Welcome to Capital Power's second quarter 2018 results conference call. At this time, all participants are in listen-only mode. Following the presentation, the conference call will be open for questions. This call is being recorded today, July 30th, 2018. I will now turn the call over to Mr. Randy Mah, Director of Investor Relations. Please go ahead.
Good morning. Thank you for joining us today to review Capital Power's second quarter 2018 results, which were released earlier this morning. The financial results in the presentation for this conference call are 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 will start with opening comments and then open the line to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results 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 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 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'll now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
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 CAD 1.67 to CAD 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 Rolling Hills Wind Project in Missouri. We acquired a 5% equity interest in C2CNT, a company that captures and transforms carbon dioxide into carbon nanotubes. 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 of the coal facility as early as 2020. Turning to slide five, 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 CAD 200 million per year in discretionary cash flow, which supports CAD 400 million-CAD 500 million of annual growth CapEx per year. Also supporting the dividend is an AFFO payout ratio target of 45%-55%. Moving to slide six. In the second quarter, the average Alberta spot price was CAD 56 per megawatt hour. This is clearly triple the CAD 19 per megawatt hour in the second quarter of 2017. As you can see from the Alberta peak demand chart, there's an upward trend for both the winter and summer peak demand periods. The current demand growth of 3%-4% resulted in a new summer peak demand record of 11,100 MW 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 seven 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 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 are positioned under the market design to do very well.
Slide eight summarizes the progress made on our renewables growth strategy. We currently have 450 MW under construction and advanced development from three contracted wind projects that will add to our fleet over the next two years. We have 245 MW of potential wind development opportunities to develop in Alberta's Renewable Electricity Program, and we have approximately 1,200 MW of potential wind development opportunities located throughout the U.S. I'll now turn the call over to Bryan DeNeve.
Thanks, Brian. I'll review our second quarter financial performance starting on slide nine. Overall, financial results in the second quarter exceeded our expectations. This includes generating CAD 76 million in adjusted funds from operations and adjusted EBITDA of CAD 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 1st, 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 the 21% rate that became effective January 1st, 2018. This resulted in a one-time non-cash increase to adjusted EBITDA of CAD 44 million. Additional information for modeling Bloom Wind is shown on slide 10. On the chart, we show the impact from the renegotiated tax equity agreement on EBITDA and pre-tax cash flow. The chart is intended to be illustrative, and all other inputs, such as generation, production tax credits, and foreign exchange rates were held constant.
Under the renegotiated tax equity agreement and considering the reduction in the 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 CAD 363 million, up 81% year-over-year. Adjusted EBITDA before unrealized changes in fair values was CAD 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 CAD 0.22 per share were down 19%, compared to CAD 0.27 in the second quarter of 2017. As mentioned, we generated adjusted funds from operations of CAD 76 million, which was 73% up year-over-year.
AFFO on a per share basis was CAD 0.74 compared to CAD 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 CAD 670 million, up 24% from 2017. Adjusted EBITDA before unrealized changes in fair value was CAD 374 million, up 44% for the same period in 2017, primarily due to the amended Bloom Wind tax equity agreement and a full six months of contributions from Bloom Wind and additional assets acquired in 2017. Normalized earnings of CAD 0.52 per share were down 15% compared to CAD 0.61 in 2017. Adjusted funds from operations of CAD 161 million was 22% higher than the CAD 132 million in 2017. AFFO on a per share basis was CAD 1.55, up 14% compared to CAD 1.36 in the first six 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 three years have increased slightly compared to the percentages at the end of the first quarter of this year. For 2019, we are 49% hedged at an average contract price in the low CAD 50 per megawatt hour range. For 2020, we are 25% hedged at an average contract price in the low CAD 50 per megawatt hour range. For 2021, we are 5% hedged at an average contract price in the mid-CAD 50 per megawatt hour range. This compares to current average forward prices of CAD 56 for 2019, CAD 52 for 2020, and CAD 48 for 2021. We continue to benefit from having nearly 500 MW 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, Brian. The charts on slide 14 show our six-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 CAD 41 million, compared to the CAD 85 million annual target. We reported CAD 121 million in facility operating and maintenance expense versus the CAD 230 million-CAD 250 million annual target. We generated CAD 161 million in adjusted funds from operations in the first six months, compared to the CAD 360 million-CAD 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 two wind projects under construction. The construction goal for New Frontier is completing the project within CAD 182 million budget with COD in December 2018.
The other construction project is completing Whitla Wind within its CAD 315 million-CAD 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 one to three wind development projects. As highlighted earlier, we've executed a contract for the Cardinal Wind project. We have growth opportunities from the Alberta Renewable Electricity Program and from our 1,200 MW 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 for the question and answer session.
Thank you. 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 are 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. Our first question comes from David Quezada of Raymond James.
Thanks. Good morning, guys. I guess my first question, just on the outlook for development of wind in the U.S. I am wondering what your thoughts are on 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. When you think kind of an effective deadline will be for go forward on projects, just given the 2020 deadline for completion.
