Capital Power Corporation

Randy Mah - Director of Investor Relations Brian Vaasjo - President and Chief Executive Officer Bryan DeNeve - Senior Vice President and Chief Financial Officer

David Quezada - Raymond James Mark Jarvi - CIBC World Markets Ben Pham - BMO Andrew Kuske - Credit Suisse Robert Kwan - RBC Capital Markets Jeremy Rosenfield - Industrial Alliance Securities Robert Hope - Scotia Capital Patrick Kenny - National Bank Financial

Good morning and thank you for joining us today to review Capital Power's second 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.

On the call this morning is Brian Vaasjo, President and CEO and Bryan DeNeve, Senior Vice President and CFO. We will start the call with opening comments and then open the lines to take your questions.

Before we start, I would like to provide listeners that certain statements about future events made on this call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results could differ materially from the company's expectations due to various material risks and uncertainties associated with our business.

Please refer to the cautionary statement on forward-looking information on slide number 2. In today's presentation, we will be referring to various non-GAAP financial measures as noted on slide number 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 for management's perspective.

Reconciliation of these non-GAAP financial measures can be found in our second quarter 2018 MD&A. I will now turn the call over to Brian Vaasjo for his remarks starting on Slide 4.

Thanks, Randy and good morning. We had a number of achievements in the second quarter, which are highlighted on this slide.

This included a 7% increase to the dividend, which increased the annualized dividend from $1.67 to 1.79 per share. We executed a 12 year contract for 150 megawatt Cardinal Point Wind project, which is expected to be operational in 2020.

We added approximately 78 megawatts to our US growth pipeline with the acquisition of the Green Hills Wind project in Missouri. We acquired a 5% interest in C2CNT, a company that captures and transforms carbon dioxide into carbon nanotubes.

And finally we secured additional physical natural gas delivery capacity for the Genesee site. This allows for increased natural gas co-firing in 2019 and further natural gas conversion of a coal facility as early as 2020.

Turning to Slide 5, the chart illustrates our dividend history and guidance. This year's dividend increase represents our fifth consecutive annual increase of 7%.

Our current dividend guidance includes an annual 7% dividend increase owed to 2020. Further dividend growth is supported by generating approximately 200 million per year in discretionary cash flow, which supports 400 million to 500 million of annual growth CapEx per year.

Also supporting the dividend is an AFFO payout ratio target of 45% to 55%. Moving to Slide 6, in the second quarter the average Alberta's power price was $56 per megawatt hour, this clearly triple of $19 per megawatt hour in the second quarter of 2017.

As you can see from the Alberta peak demand chart, there's an upward trend for both the winter and summer peak demand periods. The current demand growth of 3% to 4% resulted in a new summer peak demand record of 11,100 megawatts being set earlier this month.

The Alberta power market has recovered and Capital Power has the best fleet of assets in the province to capture value. Turning to Slide 7, with an update of the Alberta capacity market design, AESO has now finalized its proposed market design.

The design is constructive and provides an equal opportunity for existing and new assets to earn a return on and of capital. The key design elements such as participation, market mitigation and term length are reasonable as expected.

AESO's next step in the process is to seek additional consultation with stakeholders on the technical details and finalization of various design elements. AESO will then translate its design into market rules for submission to the AUC for approval.

The final design is consistent with our view of a properly designed capacity market for Alberta and we're positioned under the market design to do very well. Slide 8 summarizes the progress made our renewables growth strategy.

We currently have 450 megawatts under construction and advanced development from three contracted wind projects that will add to our fleet over the next two years. We have 245 megawatts of potential wind development opportunities to develop in the Alberta's renewable electricity program and we have approximately 1,200 megawatts of potential wind development opportunities located throughout the US.

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

Thanks, Brian. I'll review our second quarter financial performance, starting on slide 9.

Overall, financial results in the second quarter exceeded our expectations. This includes generating 76 million in adjusted funds from operations and adjusted EBITDA of 201 million.

In the second quarter we re-negotiated the Bloom Wind Tax equity agreement. A change in law provision was triggered in the agreement due to the reduction in the US Federal corporate tax rate that was effective on January 1, 2018.

