Thank you for standing by. This is the conference operator. Welcome to Capital Power's Third Quarter twenty seventeen Financial Results Conference Call. At this time, all participants are in listen only mode. Following the presentation, the conference call will be opened for questions.
This call is being recorded today, October 2537. I will now turn the call over to Mr. Randy Ma, Senior Manager, Investor Relations. Please go ahead.
Good morning. Thank you for joining us today to review Capital Power's third quarter twenty seventeen 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 Vagil, President and CEO and Brian Denis, 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 two. In today's presentation, we will be referring to various non GAAP financial measures as noted on Slide number three. 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 third quarter twenty seventeen MD and A. I will now turn the call over to Brian Vazual for his remarks starting on Slide four.
Thanks, Randy, and good morning. I'll 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 twelve 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 $182,000,000 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 five. This slide compares the availability operating performance of our facilities for the third quarter of twenty seventeen and for the first nine months of the year compared to the same periods 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 plant 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 Brian Deniv. Thanks, Brian. I'll start on Slide six with a review of our third quarter financial performance. Overall, third quarter twenty seventeen financial results were consistent with our expectations. This includes generating 134,000,000 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 twenty sixteen.
Our trading desk performed well and captured a 96% higher realized average price at $49 per megawatt hour on our Alberta commercial assets versus the spot price. This was a result of our trading desk locked in higher prices in advance of the quarter. Despite the strong trading performance this quarter, it was even stronger in the third quarter of twenty sixteen when the trading desk had realized a realized power price of $70 per megawatt hour, which reflected trading gains on a material short position resulting from the termination of the Sundance PPA. Slide seven shows our third quarter financial performance compared to the third quarter of twenty sixteen. Revenues and other income were $346,000,000 down 7% year over year.
Adjusted EBITDA before unrealized changes in fair values was $161,000,000 up 34% from the third quarter of twenty sixteen, primarily due to the additions of Decatur Energy, Ferrous and 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 twenty sixteen. As mentioned, we generated adjusted funds from operations of $134,000,000 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 eight shows the financial results on a year to date basis.
Revenue and other income were $885,000,000 down 5% from 2016. Adjusted EBITDA before unrealized changes in fair value was $420,000,000 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 $272,000,000 were higher than a year ago, primarily due to the new acquisitions, the completion of Bloom Wind and 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 nine. We are recognizing pretax impairment charges of 46,000,000 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 render the facilities uneconomic once the PPAs expire in 2021. In the third quarter, we also recognized a pretax impairment charge of CAD 37,000,000 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 $86,000,000 income tax recovery recorded in Q2 twenty seventeen from the reversal of previous written down deferred tax asset more than offsets the goodwill impairment we are recognizing on Decatur for Q3 twenty seventeen. 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 this slide. For 2018, we have increased our hedges from 66% as reported in the second quarter of twenty seventeen to 86% at an average contract price in the high $40 per megawatt hour range. For 2019, we're 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, Joffrey CoGen and our Helcreek wind facility.
To conclude, I want to summarize our various financing activities completed this year to fund growth as shown in Slide 11. In total, we have raised just over $1,000,000,000 in gross proceeds. This includes $244,000,000 from a tax equity investor, Goldman Sachs, for Bloom Wind Another $183,000,000 from a common share issuance that was used to partially finance acquisition of Decatur Energy. In August, we raised $150,000,000 from a preferred share offering at a 5.75% yield. And most recently, we accessed the debt capital markets with a $450,000,000 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.
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 $46,000,000 year to date compared to the $80,000,000 revised annual target. We reported $161,000,000 in operating and maintenance expenses after nine months compared to $215,000,000 to $240,000,000 target.
Adjusted funds from operations is at $272,000,000 year to date, and we remain on track to generate AFFO near the midpoint of the revised annual target range of $340,000,000 to $385,000,000 To conclude, Slide 13 shows our growth targets for 2017. We completed the construction of the Blum 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've executed a twelve year contract with Morgan Stanley for 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 and A session.
All right. We will now begin the question and answer session. The first question comes from Robert Hope from Scotiabank.
Yes. Good morning, everyone. Maybe first to start off on the North Carolina plant, 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.
That's helpful. And then moving closer to Alberta, there's you're sitting on a 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, the straw 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 the ASO has constructed them so that they do get a wide range of views. From our perspective, they're moving forward as one would have expected. And certainly the ASO continues to look at the process and modifies elements as it goes forward all with a view of meeting its schedule of having answers by the middle of next year. And we believe that they continue to be on target.