In response to your first question, we are not seeing much evidence of a shortage of either turbines or contractors in the U.S. or Canada to execute on projects. There continues to be a significant amount of capacity that is 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 is easier from a construction, i.e., no winter construction. Again, very much dependent on the particular project and where it is on permitting, et cetera. When we look across our projects, we see a number of projects that we could potentially move to actually starting construction or advanced development within 2019 for completion in 2020.
Okay, great. Thank you. That was very helpful. My only other question, just on the increased capacity for natural gas delivery at Genesee. I noticed in the release, you said as early as 2020 for potential conversion. I am wondering if you have any color you can provide on your thoughts as to what will govern your decision on the timing for that.
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 timeframe in which we can react. Obviously one of the significant elements around that ability to react quickly is having natural gas to the site. 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.
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. There's a number of reasons to get significant volumes of natural gas to the site sooner rather than later, but certainly does facilitate a timely decision around the conversion of natural gas of those coal units. We haven't changed our fundamental outlook from what we've had before, that until you see some significant increases in carbon prices or we don't see a conversion to natural gas until at least 2020 or beyond.
Great. Thank you very much. That's all I had.
Our next question comes from Mark Jarvi of CIBC World Markets.
Good morning. I wanted to touch on the hedging. I think it says in the disclosures there, we are 93% hedged in the quarter and 87% overall for the year. I think you were close to 100% in Q1. 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 two quarters, but it would be in the ballpark of what you'd seen us going into the year.
Okay. 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 high a price as what the market provided in the quarter?
Yeah. One of the things to look at is our capture price includes a number of elements. It would include the weighted average price of all the hedges we would have entered into for the quarter over the past two to three years, depending on the timing when those hedges were entered into. Certainly, Q2 typically is a lower price quarter relative to the rest of the year. You can expect that our portfolio that was locked in, was locked in in prices more on the lower side. On top of that, we would look at what did we realize with our peaking facilities and the small amount of length that we didn't hedge forward. All that gets rolled together.
The fact that our capture 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. I just wanted to move. There's a comment in the press release about it says, "Actively participating 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 are something you guys are pursuing right now.
We continue to look across the broad spectrum of opportunities, whether they be natural gas or wind, and acquiring fully contracted operational assets. On the renewables side, occasionally we see one where we think we may be able to bring some expertise or manage some risks around those operations. Again, those are relatively few. What we do see a lot of now is an increasing number of opportunities to buy sites or acquire interest in sites that have a high potential for becoming 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.
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 the sites, and assessing their potential and 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 or be complete by the end of 2020. It does have a high potential for contracting and we are 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.
All right. I'll leave it there. Thank you, guys.
Our next question comes from Ben Pham of BMO.
Yeah, thanks. Good morning. I had a question on the Alberta REP for this year. Could you comment on the queue you're seeing in terms of potential bidders versus the first iteration?
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.
Okay.
You could correct me if I'm wrong. 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.
Can I ask you on the slide on the Bloom Wind, EBITDA, cash flow moving around. On the cash flow, it looks like the trend is modestly lower from before. I'm just wondering why the returns aren't different. Is there a change in the denominator portion?
Yeah. Where we make it up, Ben, which isn't shown on this graph, is the fact that after the flip and the contract period, we benefit from the lower corporate tax rate in the U.S.
Can I follow up on the hedging question? It seems like, and maybe, too, wanted to clarify the, if the realized price includes your peaking facilities, which seem to run very well, it suggests that your hedge price looks like it's probably more in the $45 range. If your hedge high 40s come into the year, would you say that you're closer to the forward curve in the second half than maybe the high 40s?
Yeah. As I mentioned earlier, Ben, Q2 typically is the lowest trading quarter in the forward market. Hedges we would have entered into for that quarter would typically be less than the other quarters in the year.
Okay. All right. All right, guys. Thanks a lot.
Question comes from Andrew Kuske of Credit Suisse.
Thank you. Good morning. I think I have some questions for either of the Brians, really, on the issuer bid. 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 reinvestment in the business?
We have two 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. 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. 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. That's a balance we try to maintain. Really, our activity in buying back stock, a lot of it hinges on the status of our development portfolio.
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 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 sort of a normalized view of things?
Your question's around weather driving demand growth in Alberta?
Yes. On a near-term basis.
Yeah. When we speak to 3%-4% demand growth on an annualized basis, that is weather normalized. 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%. We've normalized that out and generally we're seeing in that 3%-4% range.
Finally, if I may, as it just relates to the last point, if you've got 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?
Again, I don't think our optimization was offside on the quarter. When you look at our capture price of, I think it was around CAD 51 a megawatt hour, it definitely was lower than where the settled price was for the quarter. Again, you have to keep in mind that embedded in our capture price is a historical hedging that we've undertaken over the past two to three years. Q2 typically in the forward-based market trades at the lowest price for the entire year. Q2 was really robust. It had high settled prices. We captured a lot of that with our peaking facilities. We also came into the quarter with most of our base load hedged, and it was hedged in mid to high CAD 40s. That's why our capture price came in lower.
That's great. Thank you.
Our next question comes from Robert Kwan of RBC Capital Markets.
