Welcome to the Capital Power's fourth quarter and year-end 2017 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, February 16th, 2018. 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 fourth quarter and year-end 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'll start the call with opening comments and then open up the lines to take your questions. Before we start, I would like to remind listeners that certain statements about future events made on this call are forward-looking in nature and are based on certain assumptions and an 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 analysis of the Company's results from management's perspective. Reconciliations of these non-GAAP financial measures can be found in the Company's 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 brief recap of our success in 2017. Last year, we achieved substantial growth in our cash flow from contracted facilities and very significant diversification of our portfolio of assets. Our successes included executing on a renewable strategy that led to a successful 20-year contract with Whitla Wind in the first round of AESO's Renewable Electricity Program and commencing the New Frontier project in the United States. We also acquired five contracted thermal assets consisting of four facilities from Veresen and Decatur Energy from LS Power. Through acquisitions and the completion of Bloom Wind, we added nearly 1,300 MW to the fleet. These additions to the fleet contributed to a 13% increase in AFFO per share and increased the contracted percentage of adjusted EBITDA from 67% in 2016 to 79% in 2017.
We continued our path of annual dividend increases, first, by increasing the dividend for the fourth consecutive year with a 7% increase and second, extended our dividend growth guidance out to 2020 based on the 2017 asset additions. From our operations perspective, we exceeded our availability performance target on our plants with a 96% average availability. The trading desk continues to perform well and captured a CAD 51 per MWh realized Alberta price in 2017 compared to the CAD 22 average spot price. Finally, through various initiatives, we continue to make progress in reducing our carbon footprint. Turning to slide five with an update on the Alberta power market design. In late January, AESO released Draft One of the comprehensive market design for the new capacity market.
Overall, the design appears constructive and resembles a market structure where existing and future assets will have the opportunity to earn a return on and a return of capital without putting undue costs or risks on ratepayers. The Government Alberta commitments to treat new and existing assets equitably and to continue a level playing field have been honored as the design would provide for one auction for the contract term for both existing and new capacity resources. Draft One includes reasonable provisions regarding energy and capacity market mitigation as expected. AESO will be working through an iterative process which will see the market design finalized by July 20th, 2018. Overall, Draft One is generally consistent with our view of a properly designed capacity market for Alberta, and Capital Power is well-positioned under this market design.
On slide six, we've illustrated AESO's forecast for revenues for baseload facilities based on proposed design. The chart shows the current forward price for 2018-2020. In 2021, when the capacity market is implemented, the combined energy and capacity payment is expected to be in the CAD 55-CAD 65 per MW hour range. This range is reasonable and will allow existing and future assets an opportunity to earn a return and a return of capital. The release of Draft One and this projection provides much greater certainty about the Alberta market post-2021. Moving to slide seven. The next two rounds of the Renewable Electricity Program have been announced.
It is targeting 700 MW of new renewable capacity, including 300 MW through a process that projects to have a minimum Indigenous equity component. Two key requirements for both processes are that projects have to be new or expanded renewable electricity generation projects and require a connection to existing distribution or transmission systems. AESO expects to launch both competitions this spring, and successful bidders will be announced by the end of 2018. Capital Power is well-positioned to bid on both competitions with its Whitla 2 and Halkirk 2 projects. I'll now turn the call over to Brian.
Thanks, Brian. I'll start on slide eight with a review of our fourth quarter financial performance. Overall, financial results in the fourth quarter were in line with our expectations. This includes generating ninety-one million in adjusted funds from operations and reporting normalized earnings of twenty-four cents per share. Alberta spot prices in the fourth quarter averaged twenty-two dollars per megawatt hour, which was identical to the spot price in the fourth quarter of 2016. Our trading desk performed well and captured 109% higher realized average price of forty-six dollars per megawatt hour on our Alberta commercial assets versus the spot price. Despite the strong trading performance in the quarter, it was even stronger in the fourth quarter of 2016, when the trading desk captured a realized power price of sixty-seven dollars per megawatt hour. Slide nine shows our fourth quarter financial performance compared to the fourth quarter of 2016.
Revenues and other income were CAD 261 million, down 7% year-over-year. Adjusted EBITDA before unrealized changes in fair values was CAD 172 million, up 25% from the fourth quarter of 2016, primarily due to the additions of the Veresen assets and Decatur Energy, addition of Bloom Wind, and the off-coal compensation payment. Normalized earnings of CAD 0.24 per share were down 11% compared to CAD 0.27 in the fourth quarter of 2016. As mentioned, we generated adjusted funds from operations of CAD 91 million, which was up 63% on a year-over-year basis. Slide 10 shows the annual financial results for 2017 versus 2016. Revenue and other income were CAD 1.1 billion, down 6% from 2016.