Under revised commercial terms, the Bloom partnership claimed bonus tax depreciation in 2017, to capture a larger portion of the tax depreciation at the 35% federal income tax rate versus the 21% rate that became effective January 1, 2018. This resulted in a onetime non-cash increase to adjusted EBITDA of 44 million.

Additional information for modeling Bloom Wind is shown on Slide 10. On the chart we show the impact from the renegotiated tax equity agreement on EBITDA and pre-tax cash flow.

The chart is intended to be illustrative and all other inputs such as generation, production tax credits and foreign exchange rates were held constant. Under the re-negotiated tax equity agreement in considering the reduction in US Federal corporate tax rate, we've maintained our original expected returns from Bloom Wind.

Slide 11, shows our second quarter financial performance compared to the second quarter of 2017. Revenues and other income were 363 million up 81% year-over-year.

Adjusted EBITDA before unrealized changes in fair values was 201 million, up 61% from the second quarter of 2017. The increase was due to the amended Bloom Wind Tax equity agreement, a greater contribution from the Alberta contracted facilities and a full quarter of contributions from Decatur Energy in Bloom Wind.

Normalized earnings of $0.22 per share were down 19% compared to $0.27 in the second quarter of 2017. As mentioned we generated adjusted funds from operations of 76 million, which was 73% up year-over-year.

AFFO on a per share basis was $0.74 compared to $0.45 in the second quarter of 2017. Slide 12, shows the financial results for the first half of the year compared to 2017.

Revenues and other income were 670 million, up 24% from 2017. Adjusted EBITDA before unrealized changes in fair value was 374 million, up 44% for the same period in 2017, primarily due to the amended Bloom Wind Tax equity agreement a full six months of contributions from Bloom Wind in additional assets acquired in 2017.

Normalized earnings of $0.52 per share were down 15% compared to $0.61 in 2017. Adjusted funds from operations of 161 million was 22% higher than the 132 million in 2017, AFFO on a per share basis was a $1.55, up 14% compared to a $1.36 in the first six months of 2017.

Turning to Slide 13, our commercial hedging profile for 2019 to 2021 at the end of the second quarter of 2018 is shown on the Slide, The hedge percentages in all three years have increased slightly compared to the percentages at the end of the first quarter of this year. For 2019 we're 49% hedged at an average contract price in low $50 per megawatt hour range.

For 2020 we're 25% hedged at an average contract price in the low $50 per megawatt hour range and 2021 we're 5% hedged at an average contract price in the mid $50 per megawatt hour range. This compares to current average forward prices of $56 for 2019, $52 for 2020 and $48 for 2021.

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

Thanks, Bryan. The chart on Slide 14, show six month operational and financial performance compared to ours 2018 annual targets.

In the first half of the year average facility availability was 95%, which is consistent with our 95% annual target. Our sustaining CapEx was 41 million compared to the 85 million annual target.

We reported 121 million in facility operating and maintenance expense versus the 230 million to 250 million annual target. We generated 161 million in adjusted funds from operations in the first six months compared to the 360 million to 400 million annual target range.

We continue to expect our 2018 AFFO to be above the midpoint of the range. Slide 15, outlines our construction and development target for 2018.

We currently have two wind projects under construction. The construction goal for new frontier is completing the project within 182 million budget with COD in December 2018.

The other construction project is completing Whitla Wind within its 315 million to 325 million budget with the COD in the fourth quarter of 2019. On the development side, our goal is to execute contracts for the output of one to three wind development projects.

As highlighted earlier we have executed a contract for the Cardinal Wind project. We have growth opportunities from the Alberta renewable electricity program and from our 1,200 megawatts of potential wind development opportunities in the US.

I will now turn the call back to Randy.

Okay. Thanks, Brian.

Operator, we're ready for question-and-answer session.

Thanks. Good morning, guys.

I guess my first question just on the outlook for development of wind in the US. I'm wondering what your thoughts are on I guess contractor availability and any potential for there to be a little bit of congestion and develop just given the huge overall pipeline in the country and when you think kind of an effective deadline will be for go forward on projects just given the 2020 deadline for completion?