Good morning. Maybe I can just start with guidance. There's no change in the statement, you also noted that Q2 results exceeded your expectations. 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. We're still very confident we'll exceed the midpoint at this stage.
Okay. Directionally, you were coming out of last quarter, you were above midpoint, now you're just further above the midpoint?
Yes.
You're still within the range? Okay.
That's correct.
Just on the Genesee gas capacity side of things, is it your own pipe or have you contracted for firm service on NGTL?
I guess to be clear, what's happening is that there is a large pipe that will be built to our station gate by 2019. There is some portion of that, as you scroll forward in time, that we have committed to, and I'll say generally, reasonably modest commitment. It has brought a significant amount of natural gas to our station gate.
Sorry, is it a transmission pipe, is it an LDC pipe, or is it a third-party new pipe coming in?
Well, it's NGTL.
Okay. I assume you've got firm service, although you'd be subject to any rationing back that NGTL may have?
Yes.
Okay. Maybe just to finish a small question looking at the segments. Ontario and B.C. contracted. It looks like in the disclosure, revenues from the disclosed plants are up a few million CAD. York's up a couple million CAD. The segment's down CAD 1 million. I don't know if it's K2, because it looks like those revenues were down CAD 3 million, although the generation was up. I'm just wondering if you can give some extra color as to what happened in the segment.
In terms of Q2 for the B.C. Ontario contracted segment, the York facility did not quite come in at expectations for the quarter on an EBITDA basis. That would be the primary driver.
York was still CAD 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's just it looks like all of your revenue drivers are up, with the exception of K2, yet the segment was down. Were there some unusual costs in the quarter? Even just as a kind of follow-on, why was K2 revenue down CAD 3 million, yet generation was higher year-over-year?
We'll have to get back to you on that question.
Okay. Thank you.
Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
Morning. 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? What's the market maybe for RECs also in that area? Can you provide any color?
As we're looking at it, although there's opportunities for RECs, I'd say broadly speaking, our primary driver is both ability to tap the market from a hedge perspective. There's also a number of utility and co-op opportunities in the area. We're looking at a broad array of opportunities in relatively short order.
Okay. You 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 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.
There's a number of considerations that go into that. One element is where that transaction was rated wasn't that strong in our view. The lift we would get in terms of 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. I think at the end of the day, it's not something that's high on our priority list. Particularly, it would be something we would take a much closer look at if we had a need for a lot of cash at any point in time.
Great. Okay. Maybe just a final commentary on a difficult subject. Obviously in Ontario, there were some directives issued by the government recently in relation to projects that were pre-operating, so not impacting your assets specifically. I'm wondering if you have looked at the value of those assets and if you are bracing yourself or potentially in discussions with the government over the actual operations.
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. There's quite a bit of difference in between canceling projects and 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, it's happened in British Columbia, it's happened in Ontario before. It'll continue to be happening. It happens in other countries. 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.
We don't expect that to happen in Ontario, and certainly the narrative and the advice we've received is that's something that's not on the table.
Okay. That's good to hear. All right, that's it for me. Thank you.
Our next question comes from Rob Hope of Scotiabank.
Good morning, everyone. Along the same theme, in terms of Ontario, when you're looking at the market renewal that the IESO is going to put forward, can you give us some thoughts on how you think that will play out and whether or not that could be a headwind or tailwind for your assets there?
Well, certainly, philosophically, we see the development of any market as being positive. When you look at assets, and even though our assets in Ontario, the contracts are up 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. 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 more from a transmission perspective. From a developed market perspective, they would have both of those attributes valued and would be very positive for us.
All right. Thank you for that. Just moving down south of the border. 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?
We continue to look at projects. In particular, we're currently looking at, obviously, Cardinal Wind, but New Frontier as well. With New Frontier, we've had a 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. It continues to be a market that's open to us and open for our development.
Thank you. I'll jump back in the queue.
Once again, if you have a question, please press star, then one. Our next question comes from Patrick Kenny of National Bank Financial.
Good morning, guys. Just back on potentially converting the Genesee units in a couple of years. Obviously, carbon prices and gas prices are key drivers, but also wondering how the coal mine reclamation costs might factor into your decision there. 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. If that's a factor in your decision to leave at least one unit on coal for a while beyond 2020.
In terms 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, one unit on coal. The reason being is that a lot of your fixed costs remain relatively the same, and yet you have basically a significant change to your denominator. That makes it somewhat challenging, again, to leave one unit in coal and convert two 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 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 the natural gas capacity to the plant.
What it actually does is it enhances the staying on coal case because you're able to utilize, again, greater portions of natural gas, which reduces the differentiation between the two cases. 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 basically one mine. We're mining in two areas, but again, it's a relatively tight cost, and the 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. It doesn't enter into our considerations of converting to natural gas.
All right. That's great color. Thanks, Brian. Just lastly on the 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 are certainly assessing the new market design and coming to conclusions 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 a 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. Certainly we're not riding right on the edge. We're not looking to improve those credit metrics to the point of a one-notch upgrade. I think the expectation is more that we'll maintain that as we move forward.
All right. That's great. Thanks very much, guys.
Once again, if you have a question, please press star then one. 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 will 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.