Capital Power Corporation

Good morning and thank you for joining us today to review Capital Power's fourth quarter and full year 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 me on 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 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 analyses made by the company. Actual results could differ materially from the company’s expectations due to various 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 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 fourth quarter 2018 MD&A. I will now turn the call over to Brian Vaasjo for his remarks starting on slide 4.

Thanks, Randy. Good morning.

I'll start off by recapping our highlights from 2018, it was an excellent year with nearly 600 megawatts of net additional contractor growth added to the fleet. This growth came from both development and acquisitions.

We secured a 12-year contract for 150-megawatt Cardinal Point Wind project and commenced construction of the project with COD in 2020. We completed the 99-megawatt New Frontier Wind project on time and below budget.

On the acquisition side, we acquired Arlington Valley, which added 580 megawatts of contracted growth. As part of our joint venture for K2 Wind, we were presented with an opportunity to divest our one-third minority interest at an attractive valuation, there was open and pre-tax gain of $159 million.

At our Genesee coal facility in Alberta, we advanced our eventual coal to gas conversion plans by securing additional physical gas delivery capacity to the Genesee site. This will enable increased natural gas coal firing and allow for full conversion to natural gas in the future.

We have strong financial performance in 2018 that included generating 395 million in AFFO that exceeded the midpoint of our 350 million to 400 million target range. The strong AFFO performance and committed growth projects allowed us to increase the dividend by 7% for the fifth consecutive year and extend the annual dividend growth guidance to 2021.

Turning to slide 5, I'll briefly touch on the Alberta power market and its stable outlook. In 2018, there was a significant step change in power prices compared to 2017.

This was primarily driven by the mothballing and retirements of coal plants, robust demand growth and a higher carbon tax. The average spot price is $55 per megawatt hour in the fourth quarter 2018, which more than doubled the $22 per megawatt hour spot price in the fourth quarter of 2017.

The forward prices are in the mid $50 per megawatt hour for the balance of 2019. And 2022 to 2021 forward prices are in the mid $40 per megawatt hour due primarily to the lack of liquidity but as well to carbon tax uncertainty and additional wind supply coming on.

I'll now turn the call over to Bryan DeNeve.

Thanks Brian. I'll start by reviewing our Q4 financial results on slide 6.

We completed 2 major planned outages at Genesee 3 in Decatur that lowered our average facility availability to 94% in the fourth quarter compared to 95% a year ago. We recorded a 159 million pre-tax gain on the disposal of our one-third minority interest in K2 Wind.

Adjusted EBITDA before mark-to-market was 166 million in the fourth quarter that was slightly below our expectations. We generated AFFO of 80 million in the quarter, which was generally in line with our expectations.

Of note, we incurred a higher sustaining CapEx to 25 million in the fourth quarter, compared to 30 million in Q4 2017. Slide 7 shows our fourth quarter financial performance compared to the fourth quarter of 2017.

Revenues and other income were $335 million up 28% year over year. Adjusted EBITDA before unrealized changes and fair values of commodity derivatives and emission credits was $166 million, down 3% from the Q4 2017.

The decrease is primarily due to weaker results in the Ontario, BC and US contracted assets and higher corporate expenses that were partially offset by strong upward results. Normalized earnings at $0.33 per share were up 38% compared to $0.24 in the fourth quarter of 2017.

As mentioned, we generated AFFO of $80 million that was down 15% year over year, primarily due to higher sustaining CapEx. AFFO on a per share basis was $0.78 compared to $0.90 in the fourth quarter of 2017.

Turning to Slide 8, which shows our 2018 financial results compared to 2017. Revenues and other income were at $1.4 billion, up 22% from 2017, adjusted EBITDA before unrealized changes in fair value of commodity derivatives of emission credits was $713 million, up 20% primarily due to strong results in the Alberta contracted facility segment and a full year contributions from assets acquired in development 2017.

Normalized earnings were $1.20 per share up 7% compared to $1.12 in 2017. AFFO of $397 million was 10% higher than $361 million in 2017 and AFFO on a per share basis was $3.85 compared to $3.58 in 2017.

