Capital Power Corp

TSX:CPX

Earnings Call Transcript 2017-Q4

[Operator]

Welcome to the Capital Power's Fourth Quarter and Year-end 2017 Financial Results Conference Call. [Operator Instructions] This call is being recorded today, February 16, 2018. I will now turn the call over to Mr. Randy Mah, Senior Manager, Investor Relations. Please go ahead.

[Randy Mah]

Good morning, and thank you for joining us today to review Capital Power's fourth quarter and year-end 2017 results, which were released earlier this morning. The financial results and the presentation slides for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vaasjo, President and CEO; and Bryan DeNeve, Senior Vice President and CFO. We will start the call with opening comments and then open up the lines to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this 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 #2.In today's presentation, we will be referring to various non-GAAP financial measures, as noted on Slide #3. 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 the company's 2017 MD&A. I will now turn the call over to Brian Vaasjo for his remarks starting on Slide #4.

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

Thanks, Randy, and good morning. I'll start off with a brief recap of our success in 2017. Last year, we achieved substantial growth in our cash flow from contracted facilities and very significant diversification of our portfolio of assets. Our success has included executing on a renewable strategy that led to a successful 20-year contract with Whitla Wind in the first round of AESO's Renewable Electricity Program and commencing the New Frontier project in the United States. We also acquired 5 contracted thermal assets consisting of 4 facilities from Veresen and Decatur Energy from LS Power. Through acquisitions and the completion of Bloom Wind, we added nearly 1,300 megawatts to the fleet. These additions to the fleet contributed to a 13% increase in AFFO per share and increased the contracted percentage of adjusted EBITDA from 67% in 2016 to 79% in 2017. We continued our path of annual dividend increases: first, by increasing the dividend for the fourth consecutive year with a 7% increase; and second, extended our dividend growth guidance out to 2020 based on the 2017 asset additions. From our operations' perspective, we exceeded our availability performance target on our plants with a 96% average availability. The trading desk continues to perform well and captured $51 per megawatt hour realized Alberta price in 2017 compared to the $22 average spot price. Finally, through various initiatives, we continue to make progress in reducing our carbon footprint. Turning to Slide 5. With an update on the Alberta power market design, in late January, AESO released Draft 1 of a Comprehensive Market Design for the new capacity market. Overall, the design appears constructive and resembles a market structure where existing and future assets will have the opportunity to earn a return on and a return of capital without putting undue cost or risks on ratepayers. The Government of Alberta commitments to treat new and existing assets equitably and to continue a level playing field have been honored as the design would provide for one action with a contract term and for both existing and new capacity resources. Draft 1 includes reasonable provisions regarding energy and capacity market mitigation as expected. AESO will be working through an iterative process, which will see the market design finalized by July 20, 2018. Overall, Draft 1 is generally consistent with our view of a properly designed capacity market for Alberta, and Capital Power is well positioned under this market design. On Slide 6, we've illustrated AESO's forecast for revenues for baseload facilities based on proposed design. The chart shows the current forward price for 2018 to 2020. In 2021, when the capacity market is implemented, the combined energy and capacity payment is expected to be in the $55 to $65 per megawatt hour range. This range is reasonable and will allow existing and future assets and an opportunity to earn a return and the return on capital. The release of Draft 1 and this projection provides much greater certainty about the Alberta market post-2021. Moving to Slide 7. The next 2 rounds of the Renewable Electricity Program have been announced. It is targeting 700 megawatts of new renewable capacity, including 300 megawatts through a process that projects to have a minimum indigenous equity component. Two key requirements for both processes are that projects have to be new or expanded renewable electricity generation projects and require a connection to existing distribution or transmission systems. AESO expects to launch both competitions this spring, and successful bidders will be announced by the end of 2018. Capital Power is well positioned to bid on both competitions with its Whitla 2 and Halkirk 2 projects. I'll now turn the call over to Bryan.

