing cash and use of our credit facilities. The transaction will provide immediate accretion to both adjusted funds from operations and earnings. In the first full year of operations, the acquired assets are expected to add CAD 24 million to AFFO, which is about CAD 0.25 per share, representing a 7% increase. The accretion on earnings per share is CAD 0.11 per share.
The projected EBITDA contribution from these assets is approximately CAD 55 million per year. The closing of the transaction is expected to occur in the second quarter of this year and is subject to regulatory approvals and satisfaction of closing conditions. Overall, the transaction will significantly add to our contracted cash flows out to the end of the next decade. Moving to slide five, I want to provide more details on the assets. The two Ontario natural gas facilities are York Energy Centre and East Windsor Cogen Centre. We're acquiring a 50% interest in York Energy, which provides us with 200 MW of capacity from the total 400 MW capacity of the plant. We will have a 100% interest in East Windsor, which has an 84 MW capacity. Both facilities are under long-term PPAs with the Ontario ISO and have an average remaining PPA life of 14 years.
Under the PPAs, the plants earn revenues through fixed capacity payments that are partially indexed to inflation, and there is a pass-through of O&M, fuel, and startup costs. The assets are strategically located in Ontario, which supports future recontracting of the PPAs on economic terms. Slide 6 describes the waste heat generation facilities in B.C. The two waste heat assets, 5 MW each, are located in Westcoast Energy's B.C. gas pipeline compressor stations in Savona and 150 Mile House. Both waste heat generation facilities are fully contracted with BC Hydro and have 11 years of contract life remaining after expiry in 2028. The electricity purchase arrangements have partial inflation indexation and provide premium pricing under peak load hours. Turning to Slide 7, this updated chart shows the growth in our contracted EBITDA from 2010-2017.
As you can see, our contracted EBITDA has increased 194% during the same period, which translates into a 17% compound annual growth rate. For 2017, you can see the significant increase in contracted EBITDA from a number of new sources, which includes Bloom Wind, which is expected to be completed in the third quarter, the start of annual off-coal compensation payments from the Alberta government, and the expected contributions from the acquisition of the two natural gas plants and two waste heat assets that I discussed. Accordingly, the long-term contracted EBITDA as a percentage of total EBITDA increases from 66% in 2016 to 79% in 2017. On slide eight, I'll summarize the transaction by highlighting the numerous benefits. We are acquiring young, high-quality assets that have an excellent operating history, which will strengthen our existing fleet of assets.
With the waste heat facilities located in B.C. and natural gas facilities located in Ontario, they provide geographical diversification from our incumbent market in Alberta. All of the assets are under long-term contracts. The weighted average remaining contract life of 14 years enhances our contracted cash flows as these original contracts expire between 2028 and 2032. The Ontario PPAs are well-positioned for recontracting on economic terms after these original PPAs expire. The transaction provides immediate accretion. In the first full year of operations, we expect AFFO accretion of CAD 0.25 per share and CAD 0.11 per share to earnings. For 2017, our contracted EBITDA is expected to increase approximately 8%. All of these assets are under long-term contracts. The transaction will enhance our contracted cash flow profile and our ability to grow our dividends. Finally, the transaction will improve the overall business risk.
We expect the credit rating agencies to affirm our credit ratings and outlook. Turning to slide nine, I'll briefly review our highlights for 2016. Capital Power's performance in 2016 was strong, with the company meeting its annual operating and financial targets. This includes achieving average facility availability of 94%, generating CAD 384 million in funds from operations, which was within the CAD 380 million-CAD 430 million target, but at the lower end of the range, primarily due to the Sundance PPA settlement payment in the fourth quarter. Financial results also included a strong year of EBITDA of CAD 520 million. We continued to construct the Bloom Wind Project, which is on schedule for commercial operations in the third quarter of 2017. Other highlights for 2016 include reaching a satisfactory agreement on fair compensation for early phase-out of coal-fired generation and the settlement of the Sundance PPA dispute with the Alberta government.
