Capital Power Corporation

Randy Mah – Senior Manager, Investor Relations Brian Vaasjo – President and Chief Executive Officer Bryan DeNeve – Senior Vice President, Finance and Chief Financial Officer

Robert Hope – Scotiabank David Quezada – Raymond James Patrick Kenny – National Bank Financial Ben Pham – BMO Mark Jarvi – CIBC Andrew Kuske – Credit Suisse Avery Haw – TD Securities Robert Kwan – RBC Markets Jeremy Rosenfield – Industrial Alliance Securities

Good morning. Thank you for joining us today to review Capital Power’s third quarter 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 conclude with a question-and-answer session. 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 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 the company’s third quarter 2017 MD&A.

I’ll now turn the call over to Brian Vaasjo for his remarks starting on Slide number 4.

Thanks, Randy, and good morning. I will start off with a review of the highlights in the third quarter.

In August we announced that our second U.S. wind development project New Frontier Wind is underway after we executed a 12-year fixed price contract with Morgan Stanley covering 87% of the facility’s output.

The contract is a revenue swap arrangement involving a fixed volume of generation for a fixed price. The long-term predictable revenues allow the project to secure renewable energy tax equity financing.

The capital cost for the project is estimated to be $182 million with Capital Power funding one-third and the tax equity investor funding two-thirds of the cost. New Frontier Wind located in North Dakota will have 99 megawatts of capacity with commercial operations expected to start in December 2018.

Once completed, New Frontier will be another contracted asset that will strengthen our contracted cash flow profile. Turning to Slide 5.

This slide compares the availability operating performance of our facilities for the third quarter of 2017, and for the first nine months of the year compared to the same period a year ago. We had excellent operational performance in the third quarter with average availability of 97%, which was higher than the 96% from a year earlier.

In the first nine months of the year the average availability was 96% compared to 94% a year ago. There are no major planned outages for the remainder of the year, so we are on track to meet our 95% plant availability target for 2017.

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

Thanks, Brian. I’ll start on Slide 6 with the review of our third quarter financial performance.

Overall, third quarter 2017 financial results were consistent with our expectations. This includes generating $134 million in adjusted funds from operations and normalized earnings per share of $0.28.

Alberta spot prices in the third quarter averaged $25 per megawatt hour compared to $18 per megawatt hour in the third quarter of 2016. Our trading debts performed well and captured 96% higher realized average price of $47 per megawatt hour on our Alberta commercial assets versus the spot price.

This was a result of our trading debts walking in higher prices in advance of the quarter. Despite the strong trading performance this quarter, it was even stronger in the third quarter of 2016, when the trading desk had realized the realized power price is $70 per megawatt hour which reflected trading gains on a material short position resulting from the termination of the Sundance PPA.

Slide 7 shows our third quarter financial performance compared to the third quarter of 2016. Revenues and other income were $346 million, down 7% year-over-year.

Adjusted EBITDA before unrealized changes in fair values was $161 million, up 34% from the third quarter of 2016, primarily due to the additions of the Decatur Energy, Veresen assets and Bloom Wind, which was partially offset by lower portfolio optimization contribution. Normalized earnings of $0.28 per share were down 10% compared to $0.31 in the third quarter of 2016.

As mentioned, we generated adjusted funds from operations of $134 million, which was up 70% on a year-over-year basis. The AFFO includes the annual coal compensation that we received in the third quarter.

Slide 8 shows the financial results on a year-to-date basis. Revenue and other income were $885 million, down 5% from 2016.

Adjusted EBITDA before unrealized changes in fair value was $420 million, up 13% from the same period in 2016, primarily due to the new additions to the fleet and partially offset by lower trading gains. Normalized earnings of $0.88 per share were down 7% compared to $0.95 in 2016.

Adjusted funds from operations of $272 million were higher than a year ago, primarily due to the new acquisitions, the completion of Bloom Wind in the coal compensation payment. The increase in AFFO was partially offset by higher CapEx spending and higher finance expense due to the new acquisitions.

Turning to Slide 9. We are recognizing pre-tax impairment charges of $46 million at Southport and Roxboro due to the uncertainty around capital investments that would be required to meet more restrictive sulfur dioxide emission standards.

Impairment recognizes the fact that the revised emission standards will likely to render the facilities uneconomic once the PPAs expire in 2021. In the third quarter we also recognized a pre-tax impairment charge of $37 million for the Decatur Energy generating facility.

The goodwill associated with Decatur Energy was primarily attributable to the ability to use previously written down U.S. income tax loss carryforwards.