So in response to your first question I would not see much evidence of shortage of either turbines or contractors in the US to or Canada to execute on projects and there continues to be there are significant amount of capacity that is available to us. In terms of the deadline or the completion by the end of 2020, a lot depends on the particulars of project certainly some of the smaller projects can certainly be done within a calendar year from start to finish especially in the US where as you go south it's easier from a construction no win construction.

But again very much depending dependent on a particular project and where it is on permeating et cetera. So we when we look across our projects we see a number of projects that we could potentially move to actually starting construction or advanced development within 2019 for completion and 2020.

Okay, great. Thank you is very helpful.

And my only question just on the increased capacity for natural gas delivery Genesee I notice in the release it's you said as early as 2020 for potential conversion. I'm wondering if any color you can provide on my on your thoughts as to what will govern your decision on the timing for that?

So timing decisions continues to be the same as it relates to be clarity around carbon pricing as well as the outlook for natural gas. What we've been doing over the last couple of years is maximizing our optionality and shortening up the time frame in which we can react.

And obviously one of the significant elements around that ability to react quickly is having natural gas to the site. So we've dealt with that so to speak long lead time item.

In addition to that and what's very significant to our outlook over the next few years is a factor that moves us to a position where we can coal fire more and more natural gas in the coal units. And as we move forward through the back part of 2019 and into 2020 we expect to be called firing and have the capacity to coal fire no significantly greater than it is today.

So there are a number of reasons to get natural significant volumes of natural gas to the site no sooner rather than later but certainly does facilitate a timely decision around the conversion of natural gas of those core units. Now we haven't changed our fundamental outlook from what we've had before but until you see some significant increases in carbon prices or we don't see a conversion to natural gas until at least 2020 or beyond.

Okay, great. Thank you very much, that's all I had.

Hi, good morning. I want to touch on the hedging I think it has been in the disclosures that we are 93% hedged in the quarter and 87% overall for the year I think you are close to 100% in Q1.

So if you give us some context for Q3 and Q4 to you position yourself to be quite open for the some on the peak pricing?

We've continued to manage our position for the balance of the year, can't really get into specific percentages of hedging for those two quarters. But it would be in the ballpark of what you'd seen going into the year.

Okay. And then if you try some context with the optimization revenue in the quarter and any unrealized pricing.

Is I just all related to the hedging book or is there some other things that happened in terms of not be able to realize as higher prices what the market provide in the quarter?

Yes. So one of the things to look at is our capture price includes a number of elements.

So it would include the weighted average price of all the hedges we would have entered into for the quarter over the past two to three years, depending on the timing of when those hedges were entered into. Certainly Q2 typically a lower price quarter relative to the rest of the year, so you can expect that our portfolio that was locked in was locked in price is more on the lower side.

And on top of that, we would look at what did we realize with our peaking facilities and the small amount of length that we didn't hedge forward so all that gets rolled together. Basically the fact that our capture price came in below the settled price for the quarter primarily is just a reflection of the fact that we had some long term hedges that we entered into a number of years ago.

Okay. And then I just wanted to move there's a comment in the in the press release about you guys are actually participating competitive opportunities to acquire contracted wind assets, I think you provide more contacts and I guess that's a new comment whether or not that includes offering offsets whether or not operating in renewable assets or something you guys are pursuing right now?

So we continue to look across the broad spectrum of opportunities whether they be natural gas or wind in and acquiring fully contracted operational assets. On the renewable side, occasionally when we see one where we think we may be able to bring some expertise or more manage some risks around those operations.

But again those are those are relatively few. What we do see a lot of now is an increasing number of opportunities to buy sites or acquire interest in sites that have high potential for becoming fully contracted assets in the relatively near term.

Just following-on that comment maybe you can provide, a bit of color on the Green Hills project in terms of the stages at how you guys came to get your hands on that project. So there's a number, there's a number of projects on actually both sides of the border that come to light probably every quarter we're looking at had ten to a dozen sites into an assessing their potential and their ability to actually come to fruition again in the relatively near term?