Overall, we had a strong year over year performance in all our key financial metrics. Turning to Slide 9, I'll provide an update on our Alberta commercial portfolio positions.

There'll only be moderate changes to our commercial hedging profile for 2019 to 2021 since our updates at Investor Day in December. For 2019 we are 78% hedged at an average contract price in the mid $50 per megawatt hour range.

For 2020 we're 34% hedged at an average contract price in the low $50 per megawatt hour range, for 2021 we're 1% hedged at an average contract price in the low $80 per megawatt hour range. This compares to current average forward prices of $54, $47 and $45 per megawatt hour for 2019 to 2021, respectively.

We continue to benefit from having nearly 500 megawatts of gas peaking and wind to capture the upside from low natural gas prices, higher power prices and price volatility. I will now turn the call to Brian.

Thanks Bryan. I'll conclude our comments by comparing our 2018 performance against our targets and outline our 2019 targets.

As shown on the Slide 10, we met our average facility availability of 95% our sustaining capital expenditures of $79 million came in below that $85 million dollar target. We reported $238 million in facility operating and maintenance expense that was within the $230 million to $250 million target.

And we've generated $397 million in AFFO that was at the high end of the $360 million to $400 million target range. Slide 11 outlines our development and construction targets for 2018.

We completed New Frontier on schedule with commercial operations commencing last December and received net tax equity financing of 125 million from the tax equity partner JP Morgan. The project was completed slightly below its $182 million budget.

Therefore, the returns on the project are forecast to exceed the original expectations. We continue to construct Whitla Wind and the project is tracking on budget and on schedule with commercial operations expected in the first quarter, fourth quarter of this year.

On the development side, our goal was execute contracts for the output of one to three wind projects. We met this target by executing a 12-year PPA at a 15-year contract for Cardinal Point Wind project.

For 2019, I'll quickly highlight our targets starting on slide 12. Our operational targets include average facility availability of 95%, which was the same target for 2018 our sustaining CapEx target ranges 80 million to 90 million, which is consistent with the 2018 target.

Our financial targets are shown on slide 13. Adjusted EBITDA is forecasted to be between 800 million and 850 million, 16% increase based on the midpoint of the range compared to 2018 results.

Our target of AFFO was 460 million to 510 million, representing a 22% increase compared to 2018 results. Finally, our 2019 development and construction targets are shown on slide 14, we currently have two fully contracted wind projects under construction.

This includes Whitla Wind in Alberta that has a 315 million to 325 million budget with commercial operations targeted for the fourth quarter of this year. We also have our Cardinal Point Wind project under construction in Illinois.

The budget is 289 million to 301 million with a target to begin commercial operations in March 2020. Once completed these two wind projects will add 350 megawatts of long-term contractor generation to our fleet.

We are also targeting 500 million of committed contracted growth capital in 2019. I'll now turn the call back over to Randy.

Thanks Bryan. Claudia we're ready to start the Q&A session.

Just on slide 9 here. Let's say your hedging positions.

You're still fairly open in 2020 and despite the normal accreditation for prices, and you mentioned the carbon tax uncertainty. But just wondering how you're thinking about putting on additional hedges here ahead of the election in the spring or do you think the four prices in the mid to high-40s fairly reflects where spot prices will likely settle under a lower carbon tax scenario?

When we look at forward crisis in 2020 and 2021. We feel they do materially under state where we believe prices will settle, even with some changes in the carbon compliance program.

So if that gap persists, you probably won't see us selling much forward into the market at those current forward prices.

Okay, that's great. And then just with respect to your standing CapEx target of $80 million to $90 million here in 2019.

Can you remind us what happens to that range as you ramp up your coal firing capabilities at Genesee into 2020? Does that target come down at all?

No we expect it'd more or less remain within that range. As we as we burn more natural gas, we do expect there will be some benefits in terms of maintenance CapEx, but it wouldn't be material enough to make a substantial change to that projection.