[Bryan DeNeve]

Thanks, Brian. I'll start on Slide 8 with a review of our fourth quarter financial performance. Overall, financial results in the fourth quarter were in line with our expectations. This includes generating $91 million in adjusted funds from operations and reporting normalized earnings of $0.24 per share. Alberta spot prices in the fourth quarter averaged $22 per megawatt hour, which was identical to the spot price in the fourth quarter of 2016. Our trading desk performed well and captured 109% higher realized average price of $46 per megawatt hour on our Alberta commercial assets versus the spot price. Despite the strong trading performance in the quarter, it was even stronger in the fourth quarter of 2016 when the trading desk captured and realized power price of $67 per megawatt hour. Slide 9 shows our fourth quarter financial performance compared to the fourth quarter of 2016. Revenues and other income were $261 million, down 7% year-over-year. Adjusted EBITDA before unrealized changes in fair values was $172 million, up 25% from the fourth quarter of 2016, primarily due to the additions of the Veresen assets and Decatur Energy, addition of Bloom Wind and the off-coal compensation payment. Normalized earnings of $0.24 per share were down 11% compared to $0.27 in the fourth quarter of 2016. As mentioned, we generated an adjusted funds from operations of $91 million, which was up 63% on a year-over-year basis. Slide 10 shows the annual financial results for 2017 versus 2016. Revenue and other income were $1.1 billion, down 6% from 2016. Adjusted EBITDA before unrealized changes in fair value was $592 million, up 16% for the same period in 2016, primarily due to the new additions to the fleet and partially offset by lower trading gains. Normalized earnings of $1.12 per share were down 8% compared to $1.22 in 2016. Adjusted funds from operations of $363 million was 18% higher than the $307 million in 2016, primarily due to the same factors described for the fourth quarter. Of note, the 2017 AFFO payout ratio was 44%, which is slightly below the low end of the 45% to 55% annual target range. This low payout ratio supports our annual -- 7% annual dividend growth guidance. Turning to Slide 11, with an outlook on the Alberta power market. Our commercial hedging profile for 2018 to 2020 as of the end of 2017 is shown on this slide. For 2018, we are 87% hedged at an average contract price in the high $40 per megawatt hour range. For 2019, we're 37% hedged at an average contract price in the low $50 per megawatt hour range. And for 2020, we're 20% hedged at an average contract price in the low $50 per megawatt hour range. Compared to the $22 average power price in 2017, forward prices have moved significantly as depicted in this chart. The charge shows the 2018 to 2024 prices at 3 different points in type, at the end of Q3 2017, December 7 following our Investor Day and where they currently sit today. As you can see, both 2018 and 2019 forward prices have increased from the mid-$40 per megawatt hour range at the end of Q3 last year to the high $50, low $60 range currently. Although we have a significant hedge position in 2018, we still have nearly 500 megawatts of gas peaking and wind to capture upside from the higher power prices and price volatility. There is also significant upside for 2017 where we're only 37% hedged. I'll now turn the call back to Brian.

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

Thanks, Bryan. I'll conclude our comments by reviewing our 2017 performance versus our annual targets, starting on Slide 12. We finished the year with strong average availability of 96%. It exceeded our 95% target. Our sustaining CapEx at $59 million was lower than the $80 million target, mostly due to lower than expected mine capital spending, project scope reductions and deferral of various projects into future periods. We reported $224 million in operating and maintenance expense in 2017, which is in line with the $215 million to $240 million target. And we generated $363 million in adjusted funds from operations that was at the midpoint and a revised annual target range of $340 million to $385 million. We had an exceptional year of growth in 2017. As shown on Slide 13, we significantly exceeded our targets. We completed the construction of the Bloom Wind project ahead of schedule and with construction cost below budget. We were successful in executing long-term contracts with 2 new wind developments, New Frontier Wind in the U.S. and Whitla Wind in Alberta. We also acquired 5 thermal assets that significantly increased our contracted cash flow and provided geographic diversification. With 2017 completed, I'll briefly outline our 2018 priorities, starting with our development and construction targets on Slide 14. We currently have 2 wind projects under construction. This includes constructing New Frontier within $182 million budget with COD in December 2018. The other is completing Whitla Wind within its $315 million to $325 million budget with COD in the fourth quarter of 2019. Our goal is to execute contracts for the output of 1 to 3 new wind developments. These would potentially come from rounds 2 and 3 of the Albert Renewable Energy Program that was highlighted earlier and our U.S. portfolio of opportunities. In the U.S., the impact from recent tax reform on our renewables portfolio and growth opportunities is not expected to be material. Therefore, we expect to continue adding wind facilities from our U.S. development pipeline. Finally, our 2018 financial target is shown on Slide 15. As announced at our Investor Day in December, we are targeting $360 million to $400 million in AFFO for 2018. Based on our outlook, we are now expecting AFFO to be above the midpoint of the guidance range. As shown on the chart, we expect our 2018 AFFO per share to contribute to achieving a 10% compounded annual growth from 2014 to 2018. I'll now turn the call back to Randy.

