Capital Power Corp

TSX:CPX

Earnings Call Transcript 2018-Q3

[Operator]

Welcome to Capital Power's Third Quarter 2018 Results Conference Call. [Operator Instructions] This call is being recorded today, October 29, 2018.I will now turn the call over to Mr. Randy Mah, Director of Investor Relations. Please go ahead.

[Randy Mah, Senior Manager of Investor Relations]

Good morning, and thank you for joining us today to review Capital Power's third quarter 2018 results, which were released earlier this morning. The financial results and the presentation for this conference call are posted on our website at capitalpower.com.Joining the call are Brian Vaasjo, President and CEO; and Bryan DeNeve, Senior Vice President and CFO. We will start with opening comments and then open the lines to take your questions.Before we start, I would like to remind listeners that certain statements about future events made on this call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on Slide #2.In today's presentation, we will be referring to various non-GAAP financial measures as noted on Slide 3. These measures are nondefined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP, and therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures can be found in our third quarter 2018 MD&A. I'll now turn the call over to Brian Vaasjo for his remarks starting on Slide 4.

[Brian Tellef Vaasjo, President, CEO & Director]

Thanks, Randy, and good morning. I'll start off by reviewing what are the highlights of the third quarter. On September 6, we announced an agreement with Oaktree Capital Management to acquire the a 580-megawatt contracted Arlington Valley gas facility in Arizona for USD 300 million. The acquisition has the following strategic benefits. First, it provides immediate accretion with a 5-year average accretion of $0.22 or 6% on AFFO per share and $0.03 or 2% to earnings per share. Second, Arlington strengthens our contracted cash flow profile. The facility is contracted until 2025 with a high probability of recontracting as confirmed through third-party assessments. We're also pursuing additional contracts for the output generated in the non-summer toll months. Third, Arlington is a key addition to our U.S. growth plans. It's a well-positioned asset in the attractive Desert Southwest power market. And finally, Arlington provides geographic diversification outside of our core market of Alberta.Turning to Slide 5. The Arlington acquisition will initially be financed utilizing our credit facilities followed by permanent debt financing to take place at a later date. Given our existing balance sheet capacity, there is no need to issue equity. We expect the closing of the acquisition to be completed before the end of this year. Overall, the acquisition is a lower risk, long-term cash-generating investment, which provides an important platform for further potential growth in the Desert Southwest.Moving to Slide 6, I'll briefly touch on the Alberta power market and its positive outlook. In the third quarter 2018, the average spot price was $54 per megawatt hour, which is more than double the $25 per megabyte hour spot price in the third quarter of 2017. The forward prices for the remainder of 2018 and the full year 2019 to 2021 continue to reflect the positive dynamics in the market with prices around $50 and above.Current demand growth of 3% to 4% in the provinces contributed to the upward trend for both winter and summer peak periods. As depicted in the Alberta peak demand chart on August 10, a new record for summer peak demand of 11,169 megawatts was recorded. We continue to have a positive outlook for the Alberta power market, and with our diverse fleet of assets in the province, we're well positioned to capture value. I'll now turn the call over to Bryan DeNeve.

[Bryan DeNeve, Senior VP of Finance & CFO]