All right. Thank you. I'll hop back in the queue.
Our next question comes from David Quezada from Raymond James.
Yes. Thanks. Good morning, guys. I'm wondering if you guys could just give your updated thoughts on The U. S.
Wind market. I I know you guys have primarily prequalified projects by way of investing in transformers. And I'm wondering what you think about a 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 to 2020, we'd expect that post 2020, you may well see even softer prices associated with 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, 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 in The U. S. But we're still seeing strong demand from other entities.
So we have a short list. We're commencing meetings and 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.
Our next question comes from Patrick Kenny from National Bank Financial.
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 are relatively small and noncore, just your thoughts on potentially selling those assets earlier and redeploying into longer life assets?
So those assets are typically generating in the range of $15,000,000 to $16,000,000 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 do maybe a potential buyer, as an example. But, you know, in in parallel to that, as Brian mentioned, we are looking at things we can do on those facilities to, potentially run them past 02/2021.
Okay. And 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 fully 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 ways out.
Okay, great. And one last housekeeping item and then I'll jump back in the queue. But just on the EBITDA guidance for Decatur, still at CAD60 million, the Canadian dollar has strengthened a few pennies since April. Is that 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 and relative to our expectations in the business case. So it is performing ahead of expectations. As far as the exchange rate is concerned, the change is affecting the revenue we're receiving, but we're seeing offsetting gains from our U. S. Private placement debt from the exchange rate.
So generally, as an organization overall, we're hedged to FX for all intents and purposes.
All right. Got it. I'll jump back in the queue, guys. Thanks.
Our next question comes from Ben Pham from BMO.
Thanks. Good morning. Couple of questions on Alberta. Can you confirm whether you if you qualify for the Alberta RP renewable program?
Yeah. We can confirm that we have qualified.
Okay. That's And then I also wanted to touch base on more specifically operations. And it 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 on the gas cycle side?
Maybe provide a little bit more color there.
Yes. So there's a number of factors that have 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 mainline being able to move gas to the East.
So those very low gas prices have dropped gas fired units lower in the merit order. And in fact, we have seen periods where our peaking units, coal rebar, are lower variable cost than the coal fleet and so have been dispatched. The other thing we've seen happen is, as you mentioned, there is volatility starting to come back. We've experienced a few hours of pricing up at the $999 range in Alberta, and that's due to the strong load growth we've seen so far in 2017. And so yes, we're starting to see volatility start to creep back, which, of course, allows Colvard Bar to capture those the benefit of those price spikes.
Okay. My only other question, maybe just some of those comments that you mentioned, Brian, has that changed in any way your view on 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 everybody. Our
next question comes from Mark Jarvi of CIBC.
Good morning. Quick question on Decatur, given this
is sort of one of
the first quarters you've seen a bigger impact. I know it's got a tolling agreement. Maybe you can just help us guide to where maybe EBITDA was in the quarter and seasonality on that?
Yes, basically, our EBITDA for the quarter for Decatur is around CAD 27,000,000. And that's in Canadian dollars.
Okay.
And then just going back to Alberta and your comment about the volatility, just wondering where current prices are and what you're seeing now in volatility in terms of where we might see Q3 into Q4 realized pricing and portfolio optimization revenues trend? Do you think it will be kind of flat? Or do think there's opportunity to go higher in Q4 versus Q3?
Believe there's some opportunity to increase on portfolio optimization in Q4, particularly if we continue to see the load growth continue through the balance of the year. Certainly, when we look forward to Q1 of twenty eighteen 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 and 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 about that upward trajectory,
you like do you guys see
that as sort of a step function in beginning of twenty eighteen? Or do you see it just a slow sort of rise as people figure out how they're going to manage their carbon credits and different strategies?
We believe we'll see a step function starting January 2018 due to those two coal retirements I referred to as well as the new carbon tax taking effect. The other potential step we'll see will be the start of Q2 twenty eighteen. At that point, we expect TransAlta will have offer control over Sundance three through six with the termination of the PPAs on those units. We expect they'll start strategically bidding those units which will increase prices and volatility in the Alberta market compared to the balancing pool, which is tended to just bid 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. It was only like one quarter left, and it was still fairly wide even though you're staying at midpoint.