[Randy Mah]

Okay. Thanks, Brian. Operator, we're ready to start the questions-and-answer session.

[Operator]

[Operator Instructions] Our first question comes from David Quezada of Raymond James.

[David Quezada, Equity Analyst]

My first question, just on the draft of the Comprehensive Market Design. Wondering if you can just provide any other color there. Are there any material items in your view that's going to be ironed out? And maybe just more broadly, what -- how that affects your thoughts on potentially deploying capital further in Alberta in the future?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So as the Draft 1 came out, the AESO had identified a number of areas that were still open for a significant discussion. And I think as we've said all the way along, as long as the broad market parameters are there, a lot of the details -- again, as long as they work well together within the other constructs of the market, we are somewhat indifferent to. So as we see it, there's really nothing in the scope of these other areas. Again, as long as properly implemented, would create any significant concern for us. And in terms of the what it means in terms of investing further in Alberta, I mean, we continue to have the Genesee 4, 5 project on the shelf, but ready to go. And I think as we've communicated consistently, one of the elements, of course, is the market design. And we're getting pretty close to saying that's a checkmark. Then the other issue is whether or not all the constructs around the market and what impacts on the market fundamentals is there, I mean, we certainly would expect once the capacity market is put in place, that it would be an enduring market. And when we would make an investment decision, part of it would be on our confidence. So the market that we'll see in 2021 and 2022 is the same market that will be there in 2025 and 2030, et cetera. So that's another very significant element of consideration for us is how stable will the market design be going forward.

[David Quezada, Equity Analyst]

Okay, great. That's helpful. And just moving to the U.S. and just would appreciate the thoughts on tax reform and you don't expect a material impact. But I'm just wondering, do you feel that there is any potentially reduced appetite for tax equity financing. Does that color your view on the U.S. development portfolio at all?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So there is definitely a reduction in appetite for parties to invest in tax equity. And that comes through the BEAT provisions and so on, not directly because of anything that directly impacted on the renewable side. Having said that, in talking to participants in that market fairly extensively, there are some whose appetite has been eliminated, but there still exists a very robust market. We would expect that a change in expectation around their expectations of return or yield has probably moved up sort of 25 to 50 basis points. And we see that's the impact of, I'll say, the declining appetite for tax equity in the U.S. And again, that doesn't impact on our outlook for successfully completing projects.

[Operator]

Our next question comes from Patrick Kenny of National Bank Financial.

[Patrick Kenny, Research Analyst]

Just on your gas peaking capacity, can you speak to whether or not you're looking at now locking in some of the spark spreads going forward? Is that part of your hedging policy?

[Bryan DeNeve]

It certainly is part of our overall hedging strategy. And just as we look at opportunities to lock in or decide to go long on the power side, we do the same thing from a spark spread perspective for the gas assets. And one of the things we have seen in the market is increasing forward prices on electricity. But at the same time, we have been seeing a decline in natural gas prices and an expansion of those spark spreads, which has been very beneficial to our gas-fired assets.

[Patrick Kenny, Research Analyst]

And could you remind us, maybe within your cash flow guidance for 2018, what sort of capacity factor you've modeled in there for your peakers?

[Bryan DeNeve]

It varies by plant. And -- but certainly, it's probably about 2 to 3x increase in output that we've seen historically.