Okay. I'll jump back on the queue.

Thanks.

Yeah thanks. Good morning guys.

My first question just generally in the US wind market, as we started getting closer to the sunset period and wind PTC. Just any thoughts you have on how development will play out over the next couple years is that approaches that potential supplier bottlenecks, if any, and how bidding seems to be going?

So there continues to be significant interest in construction and development of a wind farms across the US. Our general expectation is that, there'll be a sort of a repause in the market without any real serious disruption in what you considered normalized development and construction activities.

I think all recognize that their level of activity in 2020 is not normal, so somewhat higher. So we, again, we expect 2021 and 2022 to be somewhat softer, but more in line with historical levels.

Okay, great. Thanks.

That's helpful. And then maybe just one other question, what are your thoughts on potential to participate in future solar development in Alberta that seems to be getting going now?

So we've always had an interest in, in moving into solar facilities. As you know, we do have one solar farm, certainly the acquisition of the Arlington facility added a tremendous amount of acreage that at some point in time we expect to be in solar.

In addition to that, we have recently acquired a site in Alberta that is a solar site that is well along in the in the permitting process, so we do expect sometime over the next few years to develop and build a solar farm somewhere.

Great. Thanks.

Appreciate that. I'll get back in the queue.

Good morning, everyone. So in your prepared remarks, you mentioned the possibility of lower carbon taxes in Alberta, just given the political uncertainty there.

Taking that even further into 2021, have you seen any changes in how you see capacity market forming depending on how or which government is in power at the time?

So in terms of any narrative on the capacity market, we haven't seen anything from the any of the any of the parties in terms of it being a political issue for the election. So I'd say at this point there's really nothing has been said, nothing has been stated.

And we wouldn't expect, it would be the kind of issue that would become a political issue at this point in time. Would reiterate that, as evidence by our on ongoing and past results we're extremely comfortable in a capacity market and certainly would do, continue to do very well if things move that continued with the energy only market.

In a capacity market again properly structured, that would be fine by us. So either way, so we would expect to do, continue to do very well in the Alberta market.

And then as a follow-up just looking back at Q4. In your prepared remarks, you mentioned that EBITDA was below your expectations for Q4, but free cash flow was in line.

Can you just walk us through some of the drivers there or why it was below your expectations?

So in Q4, it came in below our expectations from an EBITDA perspective. There were a couple of factors.

One was wind production came in below forecasts at a couple of our wind facilities. And the other driver was the accounting treatment at K2.

So that became an asset held for sale at the end of October so no longer contributed to EBITDA for the last two months of the year. So those were the primary drivers.

The one other one was that Bloom, because of the changed tax reform the benefits to the tax equity investor, which is consolidated on in our results that was lower than expected. So, but you may recall, we renegotiated that the tax equity agreement in net-net for 2018, there would have been a positive lift in terms of EBITDA.

Just wanted to touch in on Decatur first. Firstly, you have operations going in the asset, just wondering how it came in, relative to the expectations, when you guys parted the asset?

So, Decatur had a strong year in 2018 and actually has, had more generation than anticipated. So positive results relative to our initial expectations.

So relative to the 60 million of EBITDA like sort of how much incremental you guys eked out in 2018?

It was probably 2 million to 3 million.

And then just going to the Alberta commercial segment. I mean, obviously, some of your peakers were more active, higher average price, AECO was a bit lower, yet kind of flat year-over-year and the quarter, but also flat year-over-year for the full year.

Maybe talk a little bit about, why maybe we're not seeing a bit higher EBITDA and cash flow of those assets?

I think what we've seen out of the Clover Bar facilities and Joffre, they came in quite significantly ahead of our expectations in 2018. So in particular with a lower gas prices and higher power prices in effect, at much higher spark spread that contributed to significantly higher generation at our peaking facilities.

And then I guess on the other side. Is there anything at Genesee 3 or Keephills 3 in terms of anything in 2018 that sort of was a drag on performance or what you guys generated this year or this quarter should be pretty reflective if power prices hold in here through '19.