Finally, we increased Capital Power's share dividend by 6.8% and confirmed annual dividend growth guidance by 7% per year to 2018. Moving to slide 10. This slide summarizes the availability operating performance of our facilities for the fourth quarter of 2015 and 2016, for the full year of 2016. We had solid operating performance in the fourth quarter, with average facility availability of 94%, which was lower than the exceptional 99% performance in Q4 2015 due to the planned outages at Genesee 3 and Shepard in the fourth quarter of 2016. For 2016, our facilities performed well with an average availability of 94%. The strong operational performance is illustrated on slide 11. This chart shows the average availability of our facilities over the past five years. As you can see, 2016 is a continuation of our strong track record of operations and high fleet availability.
This strong operational performance has resulted in an average availability of 94% over the past five years. I'll now turn the call over to Bryan DeNeve.
Thanks, Brian. On Slide 12, I'll review our fourth quarter financial performance. We generated CAD 75 million in funds from operations, which was down 40% compared to CAD 125 million in the fourth quarter of 2015, due to the one-time Sundance PPA settlement payment of CAD 20 million and realized losses from the settlement of interest rate swaps. We reported normalized earnings per share of CAD 0.27, which was lower than the CAD 0.42 in the fourth quarter of 2015. Our trading desk performed well and captured a realized price of CAD 67 per MW hour on our Alberta commercial assets. That is 205% higher than the average spot price of CAD 22 per MW hour in the fourth quarter of 2016. Slide 13 shows a summary of our fourth quarter financial results compared to the fourth quarter of 2015.
Revenues were CAD 280 million, down 17% from the fourth quarter of 2015, primarily due to unrealized changes in fair value of commodity derivatives and emission credits and lower revenues from the Alberta Commercial Facilities, Sundance PPA, and Portfolio Optimization Segment. Adjusted EBITDA before realized changes in fair values was CAD 138 million, down 5% from the fourth quarter of 2015. This was primarily due to the one-time Sundance PPA settlement payment and a net realized loss on the termination of interest rate derivatives. Normalized earnings of CAD 0.27 per share decreased 36% compared to CAD 0.42 in the fourth quarter of 2015. As mentioned, we generated Funds From Operations of CAD 75 million in the fourth quarter, which was down 40% on a year-over-year basis and impacted by the Sundance payment. Slide 14 shows our annual 2016 financial results compared to 2015.
Revenues in 2016 were approximately CAD 1.2 billion, which was down 2% year-over-year. Adjusted EBITDA before unrealized changes in fair values was CAD 509 million, up 5% from 2015, primarily due to strong portfolio optimization results. Normalized earnings per share were CAD 1.22 in 2016, up 6% compared to CAD 1.15 in 2015. Funds from operations were CAD 384 million in 2016, which was down 4% year-over-year, primarily due to the Sundance settlement payment and realized losses from the settlement of interest rate swaps. The realized losses from interest rate swaps flow through FFO but do not impact adjusted EBITDA. I'll conclude my comments with our updated financial outlook for 2017 on slide 15. 2017 marks the commencement of annual off-coal compensation payments of CAD 52.4 million that we will receive each year for the next 14 years.
With the acquisition of two natural gas and two waste heat facilities that is expected to close in the second quarter, we expect to experience an increase in EBITDA. The projected EBITDA contributions on a full-year basis from these assets is approximately CAD 55 million. The slide shows our commercial hedging profile for 2017-2019 as of the end of 2016. For 2017, we continue to be fully hedged at an average contracted price in the mid-CAD 40 per MWh range. In 2018, we are 53% at an average contracted price in the low CAD 50 per MWh range. For 2019, we're 40% hedged at an average contracted price in the low CAD 50 per MWh range. In summary, our baseload merchant exposure is fully hedged in 2017. I'll now turn the call back to Brian Vaasjo.