[Patrick Kenny, Research Analyst]

Okay. And then lastly, I know you've got some time on your side here as you think about next decade and just digesting the first cut from the AESO's proposed design. But as you think about lower natural gas prices and this design framework, your initial thoughts on either keeping G1 and 2 on coal through next decade or converting early to gas?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So I think as we've indicated all along, there are 2 primary drivers to when that decision on converting to natural gas plays into. I mean, from our perspective, it's not if you convert, it's when. And as we look at that, there are a couple of things that come into play. Again, with the significant parameters, we continue to model out and look at it. And certainly, the decline in natural gas prices would have a tendency to move conversions sooner as opposed to pushing it out. And so we're actively looking at that as we speak as well as more detailed engineering, et cetera, to refine our view, and again, as we've said all along, be ready to convert that at an appropriate time. The other thing, though, that's playing into it is there is a significant ability with these boilers to also -- when you're in coal service, to also burn significant amounts of natural gas. And we're looking at that quite extensively from the perspective of it's likely not going to be where you flip a switch from burning coal to burning natural gas. There may be a fairly long transition where you're increasingly burning natural gas or have that capability when natural gas prices are favorable to, again, going back to coal. So we're exploring all of that as we speak. But certainly, having lower natural gas prices stimulates a lot more effort in that area and certainly has the impact of moving our focus to sooner rather than later.

[Operator]

Our next question comes from Mark Jarvi of CIBC Capital Markets.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

I just want to go back to the commentary on G4 and G5 and you're saying how you want to see stability in the market contract? Does that mean you wouldn't make a positive FID until you actually saw the results of the first auction?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

Not necessarily. I mean, first of all, there's going to be an identification of where the AESO says whether there's going to be a need for new capacity in the market or not. And certainly, that's a very significant element as to whether or not there is room for something like G4 in particular in the market. But in addition to that, again, it'll be the regulations that we see evolve around the new market, the degree to which regulatory bodies have the ability to reach in and make, I'd say, maybe noneconomic decisions, et cetera. So it's sort of the robustness and the stability element of the market that we'd be looking at very hard. Is -- as would, I think, any other investor on an investment decision.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay. And then going to your commentary on being above the midpoint of your guidance, maybe you can talk a little bit about the factors. Is that solely on the movement of forward cost, or is that reflective also on gas cost and/or market volatility?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So in addition to all of what you've mentioned, there is also -- although it's early in the year, there are certainly pluses and minuses that we're anticipating to take place in terms of what impacted on our original forecast. But certainly, what we see happening in the power market does definitely have a lifting impact in terms of our guidance.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Okay. And then maybe my last question for now would be, just in terms of the announcement of the NCIB, you did have it in place before, but didn't use it. Just wondering what your thoughts are in terms of your willingness to be active on it and whether or not this signals any sort of flip shift in terms of capital allocation and return of capital through a combination of buybacks and dividends going forward?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So I think we've been fairly clear in suggesting that under certain circumstances, we would execute on buying back shares as a proper capital allocation move. We've come to the conclusion that actually to the extent that we possibly can, that we would keep NCIB in place continuously, much like a shale prospectus there in the event that you need it. And when you think of the significant cash flow we have coming into the organization, $200 million a year, that can be invested in growth. And the potential lumpiness of our capital expenditures going forward, it is just simply prudent to have an NCIB in place all the time. And obviously, one to take this as a signal that we don't see growth anymore in our future and in fact our outlook for growth is essentially unchanged from our discussions during our Investor Day.

[Operator]

Our next question comes from Andrew Kuske of Crédit Suisse.

[Andrew M. Kuske]

A question probably for Bryan DeNeve. And it's just on your Alberta commercial facilities. And if I look at the adjusted EBITDA this quarter versus a year ago, you're down about $10 million on that. Is that really just a function of the power price realizations? If I go back a year ago, it's $67 for the quarter and you're $46 this quarter. So is that really the delta of the $10 million, or is there something else going on there?

[Bryan DeNeve]

No, it's exactly that, Andrew. The success of the trading activity was very strong in Q4 2016 on the strategy. And certainly, it was good this year also, but -- or Q4 2017, but it was exceptional in Q4 2016.

[Andrew M. Kuske]

So then when you look out and you think about just where the forward curve is and your ability to capture pricing, I'm not being patronizing, but your historic ability to actually capture better prices than the market on average, what do you think that optimization number would be or for that whole group or would be sort of "normalized"?

