Thank you for standing by. This is the conference operator. Welcome to Capital Power's third quarter 2017 financial results conference call. At this time, all participants are in listen-only mode. Following the presentation, the conference call will be open for questions. This call is being recorded today, October 25th, 2017. I will now turn the call over to Mr. Randy Mah, Senior Manager, Investor Relations. Please go ahead.
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 on 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 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 2017 MD&A. I will now turn the call over to Brian Vaasjo for his remarks, starting on slide number 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 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 CAD 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 five, 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 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, we are on track to meet our 95% plant availability target for 2017. I will now turn the call over to Bryan DeNeve.
Thanks, Brian. I will start on slide six with a review of our third-quarter financial performance. Overall, third quarter 2017 financial results were consistent with our expectations. This includes generating CAD 134 million in adjusted funds from operations and normalized earnings per share of CAD 0.28. Alberta spot prices in the third quarter averaged CAD 25 per megawatt hour, compared to CAD 18 per megawatt hour in the third quarter of 2016. Our trading desk performed well and captured a 96% higher realized average price at CAD 49 per megawatt hour on our Alberta commercial assets versus the spot price. This was the result of our trading desk locking 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 a realized power price of CAD 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 2016. Revenues and other income were CAD 346 million, down 7% year-over-year. Adjusted EBITDA before unrealized changes in fair values was CAD 161 million, up 34% from the third quarter of 2016, primarily due to the additions of Decatur Energy, Veresen assets, and Bloom Wind, which was partially offset by lower portfolio optimization contribution. Normalized earnings of CAD 0.28 per share were down 10% compared to CAD 0.31 in the third quarter of 2016.
As mentioned, we generated adjusted funds from operations of CAD 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 eight shows the financial results on a year-to-date basis. Revenue and other income were CAD 885 million, down 5% from 2016. Adjusted EBITDA before unrealized changes in fair value was CAD 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 CAD 0.88 per share were down 7% compared to CAD 0.95 in 2016. Adjusted funds from operations of CAD 272 million 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 9. We are recognizing pre-tax impairment charges of CAD 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. The 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 pre-tax impairment charge of CAD 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 CAD 86 million income tax recovery recorded in Q2 2017 from the reversal of the previous written-down deferred tax asset more than offsets the 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 this 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 CAD 40 per megawatt-hour range. For 2019, we're 45% hedged at an average contract price in the low CAD 50 per megawatt-hour range.
For 2020, we're 25% hedged at an average contract price in the low CAD 50 per megawatt-hour range. Although we have a significant hedge position in 2018, we still have the ability to capture upside from higher power prices or price volatility from our Clover Bar peaking facilities, Joffre Cogeneration, and our Halkirk 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 CAD 1 billion in gross proceeds. This includes CAD 244 million from a tax equity investor, Goldman Sachs, for Bloom Wind. Another CAD 183 million from a common share issuance that was used to partially finance acquisition of Decatur Energy. In August, we raised CAD 150 million from a preferred share offering at a 5.75% yield.
Most recently, we accessed the debt capital markets with a CAD 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.
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 CAD 46 million year to date compared to the CAD 80 million revised annual target. We reported CAD 161 million in operating and maintenance expenses after nine months compared to CAD 215 million-CAD 240 million target. Adjusted funds from operations is at CAD 272 million year to date, and we remain on track to generate AFFO near the midpoint of the revised annual target range of CAD 340 million-CAD 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've executed a 12-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, Bryan. Operator, we're ready to start the Q&A session.
All right. We will now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We will pause for a moment as callers join the queue. 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. 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. We continue to work to find ways to keep those facilities open. 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.
Right. That's helpful. Moving closer to Alberta, 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, I think we've commented on it in the past, there's a lot of diverse views going into the working groups, and the AESO 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. Certainly, the AESO 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. 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.
Yeah, thanks. 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 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. Just wondering if you can provide any color on how the tax equity financing arrangements are going for New Frontier, I guess, given kind of uncertainty in the tax backdrop in the U.S.
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. We're still seeing strong demand from other entities. We have a short list. We're commencing meetings and soliciting bids, and we'll be looking to getting a 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.
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? Given these assets are 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 CAD 15 million-CAD 16 million of EBITDA. 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. Duke may be a potential buyer, as an example. In parallel to that, as Brian mentioned, we are looking at things we can do on those facilities to potentially run them past 2021.
Maybe 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?
From a tax perspective, we don't expect to be cash taxable in the U.S. until the latter part of the next decade. A lot of that's, of course, driven by the capability of being able to use the net operating losses as well as the
The step up on the purchase price for Decatur. The cash tax horizon is quite a ways out.
Okay, great. One last housekeeping item and then I'll jump back in the queue, just on the EBITDA guidance for Decatur, still at CAD 60 million. The Canadian dollar has strengthened a few pennies since April. Is that just rounding or have you found other operating cost savings now that you've been running the plant here for a few months?
I would say that we have found some operating savings on operating the plant and relative to our expectations in the business case. It is performing ahead of expectations. As far as the exchange rate's concerned, the change is affecting the revenue we're seeing, but we're seeing offsetting gains from our U.S. private placement debt from the exchange rate. 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. A couple questions on Alberta. Can you confirm whether you've qualified for the Alberta REP renewal program?
Yeah, we can confirm that we have qualified.