The $86 million income tax recovery recorded in Q2 2017 from the reversal of previous written down deferred tax asset more than offsets a goodwill impairment we are recognizing on Decatur for Q3 2017. Of note, there was no cash impact from these impairments.

On Slide 10 I’ll review the financial outlook. Our updated commercial hedging profile for 2018 to 2020 is shown on the slide.

For 2018 we have increased our hedges from 66% as reported in the second quarter of 2017 to 86% at an average contract price in the high $40 per megawatt hour range. For 2019, we are 45% hedged at an average contract price in the low $50 per megawatt hour range.

And for 2020, we’re 25% hedged at an average contract price in the low $50 per megawatt hour range. Although we have a significant hedge position in 2018, we still have the ability to capture upside from higher prices or price volatility from our Clover Bar peaking facilities, Joffre Cogen and our Halkirk Wind facility.

To conclude, I want to summarize our various financing activity completed this year to fund growth as shown in Slide 11. In total we have raised just over $1 billion in gross proceeds.

This includes $244 million from a tax equity investor, Goldman Sachs, for Bloom Wind. Another $183 million from a common share issuance that was used to partially finance acquisition of Decatur Energy.

In August we raised $150 million from preferred share offering at a 5.75% yield. And most recently we accessed the debt capital markets with $450 million medium-term note in September that had a seven-year term at 4.284%.

We remain committed to maintaining our investment grade credit ratings while strengthening our financing capabilities to fund growth. I’ll now turn the call back to Brian.

Thanks, Bryan. I’ll conclude our comments by reviewing our year-to-date performance versus our annual targets starting on Slide 12.

After the first nine months of the year average availability was 96%. As mentioned, we are on track to hit our 95% target.

Our sustaining CapEx was $46 million year-to-date compared to the $80 million revised annual target. We reported $161 million in operating and maintenance expenses after nine months compared to $215 million to $240 million target.

Adjusted funds from operations is at $272 million year-to-date and we remain on track to generate AFFO near the midpoint of the revised annual target range of $340 million to $385 million. To conclude, Slide 13 shows our growth targets for 2017.

We completed the construction of the Bloom Wind project ahead of schedule and with construction costs below budget. Our other growth target is the execution of contracts for the output of two new wind developments.

As mentioned, we executed a 12-year contract with Morgan Stanley for our New Frontier Wind and progress is being made on our other U.S. development sites.

In Alberta we continue to wait for the outcome of the first call under the Renewable Electricity Program with an announcement of the successful bidders expected before year end. I’ll now turn the call back over to Randy.

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

Yes. Good morning, everyone.

Maybe first to start off on the North Carolina plans; Southport and Roxboro. Are there any potential other uses for these facilities post 2021 or should the expectation be that they could be decommissioned then?

We continue to look for other basically fuel sources associated with those facilities. Serving Duke Energy is likely the only practical utilization of those facilities.

And I think as we’ve said before, one of our difficulties and awkward elements around dealing with Duke is that we’re precluded from commencing negotiations until two years before the contract expires. So we continue to work to find ways to keep those facilities open.

But as obviously our disclosure indicated, with the prospect of potentially other investment to reduce emissions, it’s looking increasingly likely that those facilities may not operate post 2022.

All right, that’s helpful. And then moving closer to Alberta, there’s – you’re sitting on the number of various working groups regarding the design beyond 2021.

Can you just comment on how the working groups are proceeding and whether or not, I guess, these strong models for the market design are coming together as you would have originally anticipated?

Certainly, and I think we’ve commented on it in the past, there’s a lot of diverse views going into the working groups. And Hazel has constructed them so that they do get wide range of views.

From our perspective, they’re moving forward as one would have expected. And certainly the Hazel continues to look at the process and modifies elements as it goes forward all with the view of meeting its schedule of having the answers by the middle of next year and we believe that they continue to be on target.

All right. Thank you.

I’ll hope back in the queue.

Yes, thanks. Good morning, guys.

I’m wondering if you guys could just give your updated thoughts on the U.S. wind market.

I know you guys have primarily pre-qualified projects by way of investing in transformers. And I’m wondering what you think about potential glut of turbines in that market as 2020 approaches.

Actually we’re seeing, certainly, there is more and more, I’ll say, excess capacity in the turbine market and we are starting to see what we believe to be is a bit softer pricing. As you move forward through 2020, we’d expect that – on our post 2020 you may well see even softer prices associated with the turbine manufacturers.

Okay. Great.

That’s helpful. And then just wondering if you can provide any color on how the tax finance – the tax equity financing arrangements are going for New Frontier, I guess, given kind of uncertainty in the tax backdrop in the U.S.?

Yes. So we’re commencing that process now.