Yeah, the generation should be consistent on a go forward basis with what we saw in 2018.

Okay thanks.

Now, I did want to just mention my response to Decatur. For the full year in 2018, it's actually had about $9 million positive variance in EBITDA for the entire year.

So part of that was due to higher than expected generation as I described earlier, but also we saw a positive impact due to favorable exchange rate.

Right. Okay.

Maybe just one last question for me. In terms of how much you guys were have been substituting coal for gas either in Q4 in the current outlook right now here in the beginning of 2019?

So we were utilizing a lot of gas during the period of low prices during the summer and fall of last year. As gas prices have recovered, particularly with the cold weather we've seen in Alberta, the coal firing has dropped off completely.

We do expect, however, we've started to see that resume again with lower natural gas prices as we move into the spring and summer months.

Okay. Thanks guys.

Thank you good morning. Given some of the robust presence we've seen for renewable generation.

Do you see some further monetization opportunities across your portfolio?

So Andrew as we look at that, and I think, when we looked at as a K2 sale, one of the other elements associated with that sale was the fact that we would move to being a one third owner among three to be, a one third owner and the other one are having two thirds of the, the interest in that facility. That was somewhat of a compelling factor for us to look at the value that came forward to.

As we looked across the rest of our assets, we would need an extremely compelling price, all I would say beyond what we saw with K2 for a wholly owned asset. So we're not looking to monetize any of any of the balance of our renewable assets at this point and wouldn't expect a situation to evolve where we would.

Okay, appreciate that. And then maybe just an update on what you're seeing with deal flow across North America as far as asset transactions that are being shopped at this point in time, things that you're actively looking at.

If you could give us any color on what you're seeing on a broad market basis?

So there continues to be a fair amount of activity related to natural gas on contracted assets. And we continue to look at those.

And at any point in time actively involved in a couple of them, I would say. There are continue to be some renewable opportunities in terms of the larger portfolios, et cetera, as like the Sempra facility sale that was announced last week.

And again, those depending on a particular circumstances we may look at, but there continues to be a relatively robust pipeline overall.

That's great. Thank you.

On the 2019 outlook and also the change in your hedges with it being mid-50s hedged for '19 versus lows in a recent guidance. I wanted to clarify, are you mentioned, are you modestly more positive on your outlook than the '18 Investor Day?

No. I would say we're probably consistent with our outlook at Investor Day.

Okay.

As we look at the year so far, our prices came in somewhat low expectations for January 2019. But February has been significantly above expectations.

So on balance what we've seen to date and then looking over the balance of the year. We sort of have similar expectations as we would have in December.

And then on the same topic, the 500 million of CapEx. I was more curious, how to think about, if you were not success on the development side.

Is there thinking that, if it's going to be acquisitions that backfill that. And if not, it looks like you put again NTIB is it the number three buying back stock?

So maybe Ben starting backwards, I mean you, I think you can always expect will have an NTIB in place. I think that's just proper balance sheet management and dealing with supporting share price, when appropriate et cetera.

So I think you're going to always, you can always expect that and I wouldn't read anything in particular has changed in terms of our views around that. In respect of our outlook for 2019, we would expect that and I think we reflected in our discussion in Investor Day.

So we do expect that we should be able to secure wind fund developments in 2019. So we'd see that as part of the mix.

And certainly, we say, I was just commenting we see a lot of opportunities associated with acquisitions. Like the last couple of years, we would hope and expect that we could meet that, meet and beat that $500 million target.

But again, we'll see as the year unfolds.

And can I clarify, what do you think about stock buybacks. Is this buying back 250 the equivalent of 500 million deployed on organic growth?

Roughly speaking, it would be.

And then lastly, I don't think you're part of the recent, so our fleet that was announced. I'm just want to check on that?

That's true. Yes.

I have a couple of questions. First, in terms of the capacity market option for later this year.

Do you expect that AECO will have, will be able to get that schedule locked down and be able to execute a capacity market auction by the end of this year?