Thanks, Bryan. On slide 16, I'll review our 2016 operational and financial results compared to the 2016 annual targets and provide an update on our 2017 targets. In 2016, we achieved all of our annual targets. This included an average facility availability of 94%, which met our annual target. Our sustaining CapEx was CAD 55 million, which was lower than the CAD 65 million target due to lower expenditures on planned outages and deferral of various projects into future periods. Our plant operating and maintenance expenses in 2016 were CAD 205 million, which was in line with the CAD 200 million-CAD 220 million target. Finally, we generated CAD 384 million in funds from operations, which was in line with the CAD 380 million-CAD 430 million annual target range. The slide shows our original 2017 targets, which we announced at our Investor Day in December 2016.
With the acquisition of the natural gas and waste heat assets, we have provided updated guidance. The acquisition is expected to increase O&M expenses from the original range of CAD 195 million-CAD 215 million to a revised range of CAD 205 million-CAD 230 million. We have increased our 2017 AFFO financial target from the original CAD 305 million-CAD 345 million to the new range of CAD 320 million-CAD 365 million. Turning to slide 17. We had two development and construction growth projects in 2016. Our Genesee 4 and 5 project, the full notice to proceed decision has been deferred. The continuation and timing of the project will be considered once more Alberta market structure certainty exists and new generation is required to balance supply and demand in the province. Turning to slide 18.
Our growth target for new development outside of Alberta was to execute a contract for output for new development. This was achieved with our Bloom Wind Project, with a 10-year fixed price contract covering 100% of the output. For 2017, our target is to complete Bloom Wind on time for commercial operations in the third quarter and on budget. Our growth targets also include the execution of contracts for the output of two new developments as we continue to actively progress our development pipeline in the U.S. I'll now turn the call over to Randy.
All right. Thanks, Bryan. Operator, we're ready to start the question and answer session.
Thank you. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you'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 today is from Jeremy Rosenfield with Industrial Alliance Securities. Please go ahead.
Thanks. Just a few questions on the acquisition that was announced this morning, and congratulations on that. With regard to the AFFO guidance, the CAD 24 million number there, is that from the assets alone, excluding sort of the project-level debt payments? Have you assumed something with regard to additional interest costs associated with the transaction?
Yes. That AFFO would include the interest expense from the existing project debt in place as well as any incremental debt we would see associated with the transaction.
Okay. You are assuming some portion of permanent debt financing associated with the cost there.
With regard to the balance sheet, just following on that, do you have a view as to where this takes the balance sheet in terms of leverage following the transaction and how comfortable you are with the new level as to where you'd like to be over the longer term?
Yeah. Certainly that's one of the key areas we look at when we're considering the implications of a potential acquisition. In this case, when we look at our FFO to debt metric, it does decline, of course, to some degree, given we're looking at 100% debt financing. However, it declines to around 18% FFO to debt from the S&P's perspective and how they calculate it. That still leaves us a cushion over the minimum threshold of 15%. This acquisition certainly adds leverage, but leaves us with lots of cushion relative to the credit metrics that DBRS and S&P are looking at.
Okay, great. Maybe just one additional question, in terms of the Ontario PPAs for the Ontario assets, do you know what the terms are with regard to carbon cost pass-through, if those are passed through to the buyers under the PPA?
It's Mark Zimmerman here. Yes, they are.
Okay, good. I'll leave it there for the moment, and I'll jump back in the queue. Thanks.
The next question is from David Quezada with Raymond James. Please go ahead.
Thanks. Good morning, guys. Just first on the Ontario natural gas facilities, I see here in the presentation they're strategically located to boost the odds of recontracting. Could you give us any color on, I guess, detail on why those locations are so advantageous compared to others, I guess, that haven't gotten recontracted?
Mark Zimmerman here again. Just in terms of the location of these things in the center of the grid and the transmission constraints that we have there, it is very advantageous for the operation. York itself is a very strategically placed peaker that is called upon quite frequently as load increases both winter and summer. We feel very confident that they'll continue to need that. The alternative is building a much more expensive transmission to try and alleviate that and connecting other facilities.