We have seen some potential tax equity investors stepping down and some of those are on the insurance side just given the high costs of some of the weather related issues down the U.S., but we’re still seeing strong demand from other entities. So we have a shortlist, we’re commencing meetings in soliciting bids.

And we’ll be looking to getting the tax equity investor in place in the first half of next year.

Okay. Great.

Thank you. That’s all I had for now, I’ll get back in the queue.

Hey. Good morning, guys.

Just back to Roxboro and Southport. Can you just remind us roughly how much EBITDA those two plants are generating today?

And given these assets relatively small and non-core, just your thoughts on potentially selling those assets earlier and redeploying into longer life assets.

Those assets are typically generating in the range of $15 million to $16 million of EBITDA. So as you say Pat, it is a very small percentage of our overall EBITDA.

We’re open to the possibility of potentially selling those assets, and then Duke maybe a potential buyer as an example. But in parallel to that as Brian mentioned, we are looking at things we can do on those facilities to potentially run them past 2021.

Okay. And then just moving over to Decatur just on the noise with the impairment charge; can you just remind us what the cash tax horizon for U.S.

operations looks like now with Decatur and once New Frontier hopefully comes online?

Yes. So from a tax perspective we don’t expect to be cash taxable in the U.S.

until the latter part of the next decade. But a lot of that’s of course driven by the capability of being able to use the net operating losses, as well as the step up on the purchase price for Decatur.

So, yes, the cash tax horizon is quite a result.

Okay. Great.

And one last housekeeping item and then I’ll jump back in the queue. Just on the EBITDA guidance for Decatur is still at $60 million.

The Canadian dollar has strengthened a few pennies since April. Is it just rounding or you found other operating cost savings now that you’ve been running the plant here for a few months?

So I would say that we have found some operating savings on operating the plant in relative to our expectations in the business case. So it is performing ahead of expectations.

As far as the exchange rates concerned, the change is affecting the revenue receiving but we’re seeing offsetting gains from our U.S. private placement debt from the exchange rates.

So generally as an organization overall we’re hedged to FX for all enhancing purposes.

All right, I got it. I’ll jump back in the queue, guys.

Thanks.

Thanks. Good morning.

A couple of questions on Alberta. Can you confirm whether you’re qualified for Alberta currently for renewal program?

Yes, yes, we can confirm that we have qualified.

Okay, that’s great. And then I also wanted to touch base on more specific operations.

And looks like you’ve been running Clover Bar peaking facilities in Q3. Was that – did you see peak pricing come back to Alberta?

Was that something else going on maybe just on the gas cycle side? Can you provide a little bit more color on that?

Yes. So there’s a number of factors that come into play with the gas-fired units we have in Alberta.

So the first thing that’s happened is the carbon compliance costs have gone up relative to last year. So that’s increased the variable cost of coal units.

At the same time, particularly in Q3 we’ve seen very low natural gas prices in Alberta, a lot of it due to restrictions in terms of maintenance and the main line being able to move gas to the East. So those are very low gas prices have dropped our gas-fired units lower in merit order.

And in fact we have seen periods where our peaking units, Clover Bar, are lower variable cost as a coal fleet, and so have been dispatched. The other thing we’ve seen happen is, as you mentioned, there’s volatility starting to come back.

We’ve experienced a few hours of our pricing up at $999 range in Alberta and that’s due to the strong load growth we’ve seen so far in 2017. And so, yes, there we’re starting to see volatility start to creep back which of course allows Clover Bar to capture those the benefit of those price lights.

Okay. And then another question, just maybe some of those comments you mentioned, Bryan.

Is there a change in any one of your view in coal to gas conversions in terms of timing for Gen one and two?

Not yet. Certainly, we keep a close eye on what forward gas prices are doing.

We have seen forward gas prices come down but probably not to the level that it would change our perspective on the timing of coal to gas conversion at this point.

Okay. All right.

Great. Thanks.

Good morning. A quick question on Decatur.

Given that this is sort of one of the first quarter you’ve seen a bigger impact, I know it’s a tolling agreement maybe you can just help us guide to were maybe EBITDA was in the quarter and seasonality on that.

Yes. So, yes, basically our EBITDA for the quarter for Decatur is around CAD27 million.

Okay.

And that’s in Canadian dollars.

Okay. And then just going back to Alberta and your comment about the volatility.

I’m just wondering where current prices are, whether you’re seeing volatility in terms of where we might see Q3 to Q4 realized pricing and portfolio optimization revenue trend. Do you think they’d be kind of flat or do you think there’s opportunity to go higher in Q4 versus Q3?