Okay. That's great. I also wanted to touch base on more specifically operations and it looks like you've been running Clover Bar peaking facilities in Q3. Did you see peak pricing come back to Alberta or was that something else going on maybe on the gas cycle side? Maybe provide a little bit more color there.
Yeah. There's a number of factors that have come into play with the gas-fired units we have in Alberta. The first thing that's happened is the carbon compliance cost has gone up relative to last year. That's increased the variable cost to 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. Those very low gas prices have dropped gas-fired units lower in the merit order. In fact, we have seen periods where our peaking units, Cloverbar, are lower variable cost than the coal fleet and 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 CAD 999 range in Alberta. That's due to the strong load growth we've seen so far in 2017. Yeah, we're starting to see volatility start to creep back, which of course allows Cloverbar to capture the benefit of those price spikes.
Okay. My only other question, just maybe some of those comments that you mentioned, Bryan, does that change in any way your view on coal to gas conversions in terms of timing for Genesee 1 and 2?
Not yet. Certainly, we keep a close eye on what forward gas prices are doing. We have seen forward gas prices come down. 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.
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.
Yeah, basically our EBITDA for the quarter for Decatur is around CAD 27 million.
Okay.
That's in Canadian dollars.
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 they'll be kind of flat or do you think there's an opportunity to go higher in Q4 versus Q3?
I 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 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 1 and 2. Also January 1st, we expect the new carbon compliance costs from the provincial government to come into effect, which will put upward pressure on prices in the CAD 10 megawatt-hour range.
When you think about that upper trajectory, do you guys see that as sort of a step function in the beginning of 2018? 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 2018. At that point, we expect TransAlta will have offer control over Sundance 3 through 6 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 has tended to just bid those assets in at variable cost.
That makes sense. Maybe just going back to the portfolio optimization review. You guys didn't really narrow the guidance, even though there's only one quarter left, and you're still fairly wide even though you're staying at midpoint. What would maybe make the swing tonight? 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. It's something that we certainly could have done, is look to narrow the guidance. We didn't specifically put our minds to that. 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 2017.
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 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? Obviously, the REP is probably the first thing that comes before year-end, where you get news on that. How quickly do you think you could deploy capital into just other development opportunities?
New Frontier is underway. 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 two-thirds of the capital investment. 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. 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'll be a bigger investment for us. Again, COD will be towards the end of 2019, so the capital requirements will be spread out over the next couple of years.
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 CAD 200 million 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. Maybe just a follow-up question, really on both sides of funding. 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? On the other side of it, on offtake. It seems like there's an increasing degree of sophistication among offtakers, but there's also a lot more people seeking offtake from an industrial-
Yeah
standpoint. Maybe just some wrap around some color on your perspectives on those things.
Yeah. No, certainly. On the tax equity front, we've seen a continual tightening of the returns required from tax equity investors. Certainly, that's to our benefit. 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 that tax equity investors are willing to move forward on. That plays favorably for us. On the offtake side, we've actually flipped things around. 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. We're seeing a lot more of the financial institutions in the U.S. stepping up and competing for that business. 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.
Our next question comes from Andy He from TD Securities.
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? I'm wondering if you saw value in forward pricing at the short end of the curve, which you decided to lock in. 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.
Certainly, for 2018, we've been seeing forward pricing that is probably a little bit below where we think things will settle. 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 an upward tick in settled spot prices in 2018 with the 240 MW at Clover Bar, our 190-MW share of Joffre, and also the Halkirk Wind facility. 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, 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 1 and 2, we're quite bullish on 2020. That is a factor that plays into our decision whether to continue to reduce length in that year. Andy, are you still there?
Yeah, those were my questions. Thank you.
Okay. Next question, please.
Our next question comes from Robert Kwan from RBC Capital 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. The percentage hedge that we show there, that's the percentage of the length from our baseload facilities in Alberta-
Right
which would include the coal assets in Shepard and part of the Joffre facility. That's sort of a constant number, and then it's just a question of how much of those megawatts have we sold forward. Yeah, there's nothing moving in and out of different categories.
Okay. Put differently, you're about +20% on the year that you're calling hedging. I just wanted to make sure on the proprietary trading book, they didn't get long an equal amount.
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. Is the New Frontier Wind contract contingent on you achieving acceptable tax equity financing?
No. 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. If I can just finish. It's a small delta on the off-coal payment, but I think you booked CAD 50 million in the quarter. I think the expected payment was something a little over CAD 52 million. Maybe the larger question is, was there a change in the agreement? 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'd seen the agreement, there was a provision in there for an audit. 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 CAD 52.4 million.
Okay, that's just being held back for the time being?
Yes.
Okay. That's great. Thank you very much.
Once again, if you have a question, please press star, then one. Our next question comes from Jeremy Rosenfield from Industrial Alliance Securities.
Yeah, thanks. Just a couple. First, on the wind performance, can you just comment on performance across the segments? It looked like the Ontario wind facilities were a little bit weak, and I'm just wondering if there's anything specific there. Then Bloom actually looked very strong. If there's anything specific that stood out there, just help me out there.
Well, for the most part, those are just normal fluctuations we're seeing quarter to quarter. We did have some slight curtailments at PDN, just to managing around the bat kill and our permitting. That wasn't that material. 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. 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&A side, potentially, to add additional contracted gas assets just in the near term if you've seen what's out there and available in the market? Just some thoughts there.
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. Likewise, the tax equity side. 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&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.
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. 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 a 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 Mah 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 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.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.