Thanks, Brian. I'll start off by providing an update on our Alberta commercial portfolio positions as shown in Slide 7. There have been only minor changes to our commercial hedging profile for 2019 to 2021 since the second quarter of 2018. For 2019, we are 55% hedged at an average contract price in the low-$50 per megawatt hour range. For 2020, we're 22% hedged at an average contract price in the low-$50 per megawatt hour range, and for 2021, we are 4% hedged at an average contract price in the mid-$50 per range. This compares to current average forward prices of $56 for 2019, $49 for 2020 and $48 for 2021. We continue to benefit from having nearly 500 megawatts of gas peaking and the wind to capture the upside from low natural gas prices, higher power prices and price volatility.Turning to Slide 8. In the third quarter, we had excellent operating performance with average facility availability of 98%. This contributed to a solid financial result in the quarter that exceeded management's expectations. We generated $156 million in adjusted funds from operations, which is the highest AFFO quarter since Q2, 2015, when comparative information was first reported for AFFO. On a year-to-date basis, we have generated $317 million in AFFO, which accounts for 83% of the $380 million midpoint of the guidance range. Despite the strong year-to-date results, we're maintaining our guidance and continue to be on track to achieve full year AFFO above the midpoint of our $360 million to $400 million annual guidance range. Our outlook for Q4 2018 will include the impacts for major planned outages at Genesee 3 and Decatur. We also expect sustaining CapEx will be higher compared to Q4 of 2017.Slide 9 shows our third quarter financial performance compared to the third quarter of 2017. Revenues and other income were $389 million, up 12% year-over-year. Adjusted EBITDA, before unrealized changes in fair values, was $173 million, up 7% from the third quarter of 2017. The increase is primarily due to strong results in the Alberta contracted facility segment from a higher rolling average pool price that benefited availability incentive and excess energy revenues. Normalized earnings of $0.35 per share were up 25% compared to $0.28 in the third quarter of 2017. As mentioned, we generated strong adjusted funds from operations of $156 million, which was up 16% year-over-year. AFFO on a per share basis was $1.52 compared to $1.30 in the third quarter of 2017.Turning to Slide 10, which shows our year-to-date financial results compared to the same period of 2017. Revenues and other income were $1.1 billion, up 20% from 2017. Adjusted EBITDA, before unrealized changes in fair value, was $547 million, up 30%, primarily due to the assets acquired and developed in the second quarter of 2017. After 9 months, we reported normalized earnings of $0.87 per share, which is similar to the $0.88 in 2017. Adjusted funds from operations of $317 million was 19% higher than the $267 million in 2017. And AFFO on a per share basis was $3.07, up 15% compared to $2.68 in the first 9 months of 2017. Overall, year-to-date performance is reflecting double-digit increase in revenues, EBITDA, AFFO and AFFO per share.I will now turn the call back to the Brian.

[Brian Tellef Vaasjo, President, CEO & Director]

Thanks, Bryan. I'll conclude our comments by providing a status update on our year-to-date progress versus our 2018 annual operational and financial targets as shown on Slide 11. In the first 9 months, average facility availability was 96% slightly ahead of our 95% annual target, but we expect to be on track with our annual target. Our sustaining capital expenditures is currently $54 million, and we expect full year results will be slightly higher than the $85 million target. We reported a $177 million in facility, operating and maintenance expense versus the $230 million to $250 million annual target. We are on track to meet the full year target. We generated $317 million in AFFO in the first 9 months compared to the $360 million to $400 million annual target range. As Brian mentioned, we continue to expect our 2018 AFFO to be above the midpoint of the range.Slide 12 outlines our construction and development targets for 2018. We currently have 2 wind projects under construction. For New Frontier, we are on target for completing the project within its $182 million budget and for COD in December of this year. For Whitla Wind, the project received AUC approval in August, and we've commenced physical construction of the project. The budget is $315 million to $325 million with a COD expected in the fourth quarter of 2019. On the development side, our goal is to execute contracts for the output of 1 to 3 wind projects. Earlier this year, we executed a contract for Cardinal Point Wind in Illinois, and we are targeting commercial operations in March of 2020. We have a strong pipeline of growth opportunities in both Canada and the U.S., and we continue to make progress in executing on our wind development opportunities to create value and strengthen our contracted cash flow profile. I'll now turn the call back over to Randy.

[Randy Mah, Senior Manager of Investor Relations]

Okay. Thanks, Brian. Operator, we're ready to start the Q&A session.

[Operator]

[Operator Instructions] The first question comes from David Quezada with Raymond James.

[David Quezada, Equity Analyst]

My first question here, just on the upcoming mid-term elections in the U.S., Are there any specific jurisdictions that you're keeping an eye on? Or any potential impact that you could foresee there?

[Brian Tellef Vaasjo, President, CEO & Director]

Generally, we're watching, of course, the jurisdictions that we are -- have existing operations in, and we don't see that there'll be any -- by state, any significant changes that will impact on the positioning of our facilities. Overall, of course, there is the differing trends in the U.S. towards some -- the Republicans on one hand having certain approaches to dealing with emissions, et cetera, while the Democrats have sort of a perspective on the other side of the spectrum. So there may be some broader implications on a national basis as opposed to simply on a state basis, but we are watching it quite closely.

[David Quezada, Equity Analyst]

Okay, that's helpful. And I guess, just to follow that up on the Alberta side with the election next year, any thoughts or if you had any discussions with the UCP if they potentially come in power, any changes that they might make to the power market after that election?