Adjusted EBITDA before unrealized changes in fair value was CAD 592 million, up 16% for the same period in 2016, primarily to the new additions to the fleet and partially offset by lower trading gains. Normalized Earnings of CAD 1.12 per share were down 8% compared to CAD 1.22 in 2016. Adjusted Funds from Operations of CAD 363 million was 18% higher than the CAD 307 million in 2016, primarily due to the same factors described for the fourth quarter. Of note, the 2017 AFFO Payout Ratio was 44%, which is slightly below the low end of the 45%-55% annual target range. This low payout ratio supports our 7% annual dividend growth guidance. Turning to slide 11 with an outlook on the Alberta power market. Our commercial hedging profile for 2018-2020, as at the end of 2017, is shown on this slide.
For 2018, we are 87% hedged at an average contract price in the high CAD 40 per MWh range. For 2019, we're 37% hedged at an average contract price in the low CAD 50 per MWh range. For 2020, we're 20% hedged at an average contract price in the low CAD 50 per MWh range. Compared to the CAD 22 average power price in 2017, forward prices have moved significantly as depicted in the chart. The chart shows the 2018-2024 prices at three different points in time. At the end of Q3 2017, December 7th following our Investor Day, and where they currently sit today. As you can see, both 2018 and 2019 forward prices have increased from the mid CAD 40 per MWh range at the end of Q3 last year to the high CAD 50-low CAD 60 range currently.
Although we have a significant hedge position in 2018, we still have nearly 500 MW of gas peaking and wind to capture upside from the higher power prices and price volatility. There's also significant upside for 2017, where we're only 37% hedged. I'll now turn the call back to Brian.
Thanks, Brian. I'll conclude our comments by reviewing our 2017 performance versus our annual targets, starting on slide 12. We finished the year with strong average availability of 96% that exceeded our 95% target. Our sustaining CapEx of CAD 59 million was lower than the CAD 80 million target, mostly due to lower-than-expected mine capital spending, project scope reductions, and deferral of various projects into future periods. We reported CAD 224 million in operating and maintenance expense in 2017, which was in line with the CAD 215 million-CAD 240 million target. We generated CAD 363 million in adjusted funds from operations that was at the midpoint of the revised annual target range of CAD 340 million-CAD 385 million. We had an exceptional year of growth 2017.
As shown on Slide 13, we significantly exceeded our targets. We completed the construction of the Bloom Wind project ahead of schedule and with construction costs below budget. We were successful in executing long-term contracts for two new wind developments, New Frontier Wind in the U.S. and Whitla Wind in Alberta. We also acquired five thermal assets that significantly increased our contracted cash flow and provided geographic diversification. With 2017 completed, I'll briefly outline our 2018 priorities, starting with our development and construction targets on Slide 14. We currently have two wind projects under construction. This includes constructing New Frontier within CAD 182 million budget with COD in December 2018. The other is completing Whitla Wind within its CAD 315 million-CAD 325 million budget with COD in the fourth quarter of 2019. Our goal is to execute contracts for the output of one to three new wind developments.
These would potentially come from rounds two and three of the Alberta Renewable Energy Program that was highlighted earlier in our U.S. portfolio of opportunities. In the U.S., the impact from recent tax reform on our renewables portfolio and growth opportunities is not expected to be material. Therefore, we expect to continue adding wind facilities from our U.S. development pipeline. Finally, our 2018 financial target is shown on slide 15. As announced at our Investor Day in December, we are targeting CAD 360 million-CAD 400 million in AFFO for 2018. Based on our outlook, we are now expecting AFFO to be above the midpoint of the guidance range. As shown on the chart, we expect our 2018 AFFO per share to contribute to achieving a 10% compounded annual growth from 2014-2018. I'll now turn the call back to Randy.
Okay. Thanks, Brian. Operator, we're ready to start the questions and answer session.
Certainly. 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. Our first question comes from David Quezada of Raymond James.
Thanks. Morning, guys. My first question, just on the draft of the comprehensive market design, wondering if you can just provide any other color there? Are there any material items in your view that still need to be ironed out? Maybe just more broadly, how that affects your thoughts on potentially deploying capital further in Alberta in the future?