Okay, great. Thanks. That's helpful. Just in terms of the timing of the acquisition, I see closing in 2017, but I guess just based on the additional FFO you're targeting for 2017, it kind of looks like it'll probably be towards the earlier part of the quarter. Is that fair to say?
Directionally, yes. Of course, it does require a number of typical closing conditions, so we'll need to see how those play out to refine our thinking as we move down the road here.
Okay, great. Just my last one here, just on the U.S. development portfolio and potential to do some new projects there. Any update on the environment that you're seeing in light of potential tax reform in the U.S.?
We're not seeing, although there's a lot of controversy around potential tax reform and so on, it certainly does impact on the potential or the economics of a tax equity partner. That, we expect should be settling down sometime over the next couple of months. We don't see that it's actually disrupting the level of activity in terms of people looking for long-term power purchase arrangements. On the other hand, we do see a little bit of pushback from some traditional interests in some of the states relating to more, I can call it, an anti-renewable segments are certainly coming out a little bit more in force.
Okay, great. Thank you very much. I'll get back in the queue.
The next question is from Robert Catellier with CIBC World Markets. Please go ahead.
Hi, good morning, and congratulations on the acquisition. I had a couple questions. What are you assuming in terms of synergies for the acquisition, and what are the nature and timing of these synergies?
We do have an infrastructure here in place that relates to many of the corporate functions that need to support services like this. We would expect there's some value that we'll be able to materialize out of that. As it relates to the plant itself and cost synergies, you have a complement of individuals there that will be taking over to run that, and we haven't factored any synergies into our thinking on that front. There, of course, will also be some potential revenue synergies as we look at the cost of the commodity and the transportation of it. Again, not a huge amount that we're assuming in the early days of these plans.
Just on that transportation, if there were to be a recontracting of the TransCanada Mainline and the rates come down, is that included in your synergies, or is the company even exposed to that element?
Specifically, we've not included that in our synergies as to the level of benefit that we would get for that or have to share. We're not at a position right now to give guidance on that.
Okay. Just finally.
Two wrap-up questions. One, did this acquisition come with a development portfolio at all? Finally, the average availability on these assets since inception?
On the development portfolio, generally not. As it relates to availability, we're into the high 90s. I'll probably have to get Randy to come back to you with the specific number, but it is high 90s that we have on these assets.
Okay. Thank you very much.
Next question is from Ben Pham with BMO Capital Markets. Please go ahead.
Okay. Thanks. Good morning. I just wonder your thoughts about your priorities for capital allocation post this transaction. Looks like you're taking on a bit more debt than perhaps your overall corporate structure is on a debt-to-EBITDA basis, but your payout still seems pretty low. Does this transaction potentially drive the dividend growth higher or more of an extension or more status quo?
I think, as we look forward, our number one priority, of course, is maintaining the existing dividend and growing it. The priority following that, of course, is growth that makes sense and meets our financial metrics. I think as you look forward, you can expect, depending on the nature and size of the potential growth opportunity we're looking at, you may see a financing structure that starts to bring in more equity. Certainly, that'll depend on the timing and nature of the growth opportunity.
Just to follow up on that, would you say that your balance sheet capacity for growth for acquisitions with this deal, it's potentially a bit less flexible than it was coming into the deal, that you may have to potentially look at alternative sources of equity, such as external financing or asset sales?
No. Certainly, we'd be comfortable with looking at raising equity in the market for the right acquisition or right development project that comes to us. Certainly, you wouldn't see us applying the same leverage that we did here because we did have that room and capability on the balance sheet. We'd be comfortable moving forward with an opportunity that did require some equity financing.
Can you comment? There's some other assets that Veresen is trying to sell in Ontario. Was that more of a balance sheet constraint on you guys near term, or is it something else?