I believe there is some opportunity to increase on portfolio optimization in Q4, particularly if we continue to see the low growth continue through the balance of the year. Certainly when we look forward to Q1 of 2018 and Q2, that’s where we see a number of factors will be coming into play.

There’s been announced retirements of two major coal facilities, one retired, one mothballed in Sundance one and two. Also January 1 we expect the new carbon compliance costs from the provincial government to come into effect which will put upward pressure on prices in the $10 megawatt hour range.

Okay. And then when you think the upper trajectory, do you guys see that sort of a step function in the beginning of 2018 or do you see it as sort of rise that people figure out how they’re going to manage their carbon credits in different strategies?

We believe will see a step function starting in January 2018 due to those two coal retirements I referred to, as well as a new carbon tax taken effect. The other potential step we’ll see will be the start of Q2 2018.

At that point we expect that trends out there will have offer control over Sundance three to six with determination of the PPA on those units. We expect they’ll start strategically getting those units which will increase prices and volatility in the Alberta market compared to the Balancing Pool which is intended to dissipate those assets in at variable cost.

Okay. That makes sense.

So maybe just going back to the portfolio optimization revenue, you guys didn’t really narrow the guidance, there’s only one quarter left and you’re still fairly widely seeing the midpoint. What would maybe make the swings out of the largely the commercial portfolio in Alberta that you guys maybe just taking a cautious approach widening the guidance?

That’s a good question. Certainly, if – it’s something that we certainly could have done is look to narrow the guidance, but we didn’t specifically put our minds to that.

Okay.

So, yes. And the biggest factor of course we’ll see in Q4 is the portfolio optimization.

There are opportunities in Q4 that we didn’t realize, but also how our wind facilities perform in Q4 2017.

All right. Thanks for taking the question.

I appreciate it.

Thank you. Good morning, guys.

The question really relates to the development portfolio. And when we look at your cash flows in just the access to capital markets that you had over the last year and more, you’ve got a lot of flexibility?

And then how do you think about just where you can allocate capital and how many more frontiers do you have sort of in the hopper? Obviously, the REP is probably the first thing that comes before you really get any news on that.

But how quickly do you think you could deploy capital and just other development opportunities?

Yes. So New Frontier is underway.

But, of course, one of the elements of the U.S. wind projects we always keep in mind is once they reach COD we will have a tax equity investor coming in typically around two-thirds of the capital investment.

So not a lot of capital requirement on that project. We do have a pipeline of five to six other wind projects in the U.S.

that are continually getting closer to reaching final notice to proceed, but again those are relatively light on the capital requirement basis when we look at the fact that they’ll have tax equity investors. When we look at it, we’re successful in the Alberta wind procurement.

That will be a bigger investment for us, but again, COD will be towards the end of 2019. So the capital requirements will be spread out over the next couple of years.

So having said all of that, we’re very well positioned in terms of if the right opportunity came along from an acquisition perspective, given we’re generating over $200 million of discretionary cash flow per year. Certainly, we would be able to look at funding or financing those opportunities no problem with they were to come along.

Okay. That’s very helpful.

And then maybe just a follow-up question and it’s really on both sides of funding. So when you look at the tax equity market, if you could just give us any color on back to your pricing of tax equity and how that’s changed over time, is it more favorable to you or less favorable to you?

And then on the other side of it on off-take; it seems like there’s an increase in degree of sophistication among off-takers, but there’s also a lot more people seeking off-take from an industrial standpoint.

Yes.

So maybe just some reference and color on your perspective of those things.

Yes, certainly. So on the tax equity front, we’ve seen a continual tightening of the returns required from tax equity investors, so certainly that’s to our benefit.

And even though as I mentioned earlier, we’ve had some players step aside we’re still seeing increasing competition overall, and continual downward pressure on the returns in tax equity investors are willing to move forward on. So that plays favorably for us.

On the off-take side, we’ve actually flipped things around and New Frontier was the first example where we actually went out to the market and we’re in a process to see the willingness to pay on off-takes, and we’re seeing a lot more of the financial institutions in the U.S. stepping up and competing for that business.

So that also is moving in a favorable direction for the pipeline that we’re developing in the U.S.

Okay. That’s great.

Thank you.

Hi. Good morning.

Maybe just a quick question on your updated hedge book. Can you speak to the rationale behind the most recent changes, in particular in 2018 and 2020?

And I’m wondering if you saw value in the forward pricing at the short end of the curve, which you decided to lock in, or in 2020 if there was a settling of lower priced hedges, or if you had an additional open capacity. Just wondering what the factors were when you made those decisions.

Yes. So certainly for 2018 we’ve been seeing our forward pricing that is probably a little bit below where we think things will settle.