As the draft one came out, the AESO had identified a number of areas that were still open for significant discussion. I think as we've said all the way along, as long as the broad market parameters are there, a lot of the details, again, as long as they work well together within the other constructs of the market, we are somewhat indifferent. As we see it, there's really nothing in the scope of these other areas, again, as long as properly implemented, would create any significant concern for us. In terms of what it means in terms of investing further in Alberta, we continue to have the Genesee 4, 5 project on the shelf, but ready to go. I think as we've communicated consistently, one of the elements, of course, is the market design.
We're getting pretty close to saying that's a check mark. The other issue is whether or not all the constructs around the market and what impacts on the market fundamentals is there. We certainly would expect once the capacity market is put in place, that it would be an enduring market. When we would make an investment decision, part of it would be on our confidence of the market that we'll see in 2021 and 2022 is the same market that'll be there in 2025 and 2030, et cetera. That's another very significant element of consideration for us is how stable will the market design be going forward.
Okay, great. That's helpful. Thank you. Just moving to the U.S., I just appreciate the thoughts on tax reform, and you don't expect a material impact. I'm just wondering, do you feel that there's any potentially reduced appetite for tax equity financing? Does that color your view on the U.S. development portfolio at all?
There is definitely a reduction in appetite for parties to invest in tax equity. That comes through the BEAT provisions and so on, not directly because of anything that directly impacted on the renewables side. Having said that, in talking to participants in that market fairly extensively, there are some whose appetite has been eliminated, but there still exists a very robust market. We would expect that a change in expectation around their expectations of return or yield is probably moved up sort of 25 basis points-50 basis points. We see that's the impact of, I'll say, the declining appetite for tax equity in the U.S.
That's great. Thank you. I appreciate that. Sorry.
Again, that doesn't impact on our outlook for successfully completing projects.
Perfect. I appreciate that. Thank you. I'll get back in the queue.
Our next question comes from Patrick Kenny of National Bank Financial.
Yeah, good morning, guys. Just on your gas peaking capacity, can you speak to whether or not you're looking at now locking in some of the spark spread going forward? Is that part of your hedging policy?
It certainly is part of our overall hedging strategy. Just as we look at opportunities to lock in or decide to go long on the power side, we do the same thing from a spark spread perspective for the gas assets. One of the things we have seen in the market is increasing forward prices on electricity. At the same time, we have been seeing a decline in natural gas prices and an expansion of the spark spreads, which has been very beneficial to our gas-fired assets.
Could you remind us maybe within your cash flow guidance for 2018, what sort of capacity factor you've modeled in there for your peakers?
It varies by plant. Certainly it's probably about 2 times-3 times increase in output that we've seen historically.
Okay. Lastly, I know you got some time on your side here as you think about next decade and just digesting the first cut from the AESO proposed design. As you think about lower natural gas prices and this design framework, your initial thoughts on either keeping G1 and 2 on coal through next decade or converting early to gas?
I think as we've indicated all along, there are two primary drivers to when that decision on converting to natural gas plays into it. From our perspective, it's not if you convert, it's when. As we look at that, there are a couple of things that come into play. Again, with the significant parameters we continue to model at and look at it, and certainly the decline in natural gas prices would have a tendency to move conversion sooner, as opposed to pushing it out. We're actively looking at that as we speak, as well as more detailed engineering, et cetera, to refine our view and again, as we've said all along, be ready to convert at an appropriate time.
The other thing, though, that's playing into it is that there's a significant ability with these boilers to also, when you're in coal service, to also burn significant amounts of natural gas. We're looking at that quite extensively from the perspective of it's likely not going to be where you flip a switch from burning coal to burning natural gas. There may be a fairly long transition where you're increasingly burning natural gas or have that capability when natural gas prices are favorable to, again, going back to coal. We're exploring all of that as we speak. Certainly having lower natural gas prices stimulates a lot more effort in that area and certainly has the impact of moving our focus to sooner rather than later.
All right. I appreciate the color. I'll just step back in the queue.
Our next question comes from Mark Jarvi of CIBC Capital Markets.
Morning. I just want to go back to the commentary on G4 and G5, and you were saying about how you wanted to see stability in the market construct. Does that mean you wouldn't make a positive FID until you actually saw the results of the first auction?
Not necessarily. First of all, there's going to be an identification of where the AESO sees whether there's going to be a need for new capacity in the market or not. Certainly that's a very significant element as to whether or not there's room for something like G4, in particular, in the market. In addition to that, again, it'll be the regulations that we see evolve around the new market, the degree to which regulatory bodies have the ability to reach in and make, I'd say, maybe non-economic decisions, et cetera. It's sort of the robustness and the stability element of the market that we'd be looking at very hard, as would, I think, any other investor.