I'm not at liberty to go through all the pros or the ups and downs of the whole discussion. Suffice to say that we're very intrigued with strategic nature of these gas assets, our capabilities as it relates to other parts of their portfolio. While we had some interest, not an interest at the same level as, say, some others, we very much focused our attention on the gas operations only.
Okay. That's helpful. Thanks, everybody.
The next question is from Andrew Kuske with Credit Suisse. Please go ahead.
Thank you. Good morning. It's an interesting acquisition this morning from an economic standpoint and strategic standpoint. What does the acquisition also say about the balancing act of your Alberta versus your non-Alberta exposure? Does this send any kind of messaging to the government on capital allocation as they're working through the capacity payment process?
Actually, one of the things when you look at Alberta, Andrew, is in terms of us spending capital or large amounts of capital over the next few years, those opportunities are relatively limited. As you know, and as evidenced by this transaction, we've got a lot of balance sheet capacity, and we still have a little bit of dry powder on our balance sheet and a lot of very strong cash flow. We, I think, have made it very clear that we expect to be putting out a lot of capital into the U.S. and the balance of Canada, not just for diversification reasons, but there is, I'll call it, an absence of near-term capital commitments available in Alberta.
Okay. That's helpful. Maybe just building upon that theme, when you look at just your development portfolio and the opportunities you have, in particular on the wind projects in the U.S., what kind of appetite have you seen to really do a rinse and repeat on Bloom and the structure you've used on Bloom on some of the other things that are in the pipeline in the U.S.?
On Bloom was a little bit of a unique structure, although we've seen a significant amount of interest in the market associated with it. There definitely could be opportunities, I'd say, to reuse the Bloom structure. I'd say most of the opportunities that are out there that we're participating in, I'll call it, are more vanilla in nature than, say, Bloom was.
Okay. Very helpful. One final one, if I may, just to Bryan DeNeve. Just on the impairment test and the Alberta assets being grouped as one, I know there's some details in the notes, but is this just really a function to avoid some undue volatility in the near term in the financials just on a single unit impairment versus just having it in a collection of one?
Well, earlier this year, we looked at our cash-generating units and their grouping, and it became apparent to us that Genesee 1 and Genesee 2, which we refer to as our Alberta contracted cash-generating unit, has really now reached the point where it'll be fully merchant starting 2021. It made sense to have one group of Alberta assets that were a single cash-generating unit, just given they're all so closely tied to the Alberta market. That was a decision we made earlier this year, and as we rolled through the impairment and completed that testing, it was just basically bringing all the components together, what the payment was from the government and our current forward views on those assets. We then tested that as a single cash-generating unit and came to the conclusion that we weren't in a place where there was an impairment on those assets.
Okay, that's great. Thank you.
The next question is from Patrick Kenny with National Bank Financial. Please go ahead.
Thank you. Morning, guys. Wondering if you might be able to quantify for us your internal assumptions surrounding East Windsor and York after their PPAs expire, what % reduction in EBITDA you're assuming, if any, after the recontracting?
I guess as we look out there, and bear in mind as well, we are looking at 13.8 years out there for, I think, East Windsor and an excess of 14 for York. We are expecting that there could be a nominal reduction in EBITDA as we get way out there, just given the profile that we're looking at and the strategic nature of these assets. That being said, a lot of that's going to depend upon the nature of the fleet at that point in time, load growth, what Ontario does with its nukes, et cetera. I'd be hesitant to firmly peg it, just given how far in the future this is.
Okay. For funding the cash purchase price, I am wondering if it makes sense to look at securitizing a portion of your coal compensation payments here, or is it more attractive to pursue term debt at current market pricing?
Well, we've certainly been exploring and looking at securitization of some or a portion of the coal compensation payments. There are a number of considerations to doing that. I will say that certainly it does potentially provide an attractive financing cost, but comes with quite a degree of complexity. We are very pleased, though, like in terms of our spreads on term debt and where they have come down to. Certainly, raising debt, medium-term notes in the market in Canada is a very competitive alternative for us at this point.