As it relates to that specific project, we do expect that certainly it will come to fruition within be complete by the end of 2020, it does have a high potential for contracting and we are continuing our we are going through and looking at this point in time in terms of actually marketing that project in Missouri and in the surrounding areas.

Does it possible that you could get a contract before you're on the project?

Yes. It is.

Alright, I leave it there. Thank you, guys.

Hi, thanks. Good morning.

Had a question Alberta key for this year, can you comment on the queue you're seeing in terms of potential bidders versus the first iteration?

So I'm trying to I don't believe Ben and I could be mistaken. I don't believe the queue has been identified at this point.

You could correct me if I'm rude, but I can say that we do expect that it will be highly competitive and probably not a lot different in terms of numbers than last year.

Okay, alright. Can I ask you on the Slide on the Bloom Wind EBITDA cash flow movement around?

So on the cash flow it looks like the trend has modestly lower from before. So I'm just wondering why do the returns aren't different.

Is there a change in denominator portion?

Yeah where we make it up Ben which is shown on this graph is the fact that after the flip in the contract period. We benefit from the lower corporate tax rate in the US.

Okay, alright. And can I have follow-up on hedging question it seems like it's and maybe to want to clarify that if they realized price includes year your peaking facilities what's seen a run very well it suggests that your hedge price looks like it's probably more in the $45 range.

And so if you're hedged high 40's coming into the year. Would you say that you're closer to the fourth curve in the second half than maybe the high 40's?

Yeah. As I mentioned earlier Ben, Q2 typically it's a low trading quarter in the forward market.

So hedges we would have entered into for that quarter with typically be less than the rate in other quarters in the year.

Okay, alright. Alright, guys.

Thanks a lot.

Thank you, good morning. Her is the questions for all either of the Bryans really on the Issuer Bid and how do you think about just the constraints on buying back stock versus other forms of capital return like dividends and then also just ongoing reinvestment in the business?

So we have two primary considerations when we look at I'm purchasing back stock. First fears of course, where stock price is trading relative to our view of the value of the corporation at current levels we're trading out we still believe we're undervalued.

So but having said that we also are very mindful of the growth pipeline that we have and how close we are to having new growth projects materialize and what is things we just want to be careful of is that we're not buying back stock and then following or not having to access the equity market and the costs associated with that. So that's the balance we try to maintain so really our activity in buying back stock a lot of it hinges on the status of our development portfolio.

And then maybe just an extension on that when you think about the development portfolio and your balance opportunities outside of Alberta versus those and Alberta where you've obviously got a very big position as an incumbent. How do you think about the internal development capability within the province of Alberta not just the demand that you're seeing on which is obviously robust but how much of the demand in the near term has really been driven by weather versus sort of or normalized your things?

Your questions around whether driving our demand growth in Alberta?

Yes, on a near-term basis.

Yeah, so when we speak to you out 3% to 4% demand growth on an annualized basis that is weather normalized. So certainly there's some periods where we've had some very hot weather that has exceeded historical norms and actually has pushed demand growth above 4% but we've normalized that out and generally we're seen in that 3% to 4% range.

And then finally if I may this relates to the last point. If you've got normal weather normalized 3% or 4% growth but you had spiky weather behavior that peak power prices in the quarter is not really what got the optimization offside in the quarter?

Well again I don't think we our optimization was off cycle in the quarter. When you look at our capture price, I think it was around $51 to make what our - it definitely was lower than where the settled price was for the quarter.

But again you have to keep in mind that embedded in our capture price is a historical hedging that we've undertaken over the past two to three years. And Q2 typically in a forward base market trades at the lowest price for the entire year.

So Q2 was really robust, it had high settle prices we captured a lot of that with our peak in facilities, but we also came into the quarter with most of our base load hedged and it was hedged in mid to high 40s so that's why our capture price came in lower.

Okay. That's great.

Thank you.

Good morning. Maybe to start with guidance and some of you there's no change in the statement but you also noted that Q2 results exceeded your expectations.

So are you expecting AFFO for 2018, exceed the high end of the range at this point?

Not at this point, certainly there's still some uncertainties out various as we roll through the balance of the year. We're not ready to make a statement that will be closer to the upper end of the range.