[Brian Tellef Vaasjo, President, CEO & Director]

So our general expectation is that the -- regardless of the outcome of the election, we don't anticipate that it'll have substantive changes to Capital Power's operations in the province.

[Operator]

The next question comes from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

Maybe just in terms of the Alberta coal units, just given the continued softness in the market there, just want to get a sense of how much cash you've been able to put through your coal units? And whether there's been any change in your thinking on long-term gas supply to those units as well as the conversion to gas ultimately?

[Brian Tellef Vaasjo, President, CEO & Director]

So I'll speak to the longer-term expectations around our evolution of coal to natural gas, and Bryan will speak to the shorter term as to what we've been -- did in the third quarter. So on the broader basis, we continue to look at the right time to take various steps to move our coal plants to enable them to coal fire more and more natural gas. As you may recall, we had announced that we are supporting on the large natural gas pipe coming to the facility, that was in the end of 2019. We've since updated that due to construction timing and that's moved to early 2020. And again, we continue to look at the right time to make the next levels of investment. The next significant one would be actually putting in the, I'd say, the plumbing to fully accept that natural gas capacity to the units, and we're looking at appropriate timing around that. We generally haven't changed our perspective or our approach and are looking to optimally make those investments that lead to the greatest economics associated with the coal firing of natural gas to coal, then ultimately, at some point, converting the units fully to natural gas.

[Bryan DeNeve, Senior VP of Finance & CFO]

And so just in Q3 of 2018, we continued to see quite significant volatility in actual natural gas prices, number of days where the average price settled below $1 GJ. During those periods, we're able to have natural gas comprise approximately 20% of our fuel input to our coal units, which of course, we optimize when those opportunities present itself. We foresee that those opportunities continuing to be there over the next a year or 2 just given where forward gas prices are.

[Robert Hope, Analyst]

Okay. I appreciate the color there. And then, just taking a look at your 2018 guidance, just want to get a sense of what the moving parts are there? Can you -- in the MD&A, you said that the quarter was above your expectations similar to Q2. Any -- and we're still pointing towards the upper end of the guidance. Are we more towards the upper end of the guidance? Or you look -- are there other offsetting factors there?

[Bryan DeNeve, Senior VP of Finance & CFO]

We certainly are pushing more towards the upper end of the guidance. The -- we are being mindful of the fact that one of the factors we have to keep in mind is Arlington will close at the end of November. The -- certainly, the -- December, the revenue isn't that large in that facility given that toll was a summer toll, so we're taking that into account when we look forward to Q4. We're also mindful of the fact that we have a couple more outages in Q4. One has just wrapped up at Genesee 3, and we have 1 at Decatur. So those are also elements, but certainly, at 30,000-foot level, we would see that moving further up towards the top end of the guidance -- top end of the range, sorry.

[Operator]

The next question comes from Mark Jarvi with CIBC.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

I wanted to touch base on the Alberta contracted segment. There was a more significant increase in adjusted EBITDA, like plus $13 million year-over-year versus the increase in the revenue. Maybe just help us understand why you got a bit more of an uplift on the EBITDA just versus the revenue? I know availability incentives were strong, but maybe you could provide some color there.

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes, I think, one of the factors contributing to that is being able to take advantage of low natural gas prices. So certainly, that's reducing our fuel costs and increasing the EBITDA relative to the revenue we're seeing.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Would that be the primary factor? Or is there anything else kind of impacting that segment?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes, the other factor we would see is -- just is the availability of the unit. So very strong availability means that we're getting higher availability incentive payments than what would be on a expected basis during the period.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay. And then, I'm sorry, if you guys didn't comment, you talked about closing of Arlington in November. When do you guys are thinking of, in places, of permanent financing the debt, you also do have some 2019 maturities. So I was just wondering what you guys are thinking in terms of accessing the debt markets and timing for that?