Okay
On an investment decision.
Going to your commentary on being above the midpoint of your guidance, maybe you can just talk a little bit about the factors. Is that solely on the movement of the forward curve, or is that reflective also on gas costs and/or market volatility?
In addition to all of what you've mentioned, although it's early in the year, there's certainly pluses and minuses that we're anticipating to take place in terms of what impacted on our original forecast. Certainly what we see happening in the power market does definitely have a lifting impact in terms of our guidance.
Okay. Maybe my last question for now would be just in terms of the announcement of the NCIB. You did have it in place before but didn't use it. Just wondering what your thoughts are in terms of your willingness to be active on it and whether or not this signals any sort of slight shift in terms of capital allocation and return of capital through a combination of buybacks and dividends going forward.
I think we've been fairly clear in suggesting that under certain circumstances, we would execute on buying back shares as a proper capital allocation move. We've come to the conclusion that actually, to the extent that we possibly can, that we would keep an NCIB in place continuously, much like a shelf prospectus there in the event that you need it. When you think of the significant cash flow we have coming into the organization, CAD 200 million a year, that can be invested in growth and the potential lumpiness of our capital expenditures going forward, it is just simply prudent to have an NCIB in place all the time. Obviously, one could take this as a signal that we don't see growth anymore in our future, and in fact, our outlook for growth is essentially unchanged from our discussions during our Investor Day.
Okay. That's it for now. Thanks, guys.
Our next question comes from Andrew Kuske of Credit Suisse.
Thank you. Good morning. The question is probably for Brian and DeNeve, and it's just on your Alberta commercial facilities. If I look at the adjusted EBITDA this quarter versus a year ago, you're down about CAD 10 million on that. Is that really just a function of the power price realizations? Because if I go back a year ago, it was CAD 67 for the quarter, and you're CAD 46 this quarter. Is that really the delta of the CAD 10, or is there something else going on there?
No, it's exactly that, Andrew. It's the success of the trading activity was very strong in Q4 2016 on the strategy, and certainly it was good this year also, or Q4 2017, but it was exceptional in Q4 2016.
When you look out and you think about just where the forward curve is and your ability to capture price and just some, and not being patronizing about it, but your historic ability to actually capture better prices than the market on average, what do you think that optimization number would be? For that whole group, what would be sort of, quote-unquote, normalized?
That's a really good question. Certainly, if you look historically, we've captured a significant percentage greater than the average settled spot price. Certainly, it was very healthy as we went through the downturn because we had sold forward through that period, a large part of our output. Yeah, as we roll forward, we expect we'll still continue to be able to capture a healthy percentage above the average spot.
Okay, that's helpful. Maybe just I would change directions a little bit with my last question. When you look at sort of the balance of opportunities ahead of you, and let's say the REP rounds two and three in Alberta or U.S. development, how do you think about just the relative opportunity, because you've got opportunities on really both geographies?
Well, certainly, as we, I think, indicated in the fall that our U.S. portfolio is strong, and we had at least one project that was sort of on the rim of coming to fruition, and that situation continues. I would certainly expect that we should have something coming out of the U.S. side. When you look at what might be our competitive positioning in Alberta, we've got Whitla 2, which has many of the competitive attributes of Whitla 1, so pretty positive from that perspective. We've got Halkirk 2, which is a very strong project in and of its own right. We're also for the government split in the portfolio between the 400 and 300 and the First Nations participation. In the 300, we think we're very well-positioned for that with sort of our existing relationship with the Siksika Nation.
I think we'll be a very strong competitor in the next round, and hopefully, we'll be successful there as well.
Okay, that's great. Thank you.
Our next question comes from Jeremy Rosenfield of Industrial Alliance Securities.
Yeah, thanks. A few questions. Just first on the capacity market design, there was some wording around provisions against bilateral contracts, and I was just wondering if you had thought that that might have any impact, or if you're just watching that closely to see if that might impact how you structure or how you think about the Genesee expansion going forward.
The Genesee Expansion, and I think when you think of in terms of our partner ENMAX and the agreement that we'd have with them in terms of them taking half of our capacity, I don't believe that wording is intended to preclude contracts for differences, financial agreements. I believe that a fair amount of the concern around this capacity market and that wording is around whether you actually have a bilateral physical contract, which tends not to be that common in this market, but I don't think that that necessarily impacts on our outlook at all.