[Bryan DeNeve]

That's a really good question. Certainly, if you look historically, we've captured a significant percentage greater than the average settled spot price. Certainly, it was very healthy as we went through the downturn, not because we had sold forward through that period a large part of our output. But yes, as we roll forward, we expect we'll still continue to be able to capture a healthy percentage above the average spot.

[Andrew M. Kuske]

Okay. That's helpful. And then maybe just I would change directions a little bit with my last question. And when you look at sort of the balance of opportunities ahead of you in, let's say, the rep rounds 2 and 3 in Alberta or U.S. development, how do you think about just the relative opportunity, because you've got opportunities on really both geographies?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

Well, certainly as we, I think, indicated in the fall that our U.S. portfolio is strong and we had at least one project that was sort of on the rim of coming to fruition, and that situation continues. Certainly expect that we should have something coming out of the U.S. side. When you look at what might be our competitive positioning in Alberta, we've got Whitla 2, which has many of the competitive attributes of Whitla 1, so pretty positive from that perspective. And then we've got Halkirk 2, which is a very strong project in and of its own right. And then we're also -- for the government split in the portfolio between the 400 and 300 in the First Nations' participation. In the 300, we think we're very well positioned for that with sort of our existing relationship with the Siksika Nation. So I think we'll be a very strong competitor in the next round, and hopefully, we'll be successful there as well.

[Operator]

Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.

[Jeremy Rosenfield, Equity Research Analyst]

A few questions, just first on the capacity market design. There was some wording around provisions against bilateral contracts. And I was just wondering if you had thought that, that might have any impact? Or if you're just watching that closely to see if that might impact how you structure or how you think about the Genesee expansion going forward?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So the Genesee expansion, and I think when you think of -- in terms of the -- our partner ENMAX and the agreement that we have with them in terms of them taking half of our capacity, I don't believe that wording is intended to preclude contracts with differences, financial agreements. I believe that a fair amount of their concern around this capacity market and that wording is around whether you actually have a bilateral physical contract. And so I think -- which tends not to be that common in this market. But I don't think that, that necessarily impacts on our outlook at all.

[Jeremy Rosenfield, Equity Research Analyst]

Okay, that's helpful. Second question is just on the capacity market design. Just in terms of the outlook for capacity payments versus energy payments specifically and whether the outlook for the -- based on the company's internal modeling is for maybe higher energy payments and lower capacity payments or flip or how your own internal modeling measures compared to what the AESO has done?

[Bryan DeNeve]

So we're still working through modeling the detailed design that has been put forward. But preliminary indications are that our numbers are going to look similar to what the government published.

[Jeremy Rosenfield, Equity Research Analyst]

Okay, that's helpful. And maybe just a final question just on whether you're maybe concerned or worried at all that AESO and the government might launch a large-scale hydro RFP and whether that might impact the capacity market design and pricing in the Alberta power market? Trying to read a little bit between lines of what you were saying earlier, I think, Brian, on -- you like the rough outlook, but as long as there is no intervention from outside parties.

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

The -- when you sort of -- so first of all, I mean, we've obviously had discussions with the government about what exactly are they looking for, what exactly are they thinking. And it is a sincere approach by the government to see what's out there as opposed to necessarily trying to fit a particular project or initiative. So there could be a whole range of different things. And obviously, in the capacity market, it would necessarily be supportive of something like a very, very large hydro or things of that nature. So it does certainly plumb for a level of interest in the overall market from that perspective. And again, they're not looking to try and fit either hydro or nuclear or anything else. It's a very broad sort of investigation. Now let's assume that they conclude that there is something out there and launch an RFP process, the nature of any of that, whether it's a large hydro, whether it's geothermal or any sort of dispatchable renewable, it is the long lead time, both in development and then permitting and then eventually power coming to the grid. So I don't think you would expect to see anything of that until, say, 2025 or after. And certainly with the growth that we're seeing in the Alberta market and what we see happening in terms of coal -- definite timing for coal plants to potentially be coming off, what it would effectively do is likely displace, say, a natural gas plant that otherwise would have been built. So I think the market, given time, can certainly react to it. Historically, we've talked the same way in terms of transmission. There's specific intertie or power relationship between Alberta and B.C. and it's prescribed in public. Again, that's likely not in place for a number of years and the market will react.