[Bryan DeNeve, Senior VP of Finance & CFO]

With the Arlington acquisition, we have moved forward our time frame on going to the debt market. So a very, very possible will be coming to market in Q4 of this year, and looking for something anywhere from $250 million to $400 million of medium-term notes.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay, and that's helpful. And then there was some article suggesting that you guys are either completed or closed wrapping up some tax equity for New Frontier. Just wondering anything in terms of pricing for that relative to where you guys were in the market a year ago? And when do you think the proceeds will come in from the tax equity for New Frontier?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes. So we would see that the proceeds coming in shortly after commissioning of that facility, which continues on track for December of this year. And in terms of the agreement, the rate being provided to the tax equity provider is consistent with what we've seen at Bloom.

[Operator]

The next question comes from Ben Pham with BMO Capital Markets.

[Benjamin Pham, Analyst]

One --- couple questions on Arlington, and you mentioned potential new growth opportunities in Desert Southwestern -- Desert Southwest, sorry. And is that a thought process? Is that around more M&A you're thinking in that region organic? And then maybe touch a little bit on the recontracting prospects. I know it's 7 years from now, but maybe supply, demand and potential buyers of the power at that time.

[Brian Tellef Vaasjo, President, CEO & Director]

So Ben, the -- in respect of the opportunities for growth is both from an organic perspective. We certainly -- with the land position that comes with it, certainly, see potentially some opportunity from the solar perspective. It's a good resource, it's already part of the lands that we -- that came with it. We're leasing for an operating solar facility that's there. In addition to that, on the natural gas side, there continues to be some increasing demand in the area for responsive generation, which can potentially provide for some brownfield opportunities. In addition to that from an M&A perspective, I mean, although, we've been active looking in the market for a considerable period of time and in fact, we had a business development office in Phoenix for a couple of years, there is a -- you certainly understand the market much better if you have assets there, and you're looking at what's happening to prices in that dynamics on a day-to-day basis. So certainly, can provide a, I'll say, a better opportunity, and I'd say, perhaps even a lower risk opportunity in respect of M&A activities.

[Benjamin Pham, Analyst]

And the recontracting side of things?

[Brian Tellef Vaasjo, President, CEO & Director]

So one of the things that in respect of Arlington is, as the market has evolved, and particularly with renewables coming in to the market quite significantly, this -- different assets have been utilized in different ways. And obviously, with the nature of the contracts, it's there, what's happening is that the -- you're seeing a significant summer peak. And the expectation is the appropriate economic approach to keeping cost down is to continue with that kind of activity of contracting summer peak from reliable natural gas facilities. And when we went through the process and had third-party advice, and of course, analyzed it ourselves, we saw that, that actual approach is the appropriate approach and certainly, should result in that facility being recontracted if not once, twice, again. So you'll just see in the longer-term that it's got a very, very high probability of being recontracted based on where it is in the market today and the continuation of providing that kind of energy to serve the summer peak.

[Benjamin Pham, Analyst]

Okay. So you don't see nat gas playing out the same way, you're seeing California where renewables ramping up live gas is still there, but maybe not as strong as what some folks have been expecting?

[Brian Tellef Vaasjo, President, CEO & Director]

No, we don't see that playing out the same.

[Benjamin Pham, Analyst]

Okay. And then maybe one more, can I ask on the M&A side? I understand the angle on renewables. On the gas side, it seems like you've been looking at more in the 5- to 7-year contracted contacts and then look to recontract later on. So just -- I want to clarify capacity payment market, is that so merchant-like cash flows for you guys when you think about contracts?

[Brian Tellef Vaasjo, President, CEO & Director]

So that of course, depends on the term. So if you're looking at, say, capacity payments in Alberta, which are expected to be 1-year, we wouldn't be considering those as being contracted. And in the Arlington case, we're looking at the capacity payments that -- or the term of capacity arrangement for the nonsummer period to be equivalent in length to what the contracts are today, we would consider that long term.

[Benjamin Pham, Analyst]

So what about like New England or PJM 3-year capacity payment, is that still in the merchant bucket? Here it's...

[Brian Tellef Vaasjo, President, CEO & Director]

Yes, in all likelihood. We look at some of that -- the rating agency considerations when they look at it. And there typically, you need to be sort of in the 5-year-ish range to be considering something contracted.

[Operator]

The next question comes from Andrew Kuske with Crédit Suisse.

[Andrew M. Kuske]

Question partly relates to Slide 12 in your deck and just how you've wind up the construction of really 3 major wind projects coming up over the next few years. How do you think about just your construction group, how many projects you can actually handle? And is this really a purposeful dovetailing that you've maxed out the capacity of the group or is that more of that could be done?