But we're still very confident will exceed the midpoint that at this stage.

Okay. So directionally you are coming out of last quarter you were above the midpoint now you're just further above the midpoint, but you're at all within the range, okay.

That's correct.

Just on the Genesee gas capacity side of things. Is it your own pipe or are you - have you contract for from service on NGTL?

So I guess to be clear here - what's happening is that there is a large pipe that will be built to our station gate by 2019 and there is some portion of that has as you scroll forward in time that we have committed to and I'll say generally reasonably modest commitment. But it's but it has brought a significant amount of natural gas to our station gate.

So sorry, is that a transmission pipe, is it a LBC [ph] pipe or is it a third party new pipe coming?

It's a transit - it's NGTL.

Okay, so you've got - I assume you've got firm service although you'd be subject to any rationing back that NGTL may have?

Yes.

Okay, maybe just to finish - a small question looking into segments Ontario and BC contracted it looks like in the disclosure revenues from the disclosed plants are up a few million dollars, yours a couple million. But the segments down a million.

Now, I don't know if it's K2 still looks like those revenues were down $3 million although the generation was up some just want to get some extra color as to what happened in the segment?

So in terms of Q2 for the BC, Ontario contracted segment. We did have the York facility did not quite come in at expectations for the quarter on an EBITDA basis, so that would be the primary driver.

Okay, but your still $2 million higher year-over-year?

You're right. I'm pretty sure we didn't close York in the first quarter I think it was partly into Q2 of 2107.

I understood. It just it looks like all of your revenue drivers are up with exception of K2, yet the segment was down, so were there some unusual costs in the quarter and then even just as a kind of follow-on why was K2 revenue down $3 million yet generation was higher year-over-year?

We'll have to get back to you on that question.

Okay. Thank you.

Good morning. A couple of questions the Green Hills development project is the ideal agreement a long-term contract or certain opportunity for heads and what's the market maybe for Rex also in that area, can you provide any color?

So as we're looking at it although there's opportunities for Rex as they're broadly speaking, our primary drive areas both ability to tap the market from a hedge perspective, but there's also a number of utility in co-op opportunities in the area so we're looking at a broad array of opportunities in relatively short order.

Okay. And you mentioned that it's close to an existing substation so that implies that there's not a significant risk or a need for transmission infrastructure I know there's another there's a major transmission line that's a project that's a little bit controversial running through I think a little bit so there.

Other part of it is misery, but it's not related to I want it all?

And that's correct.

Okay. Good.

Recently, one of your competitors obviously turns out that completed off core financing. I'm just wondering if there's any attractiveness for Capital Power to do something similar in order to actualize the future payments from the government.

So there's a number of considerations like into that. One element is the way that transaction was related to what's in that strong in our view so that the lift we would get in terms of the beneficial rate isn't as great as we thought it would be.

We also have some tax considerations from our perspective that we're keeping in mind. So I think at the end of the day, it's not something that's hurt our priority list and particularly as it would be we would take up much closer look at if we had a need for a lot of cash at any point in time.

Great, okay and maybe just a final commentary on a difficult subject so obviously in Ontario there were some directives issued by the government recently in relation to projects that were pre-operating, so not impacting your assets specifically but I'm wondering if you have a look at the value of those assets and if you are bracing yourself for potentially into discussions with the government over the actual operations?

So as we have look at we're not seeing any narrative and in fact narrative to the contrary around actually doing something with the operating assets. That there's quite a bit of difference in and between canceling projects providing some level of compensation to projects that haven't started versus those that are an actual operation, that's at the significant step for any government to take in terms of no saying the whole issue is a sanctity of contracts and so on.

I think any developer is always exposed to the potential of a contract to being canceled before realization whether that be others who - as happened in British Columbia, it's happened in Ontario before it will continue to be happening and it happens in other countries. So that I think is all caught up in a risk that developers take that actually change existing or eliminate existing contracts again that is a very dramatic step for a government to take.

So we don't expect that to happen in Ontario and certainly the narrative in the advice we've received is that something that's not on the table.

Okay. That's good to hear.