What would maybe make the swings in that? Is it largely the commercial portfolio in Alberta that you guys maybe are just taking a cautious approach for why you didn't narrow 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. So yes, and the biggest factors, of course, we'll see in Q4 is the portfolio optimization. There are opportunities in Q4 that we can realize, but also how our wind facilities perform in Q4 twenty seventeen.
All right. Thanks for taking the questions. Appreciate it.
Our next question comes from Andrew Kuske from Credit Suisse.
Thank you. Good morning. The question really relates to the development portfolio and when we look at your cash flows and just the access to capital markets that you've had over the last year and more, you've got a lot of flexibility in it. How do you think about just where you can allocate capital and how many more frontiers do you have sort of in the hopper? And obviously, the rep is probably the first thing that comes before year end where you get 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'll have a tax equity investor coming in, typically around twothree 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. 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 if 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 twenty nineteen. So the capital requirements will be spread out over the next couple of years. So having said all that, we're very well positioned in terms of if the right opportunity came along from an acquisition perspective, given we're generating over $200,000,000 of discretionary cash flow per year. Certainly, we'd be able to look at funding or financing those opportunities, no problem if they were to come along.
Okay. That's very helpful. And then maybe just a follow-up question, and really on both sides of funding. So when you look at the tax equity market, if you could just give us any color on effectively pricing of tax equity and how that's changed over time? Is it more favorable to you, less favorable to you?
And then on the other side of it, on offtake, it seems like there's an increasing degree of sophistication among off takers, but there's also a lot more people seeking offtake from an industrial So maybe just some wrap around some color on your perspectives on those things.
Yes. No, 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 the 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 and tax equity investors are willing to move forward on.
So that plays favorably for us. On the offtake side, we've actually flipped things around and New Frontier was the first example where we actually went out to the market and ran a process to see the willingness to pay on offtakes. 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 U. S.
Our next question comes from Avery from TD Securities.
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 and for 2020 if there was a settling of lower priced hedges or if you added additional open capacity? Just wondering what the factors were when you made those decisions.
Yes. So certainly for 2018, we've been seeing forward pricing that is probably a little bit below where we think things will settle. But generally, 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 upward kick in settled spot prices in 2018 with the two forty megawatts Clover Bar, our 190 megawatt share of Joffrey and also the Helkirk Wind facility. So we still feel we're in a great position to capture the benefit of some of the bullish factors we're seeing start to materialize for 2018.
For 2020, the 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.
Gabriel, are still there?
Yes, those were my questions. Thank you.
Next
question comes Robert Kwan from RBC Markets.
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 show there, that's the percentage of the length from our base load facilities in Alberta, which would include the, yeah, coal assets in Shepherd and part of the Joffrey facility. So that's sort of a constant number. And then it's just a question of how much of those megawatts have we sold forward. So yes, there's nothing moving in and out of different categories.
Okay. Just want so put differently, you're about plus 20 on the year that you're calling hedging. I just want to make sure on the proprietary trading book, they didn't get long 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 have stepped away. But is the new Frontier Power contract contingent on you achieving acceptable tax equity financing?
No. No. And we don't view that as a large risk in any stretch, just given the degree of interest in preliminary indications of where we'll be able to access that funding.
Got it. And if I can just finish. It's a small delta on the off coal payment, but I think you booked $50,000,000 in the quarter. Think the expected payment was something a little over $52,000,000 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 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 $52,400,000
Okay. So that's just being held back for the time being?
Yes.
Okay. That's great. Thanks very much.
Our next question comes from Jeremy Rosenfield from Industrial Alliance Securities.
Yes, thanks. Just a couple. First on the wind performance, can you just comment on performance across the segments? It looks like the Ontario wind facilities were a little bit weak and I'm wondering if there's anything specific there. And then Bloom actually looked very strong.
So if there's anything specific that stood out there, help me out there.
Well, 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 managing the around the backfill and our 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, do you think there's more opportunity on, let's say, the organic side in the wind development pipeline or on the M and A side potentially to add additional gas contracted gas assets just in the near term if you've seen what's out there and available in the market? Some thoughts there.
So I think as Brian had commented on, we see The U. S. Markets as it relates to the opportunity to hedge new projects to continue to be 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 tune of next year, probably would be expecting the target to be very similar to this year. On the M and 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 about entering even new markets going outside of Canada U. S. To pursue opportunities that may exist elsewhere? Or at this point, does that seem like something
that is 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 evolving in British Columbia in addition to 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.
This concludes our question and answer session. I would like to turn the conference back over to Mr. Randy Ma for any closing remarks.
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 7 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.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.