[Brian Tellef Vaasjo, President, CEO & Director]

Actually Andrew, it's worked out extremely well in terms of how these 3 projects have come together because as you can see from the timing, they are spread out over time and that allows us to focus resources -- particular resources such as procurement at again particular points in time and our construction capability. So it actually has helped in terms of spreading our capacity out. We clearly would be able to take on 1 or 2 wind projects in the nearer term on top of these 3.

[Andrew M. Kuske]

Okay, that's helpful. And then, maybe just a little bit differently if we're looking Ontario. You've got a project, North Dumfries project. It's an interesting load pocket. How do you think about the potential for that project? Where are you in the process? And what kind of framework are looking for in the province of Ontario?

[Brian Tellef Vaasjo, President, CEO & Director]

So we've got a number of natural gas opportunities. We've got -- I'll go on greenfield opportunities. We keep them on a low cost basis available. We've got them in British Columbia, we've got them in Arizona, we've got them in Ontario. And those are basically expected at some point in time may become a contracted facility depending on supply demand balance and whatever else happens in the jurisdiction. So when we look specifically at Ontario, and certainly with the changing government and some other policies, there may well be opportunities for further natural gas investment in Ontario. And I would say that midterm as opposed to necessarily the immediate near term. So -- and again, we'll keep opportunities alive and again, depending on where things go politically and economically with the possibility of those projects moving forward.

[Operator]

The next question comes from Patrick Kenny with National Bank financial.

[Patrick Kenny, Research Analyst]

So now with 2 pipelines being connected into Genesee, just wondering if you can comment on any volume commitments you might have on a combined basis in terms of what that might imply from a minimum coal firing percentage at Genesee post-2020?

[Bryan DeNeve, Senior VP of Finance & CFO]

So I think, Pat, we're just -- we're upgrading the capacity to Genesee. But yes, to the extent that, that larger pipe will be available early 2020, it does provide us the option to potentially increase coal firing, not only up to a higher percentage, but potentially full conversion at the facility, if they analyze the market.

[Patrick Kenny, Research Analyst]

Great. Is there any minimum coal firing percentage that we should assume, just given any underlying contracts for those 2 pipelines?

[Bryan DeNeve, Senior VP of Finance & CFO]

No, no. We'll have full optionality to go coal or gas.

[Patrick Kenny, Research Analyst]

Okay, got it. And then, just one in the near term here on the hedging policy. I mean, now that you've added Arlington and you have some of the contracted cash flows coming online organically, wondering if you feel a bit more comfortable leaving the Alberta baseload position a little more open going forward? Or should we expect the current 55% hedged rate for 2019 to move up closer to fully hedged as you roll into next year kind of similar to 2018 here?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes, a lot of it will depend on just the liquidity and the market for 2019 and where those forwards are trading at Pat. Certainly, as we see forwards moving up towards $60, that subject to liquidity would result in us looking to decrease the amount of length in the Alberta market.

[Patrick Kenny, Research Analyst]

Got it, okay. And then, yes -- sorry, just last question here, if I could. Just curious what was the downtime at Clover Bar in the quarter? Was this planned, unplanned maintenance? And then maybe just an overall comment on your expected availability and utilization rates for the peaker plants through, say, 2019?

[Brian Tellef Vaasjo, President, CEO & Director]

So yes, we expect the utilization of CBEC will continue at similar levels through 2019 is what we've been seeing in 2018.

[Patrick Kenny, Research Analyst]

And any comment on the downtime in Q3?

[Bryan DeNeve, Senior VP of Finance & CFO]

Oh, sorry. What -- can you repeat that part of the question, Pat?

[Patrick Kenny, Research Analyst]

I was just curious what was the downtime caused by. If -- and I couldn't recall if it was planned or unplanned maintenance.

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes. That was some unplanned maintenance in Q3 for CBEC. That has been fully addressed, and we would expect strong availability from those units on a go-forward basis.

[Operator]

[Operator Instructions] Our next question comes from Robert Kwan with RBC Capital Markets.

[Robert Michael Kwan, Analyst]

If I could just start with the quarter on Alberta commercial, having -- comparing to last year, both quarters were 100% hedged, but you did have better prices and volumes, although, I guess, some higher carbon costs this quarter. Were there any other moving pieces? And can you characterize the proprietary trading desk performance this year versus last year?