Well, they definitely continue on that path. Having said that, there's a it's a pretty aggressive schedule and there's a lot to be done between now and then.

So again, we'll see.

Okay. And maybe just turning to Arlington for a second.

I'm just wondering if there are any updates in terms of off peak contracting discussions and negotiations or I look on that at this point?

Sure. We had, going back to when we made the acquisition at Investor Day, we'd indicated that we had expected to close fairly quickly on getting a contract for the balance of the year that would be somewhat parallel in length to the underlying summer contracts.

As events unfolded there's a bit of a softening very temporary softening in the market in and around our closing date. I'm happy to say that the market has been firming up since then.

And we would expect some time in the first quarter to secure a longer term tolling arrangement or arrangements for the balance of the facility that's not contracted.

Good. We'll look forward to that.

And then maybe just to clean up. There's a note about record sales into PG&E and I'm just wondering if you can clarify the materiality of that.

And also, just linking that to Arlington was Arlington able to wield power into PG&E and does the bankruptcy sort of remove a potential counterparty or the short term?

Starting with Arlington. It certainly does have the capability that sale into the California market.

But I'm not aware that there's been any sales recently or expected through the PG&E. So I don't think there's any implications for Arlington by the by the PG&E situation.

In terms of the recs, we do sell recs off of our Hellkirk Wind facility into PG&E. When we completed that facility in 2013, we had mentioned that 40% to 45% of the revenue was sourced from that contract with PG&E.

Our view currently is that, based on external legal view, and what we're seeing out there, there's still a fairly high probability that that contract will remain in place. If by some chance and it was terminated, we would be free then to take those recs and remarket them and we would do that most likely in the Alberta market.

Okay, great. That's it for me.

Thanks.

Good morning. If I can just come back to the plans for the NCIB.

So Brian you mentioned it being good practice to have that outstanding but given the step up in the CapEx or the growth committed growth CapEx for this year, is it fair that at least your base expectation is not to materially use the 9 million or so shares?

Subject to share price I think that's reasonable.

Okay and I guess. On that comment subject to share price certainly tactically utilizing it where would you look to from the source of funds given the committed CapEx program?

Like would you be taking leverage up or to an earlier question would you actually look to sell assets?

So maybe I can come at it from this direction, Robert. When we look at a target of 500 million committed capital for 2019, that's over and above the capital expenditures we're making on Cardinal Point in Whitla Wind.

And that incremental 500 million we'd be able to do that without having to go to the equity market. So our balance sheet is positioned to be able to do an incremental 500 million of growth CapEx based on internally generated funds.

So if that growth doesn't materialize and if we feel our share price is undervalued, that then would be a situation that we have utilized the NCIB. And it would basically be utilizing the capabilities of the balance sheet that would support that 500 million in committed capital growth.

In terms of just coming back to the Alberta election, you've touched on carbon and market structures. Just wondering, is there anything else upon your mind as you think about how the politics could go post election in terms of an impact here?

Well certainly, the status quo is what is what we've managed to and what we're positioned for. When, I did comment earlier about the fact that, if we, if the change in government resulted in continuing with the energy only market we'd be happy with that and likewise if properly structured capacity market we'd be fine with that as well.

When it comes to the carbon side and carbon tax side the narrative from the UCP had started off suggesting moving back SGER comments of late have been more around continuing with something that's like the CCIR. Or we would expect that again with the general direction of reducing carbon tax that there will be some reduced carbon tax exposure for Capital Power.

But it's too early and hasn't been enough set to appropriately assess that.

I can finish and just confirming I think it was in the explanation and you give for, but for Ontario and BC the year-over-year decline was that sounds like it was largely due to you're not are stopping booking K2 into the second. Is that fair?

It would be that combined with falling short on a couple of our wind facilities in those jurisdictions in terms of output.

Okay. If there are no more questions, we'll conclude our conference call.

Thank you for joining us today and for your interest in Capital Power. Have a good day everyone.