[Operator]

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

[Robert Michael Kwan, Analyst]

If I come back to your answers on the NCIB a couple of questions ago, just to make sure I'm understanding, so you talked about having the NCIB outstanding at all times. And so it's kind of a strategic decision. Is that fair, i.e., given in response to kind of right here right now you're seeing your share price as being particularly attractive and we should be expecting you to be active immediately under?

[Bryan DeNeve]

Yes. So Robert, a lot of it comes down to, as Brian mentioned, the lumpiness we see in growth in those opportunities. So there's opportunities we're evaluating and looking at and -- as we move forward. But certainly if nothing comes to fruition and at the same time we look at our share price and see significant value in buying back shares, that is something we'll do. And certainly, where we're trading at today, absent a growth project with capital requirements, it'd be something we'd be looking at doing.

[Robert Michael Kwan, Analyst]

Okay. Maybe then just follow on that with respect to how you're looking at your shares vis-à-vis capital allocation and maybe tie it back to Whitla. And based on the numbers that you put forward, I think you're building it at about 12x EBITDA and your stock is trading below 10x EBITDA. And you've done a lot of work, actually a lot of work here to really kind of contract up the portfolio, get yourselves -- get the dividend very well covered. So how are you -- how does a decision then work to pursue growth project at a multiple higher than where you're trading at?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So Robert, obviously, there's -- I mean, what you've described is obviously a very accurate picture. And when we look at it, there's 2 things here. One is sort of the immediate view economically. And there is the longer view. And as we've been saying and I think we've been pretty blunt over the last little while that we certainly see as the Alberta power market becomes clearer and as we see the contracted portfolio expanding, that we should certainly see some reaction to the market in terms of multiples and reduced yield associated with our stock. So there is a bit of, I'll say, a medium-term play in here as well in terms of creating value for shareholders, which is achieving much more positive multiples and driving down our share yield.

[Robert Michael Kwan, Analyst]

But again, Bryan -- sorry, go ahead. Finished?

[Bryan DeNeve]

No, I'd just add to what Brian said, the other consideration on something like Whitla is there are significant tax advantages with that project, which goes into the consideration.

[Robert Michael Kwan, Analyst]

Okay. So maybe I don't know if that's the answer on the AFFO yield, although your own AFFO yield is pretty high. So I guess, well we know that the RFP wasn't a one-shot deal and we knew that there was going to be multiple opportunities to pursue something like Whitla. So coming back, Bryan, then to your statement that you expect, as things become clearer, that your multiple will go higher, your stock will go higher, effectively driving your yield down. Why then not the decision to be buying back the stock today and bid Whitla into rounds 2, 3, 4?

[Bryan DeNeve]

So Robert, are you -- in terms of bidding in future rounds 2, 3, 4, the trade-off of that versus buying back shares today?

[Robert Michael Kwan, Analyst]

Yes. So just kind of what went into the decision to decide to bid Whitla and at that level in the round 1 versus bidding in the later round using that excess cash to buy back the stock, which you're viewing as inexpensive and you're expecting your valuation to go higher as the market becomes clearer, but definitely your yield lower?

[Bryan DeNeve]

Yes. Well, I think, part of it is, Robert, is that the capital expenditure on something like Whitla is not until 2019. So certainly, when we look at the cash available, I think in the lumpiness of growth we were talking about, that's more on the acquisition side. So -- I mean, the fact that we're proceeding with Whitla isn't really -- doesn't preclude ability to buy back shares under the NCIB necessarily.

[Operator]

[Operator Instructions] Our next question comes from Mark Jarvi of CIBC Capital Markets.

[Mark Thomas Jarvi, Director of Institutional Equity Research]

Yes, I just wanted to clarify one thing in terms of Whitla 2 and Halkirk 2, whether or not you're in a position to bid those in both the second and the third phase or just in the third phase?

[Brian Tellef Vaasjo, Chief Executive Officer, President and Non]

So I think, as it sits today, I think we could be in position to do either. Part of it is the decisions that we make and discussions that we have over the next number of months.

[Operator]

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

[Randy Mah]

Okay. If there are no more questions, we will conclude our call. Thanks again for joining us today and for your interest in Capital Power. Have a good day.

[Operator]

This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.