Okay, great. One last question, if I could, just at Genesee, if you can reconcile for us the higher coal costs experienced in 2016 with your overall Genesee mine optimization program, and maybe what your targets are for reduced coal cost per ton through 2017?
Yeah. We're in the process, of course, working with Westmoreland in terms of a revised mining plan, given we'll be off coal at the end of 2030. Working through that, the specific answer to your question, that's something we'll have to follow up with you on.
Okay. Thank you very much.
The next question is from Robert Kwan with RBC Capital Markets. Please go ahead.
Morning. I am just looking at the EBITDA guidance and then working our way down to the AFFO guidance. Just in terms of the different line items, I think you've covered off interest expense, but I'm just wondering, can you give any granularity around expectations for cash taxes, maintenance CapEx, and then are you including the amortizing principal on the debt in the AFFO?
We aren't including the amortizing principal in terms of the calculation of FFO. At Investor Day, we walked through the adjusted funds from operation calculation. It basically takes funds from operations and then goes to the next step in terms of removing the preferred share dividends and capital maintenance expenditures, and then adds back the coal compensation. That's how we get to the AFFO calculation and number. The CAD 24 million associated with this acquisition is consistent with that approach and calculation. Again, in response to your question, it would exclude what we see as or would have taken out what we see as capital maintenance for the assets over the next year, interest payments, but not the principal payments on the amortizing debt.
Okay, just in terms of that bridge from CAD 55 down to CAD 24 is, obviously, you've got the interest, which is a huge component of it.
Yeah.
Is most of the rest maintenance CapEx, or is there a material cash tax that you're seeing?
No, there wouldn't be a material cash tax. Majority is interest expense.
Okay. Just knowing that gas can be a little lumpy, is maintenance CapEx any higher in the near term than kind of a normal run rate?
No.
There was just the discussion on synergies. I just want to make sure I'm clear. Does the CAD 55 million include your estimate of synergies or is that excluding synergies?
It does, Robert, include our estimate of synergies.
Okay. I think, Mark, you mentioned just on the mainline, and you don't have anything there on any long-haul toll. I'm just wondering, are those contracts actually exposed to that or are they a Dawn index?
What's the relationship between NIT and Dawn and how that may change vis-à-vis the cost of gas or the pricing of it for any changes that you have on the transportation side?
Okay. Are you not flow-through, though, out of Dawn?
We are. Until we see how that would manifest itself, what we go through the commodity, different things that we might do. If there is some benefit, we'll obviously pursue it, but on the face of it, we're predominantly a flow-through mechanism here.
Understood. Okay. If I can just finish. Brian, you mentioned in an earlier question, it's just you look forward, past the transaction, that you may look at financial structures that bring in more equity. I guess just coming back to securitizing the Alberta payment, you mentioned that as an option, but how does that kind of comment square up with looking at something that would require more equity?
Well, certainly if we securitize the payments, we view that as an alternative source of debt effectively at the end of the day. Generally, that's just because of how it'll work through and affect our credit metrics. Yeah, we look at securitization as an alternative to going to do a private placement in the U.S. or potentially accessing the bond market here in Canada. It wouldn't be viewed as a substitute for equity.
Okay. Understood. Thank you.
We have a follow-up question from Jeremy Rosenfield with Industrial Alliance Securities. Please go ahead.
Yeah, just on a different topic for a second. Maybe if high level, if you can comment just on the tone of the stakeholder consultations that have been going on in Alberta with regard to the development of the capacity market and how you think that's developing so far.
The process is laid out, and there's a number of processes that, again, have been laid out. It's pretty early days, but I would have to characterize it as certainly continuing to be a positive tone and one on which the government, both from the policy perspective and from the implementation perspective, they'll continue to have a positive tone.
Okay, great. Thank you.
There are no more questions at this time, and now I'll turn the call back over to Randy Mah.
If there are no more questions, we will conclude our call. 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 analyst conference call. You may disconnect your lines. Thank you for participating and have a nice day.