But generally felt it prudent to take the opportunity to reduce or increase our hedge percentage in that year. As I mentioned going through the slides, we still have a lot of capacity that can benefit from uptick in several slot prices in 2018 with 240 megawatt at Clover Bar or 190 megawatt share of Joffre and also the Halkirk Wind facility.

So we still feel we’re in a great position to capture the benefit of some of the bullish factors we’ve seen and start to materialize for 2018. For 2020, look, in terms of selling forward we’re a lot more cautious there given the higher than anticipated demand growth and what we’re seeing potentially transpire on the older coal facilities and the announcements on Sundance one and two, we’re quite bullish on 2020, and that is a factor that plays into our decision whether to continue to reduce length in that year.

Avery, you still there?

Yes. Those were my questions.

Thank you.

Yes.

Okay. Next question please.

If I can just follow-up first on the hedging side of things, is there any material change in the length for 2018 in the trading book? I guess, I’m just trying to make sure that you didn’t swap length into the hedge book from the trading book.

Not sure I quite follow the question, Robert. So like the percentage hedge that we showed there that’s the percentage of the length from our baseload facilities in Alberta.

Right.

Yes, coal assets in Shepard and part of Joffre facility. So that’s sort of a constant number.

And then it’s just a question of how much of we – of that – of those megawatts have we sold forward. So, yes, there’s nothing moving in and out of different categories.

Okay. I just – so to put differently you’re above plus $20 million on the year that you’re calling hedging, and I just want to make sure on the proprietary trading book they didn’t get along an equal amount.

No. No.

Okay. Just following up on the tax equity side, it sounds like the tax equity trends are still good even though as you mentioned some of them stepped away.

But is the New Frontier power contract contingent you achieving acceptable tax equity financing?

No, no. But we don’t view that as a large risk given in any stretch, just given the degree of interest in preliminary indications of where we’ll be able to access that funding.

Okay. And then maybe just to finish if the small delta on the off-coal payment, but I think you’ve booked $60 million in the quarter.

The expected payment was something a little over $52 million. And maybe the larger question is was there a change in the agreement and if there was are there any other change in terms that we should be aware of?

No, there was not a change in the agreement. As you’ve seen in the agreement, there was a provision in there for an audit and the government has gone through an audit process, and we are discussing a couple of elements.

We believe that we will be ultimately receiving the $52.4 million.

Okay. So that’s just being held back for the time being?

Yes.

Okay. That’s great.

Thanks very much.

Thanks. Just a couple.

First on the wind performance; can you just comment on performance across the segment? It looks like the Ontario wind facilities were a little bit weak and I’m just wondering if there’s anything specific there.

And then Bloom actually looked very strong. So if there’s anything specific that stood out there just help me out there.

So for the most part those are just normal fluctuations we’re seeing quarter-to-quarter. There we did have some slight curtailments at PDN just some outage in the – around the [indiscernible] permitting, but it’s – that wasn’t that material.

So for the most part it’s just normal variances in the wind.

Okay. Is there any carryover from the curtailment in Q4 so far or was that entirely in Q3?

It’s Q3.

Okay. And then just from a higher level perspective.

If you think about future potential acquisitions, you think there’s more opportunity on, let’s say, the organic side in the wind development pipeline or on the M&A side potentially add additional gas – contracted gas assets just in the near-term if you’re seeing what’s out there and available in the market. Some thought there.

So I think as Bryan had commented on, we see the U.S. markets as it relates to the opportunity to hedge new projects to continue to be a quite positive, and likewise the tax equity side.

So we see – certainly as we alluded to continued success in developing wind farms in the U.S. to the June of next year probably would be expecting that target to be very similar to this year.

On the M&A side, again, continue to see some activity, continue to believe we are competitive. If you look at sort of the number of transactions we would expect that there would be more new developments versus actual acquisition of natural gas facilities.

And have you looked at all of those – entering even new markets going outside of Canada, U.S. to pursue opportunities that may exist elsewhere or just point to that seem like something that’s more of a remote possibility?

That would certainly be a remote possibility. And actually at this point in time I would say that you wouldn’t expect to hear anything from us in terms of venturing outside of North America.

The combination of what we see on the development side in Alberta, in the U.S. market and potentially what might be involving in British Columbia, in addition to all the prospect of natural gas acquisitions across North America, we see that within North American strategy should definitely fulfill our growth expectations.

Great. Okay.

Thanks.

Okay. Thank you for your questions.

Please mark your calendars for our Annual Investor Day event which will be held on the morning of December the 7th in Toronto. More details on the event will be announced shortly.

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