[Bryan DeNeve, Senior VP of Finance & CFO]

So in terms of the trading gas performance, there is a couple of elements moving here. When you look at our Page 12 of our MD&A, we do have a portfolio optimization, you'll see in 2018, we had $21 million versus $96 million in the same quarter in 2017. That line can't be looked at in isolation in terms of the performance of the trading group. What will happen is as power prices have risen in Alberta, that shifts dollars from the optimization bucket to the asset buckets above. So when we look at 2018, our overall capture dollar per megawatt hour for the Alberta portfolio has been higher than 2017. And we project it'll continue to go higher as we look forward to stronger pricing in the future. So generally, our trading desk has performed at a similar level this year as it has in previous years.

[Robert Michael Kwan, Analyst]

Okay. And that's included for the quarter?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes.

[Robert Michael Kwan, Analyst]

Okay. If I can turn to some comments you made on the PPA. Obviously, the wrap was a big part of the quarter, but you also talked about lower gas in the coal firing, and so I'm wondering are you -- as -- does the PPA setup that, that full benefit flows to you and is not indexed and then as well, do you also capture the change in law provision around carbon, is that for you or is that still just a pass-through based on how much gas gets burned?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes. So the -- in terms of the carbon intensity, that for the most part is a benefit to the balancing pool as a buyer, although we do have a agreement to share some of the benefits of being able to optimize rate at the facility,But from the -- for the most part, the GHG benefits do flow through to the balancing pool. In terms of being able to utilize lower cost fuel with natural gas, that's predominantly to our benefit. So the energy payments that we receive under the PPA are all based on, as you know, formulas set in advance that basically reflect a coal-fired operation.

[Robert Michael Kwan, Analyst]

Got it. And maybe if I can just finish with Arlington, there was some talk earlier of just around elections as well as things that are going on within the state. I'm just wondering how did the ballot proposition 127 factor into your valuation of the acquisition as well as the recontracting potential?

[Bryan DeNeve, Senior VP of Finance & CFO]

So that proposition in turn which would move the state to a much higher renewable percentage, the potential impact of that was something we built in and it was a scenario we considered. At the end of the day, the way we see Arizona is, the economics are driven primarily around solar renewables as opposed to other renewable such as wind. So as you continue to bring on more and more solar, that certainly decreases that net demand during the -- those hours, but doesn't address, of course, the off-peak hours when the sun isn't shining. So even with that very high penetration, would they come in the form of renewables or in the form of solar? Sorry, we still see a need for natural gas to firm up in the off-peak hours.

[Robert Michael Kwan, Analyst]

And you like how Arlington sets both location, and I guess, setup-wise versus other gas resources than in the state?

[Bryan DeNeve, Senior VP of Finance & CFO]

Yes, certainly. Arlington has a very competitive heat rate and a big part of our analysis was where it will set in the supply curve, and we're very comfortable on its efficiency relative to other units in the state.

[Operator]

The next question comes from Jeremy Rosenfield with Industrial Alliance Securities.

[Jeremy Rosenfield, Equity Research Analyst]

Just couple questions around renewal RFPs. First, on Saskatchewan, there was the results from the RFP last week. I'm wondering if you can just comment on that, and where you sit in terms of future Saskatchewan wind RFP? And then also on the Alberta RAP rounds 2 and 3, which are closed here, time lines and any expectations that you have there?

[Brian Tellef Vaasjo, President, CEO & Director]

So in terms of Saskatchewan, we didn't participate. We continually monitor Saskatchewan. And as opportunities come up, particularly around land positions, we do look at them. But generally, we're not overly active in Saskatchewan. In Alberta, just -- one of the elements of the RAP process is it if you're involved in it, you can't talk about it and that's very, very strict rules around that. So -- but could comment, certainly expect and I think it's no surprise, but we do expect it to be quite competitive, both 2 and 3. Are there no more question? Okay.

[Operator]

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Randy Mah for any closing remarks.

[Randy Mah, Senior Manager of Investor Relations]

Okay. Thank you for joining us today. Please mark your calendars for our upcoming annual Investor Day event, which will be held on December 6 in Toronto. More details on the event would be announced shortly. Thank you for your interest in Capital Power. Have a good everyone.