Alright that's it for me. Thank you.

Good morning, everyone. Along the same theme in terms of Ontario when you're looking at the market renewal that the AESO is going to put forward.

Can you give us some thoughts on how you think that will play out and whether or not that could be headwind to tailwind for your assets?

Well, certainly philosophically we see that that development of any market is being positive. When you look at and assets and even though our assets in Ontario the contracts are up and well down the road.

We see market development is fundamentally being a very positive element. The wind farms of courses are winding issue but when you look at the natural gas facilities both of our facilities are situated to be very important from a transmission perspective and a grid securities perspective.

So we see them as being a little bit different in terms of being very valuable again for obviously the energy generation from time to time, but more from the transmission perspective in a developed market from a developed market perspective, they would have both of those at attributes of value and would be very positive for us.

Alright, thank you for that. And then just moving down south of the border, so you kind of touched on this a little bit before but the changes to tax equity market that we've seen year-to-date, has that potentially cooled your expectations for wind farms moving forward it wouldn't appear so but give us some color on the cost of tax equity there?

So we continue to look at projects in particular where we're currently looking at obviously Cardinal Wind but New Frontier is well. And with New Frontier we've had positive reception and we continue to work tax equity arrangements we haven't seen a significant change in terms of that kind of view is that we could expect in fact that New Frontier continues to be in this zone of yield we were expecting even prior to the changes in the tax laws in the US.

So it continues to be a market that's open to us and open for development.

Thank you. I'll jump back in queue.

Yeah. Good morning, guys.

Just back on potentially converting the Genesee units in a couple years obviously carbon prices and gas prices are key drivers. But also wondering how the coal mine reclamation costs might factor into your decision there.

And I'm just wondering if converting G1 and G2, but say leaving G3 on coal might allow you to push that for decommissioning liability out to 2030, and if that's a factor in your decision to leave at least one unit on coal for a while beyond 2020?

So in terms of kind of taking that question piece by piece, one of the things that - when you look at the Genesee facility and I think you look at any grouping of facilities that utilize a mine, it's actually, economically challenging to leave say one unit on coal. To the reason being is that a lot of your fixed costs remain relatively the same and yet you have to basically have a significant change to your denominator so that that makes it somewhat challenging again to leave one unit in coal and convert two units to natural gas.

In terms of that and then any changes in terms of our outlook and what we might do. We are one of the things that they're bringing more and more natural gas is when you think of an arbitrage case or being able to arbitrage that whole gas more and more which is certain, I would bring that the natural gas capacity to the plant.

What it actually does is it enhances the staying on a cold case because you're able to utilize again greater portions of natural gas which reduces the differentiation between the two cases. So as we continue to look forward, continue to see a lot of optionality around what we're able to do on this site and to optimize our ability to utilize coal and natural gas.

In relation to the cost of reclamation and we've stayed relatively tight in terms of how much we have to do require a morality of to how much of that pit is open today. It's a one basically one mine, where mining is in two areas but again it's a relatively tight cost and cost to reclamation especially spread over a number of years which is the nature of reclamation we don't see as having a very dramatic impact on cash flow.

So it doesn't enter into our considerations of converting to natural gas.

Alright, that's great color. Thanks Brian.

And then just lastly on the credit rating now that pricing has recovered and the final CMB looks to be constructive. Are you having any discussions with SMP or DVRS on what else might be outstanding to perhaps achieve a one notch up great to be made or is it on the radar at all over the next year or so?

SMP and DVRS are certainly assessing the new market design at the fair and coming to conclusions around what that means we expect we'll see something from them potentially in the near future. For us we're not really working towards one notch upgrade.

We feel triple below is the right place for us we certainly maintain our credit metrics in a way that provides cushion to the threshold so that the rating agencies have to maintain triple below. So certainly we're not writing right on the edge but we're not looking to improve those credit metrics to the point of a one notch upgrade.

So I think the expectation is more that we'll maintain that as we move forward.

That's great. Thanks very much, guys.

Okay. There are no more questions.

We'll conclude our conference call. Thank you again for your interest in Capital Power.

Have a good day, everyone.