Okay, that's helpful. Second question just on the capacity market design, just in terms of the outlook for capacity payments versus energy payments specifically, and whether the outlook based on the company's internal modeling is for maybe higher energy payments and lower capacity payments or flip, or how your own internal modeling measures compare to what the ISO has done?
We're still working through modeling the detailed design that has been put forward. Preliminary indications are that our numbers are going to look similar to what the government published.
Okay, that's helpful. Maybe just a final question just on whether you're maybe concerned or worried at all that the AESO and the government might launch a large-scale hydro RFP and whether that might impact the capacity market design and pricing in the Alberta power market. Trying to read a little bit between lines of what you were saying earlier, I think, Brian, you like the growth outlook, but as long as there's no intervention from outside parties.
First of all, we've obviously had discussions with the government about what exactly are they looking for, what exactly are they thinking. It is a sincere approach by the government to see what's out there as opposed to necessarily trying to fit a particular project or initiative. There could be a whole range of different things. Obviously, in the capacity market, it wouldn't necessarily be supportive of something like a very large hydro or things of that nature. It does certainly plumb for level of interest in the overall market from that perspective. Again, they're not looking to try and fit either hydro or nuclear or anything else. It's a very broad sort of investigation. Now, let's assume that they conclude that there is something out there and launch an RFP process.
The nature of any of that, whether it's large hydro, whether it's geothermal or any sort of dispatchable renewable, is a long lead time, both in development and then permitting and then eventually power coming to the grid. I don't think you'd expect to see anything of that until, say, 2025 or after. Certainly with the growth that we're seeing in the Alberta market and what we see happening in terms of definite timing for coal plants that potentially be coming off, what it would effectively do is likely displace, say, a natural gas plant that otherwise would have been built. I think the market, given time, can certainly react to it.
Okay.
Historically, we've talked the same way in terms of transmission. If there's a specific intertie or power relationship between Alberta and B.C., and it's prescribed and public, again, that's likely not going to be in place for a number of years, and the market will react.
Okay, that's helpful. Thanks for those answers.
Once again, if you have a question, please press star, then one. Our next question comes from Robert Kwan of RBC Capital Markets.
Morning. If I can come back to your answers on the NCIB a couple of questions ago, just to make sure I'm understanding. You talked about having the NCIB outstanding at all times, and so it's kind of a strategic decision. Is that fair? I.e., isn't in response to kind of right here, right now, you're seeing your share prices being particularly attractive, and we should be expecting you to be active immediately under it?
Yeah. Robert, a lot of it comes down to, as Brian mentioned, the lumpiness we see in growth and those opportunities. There's opportunities we're evaluating and looking at as we move forward. Certainly if nothing comes to fruition and at that same time, we look at our share price and see significant value in buying back shares, that is something we'll do. Certainly where we're trading at today, absent a growth project with capital requirements, it'd be something we'd be looking at doing.
Okay. Can I maybe then just follow on that with respect to how you're looking at your shares vis-a-vis capital allocation and maybe tie it back to Whitla? Based on the numbers that you put forward, I think you're building it at about 12x EBITDA, and your stock's trading below 10x EBITDA. You've done a lot of work, actually, a lot of work here to really contract up the portfolio, get the dividend very well covered. How does the decision then work to pursue a growth project at a multiple higher than where you're trading at?
Robert, obviously, what you've described is obviously a very accurate picture. When we look at it, there's two things here. One is sort of the immediate view economically, and there's the longer view. As we've been saying, and I think that we've been pretty blunt over the last little while, that we certainly see as the Alberta market becomes clearer and as we see the contracted portfolio expanding, that we should certainly see some reaction to the market in terms of multiples and reduced yield associated with our stock. There's a bit of, I'll say, a medium-term play in here as well in terms of creating value for shareholders, which is achieving a much more positive multiples and driving down our share yield.
I think, Brian. Oh, sorry. Go ahead. Finish.
Yeah. Oh, no, I'd just add what Brian said. The other consideration on something like Whitla is there are significant tax advantages with that project, which goes into the consideration.
Okay. Maybe I don't know if that's an answer on the AFFO yield, although your own AFFO yield's pretty high. I guess what we know that the RFP wasn't a one-shot deal, and we knew that there was going to be multiple opportunities to pursue something like Whitla. Coming back, Brian, then to your statement that you expect, as things become clear, that your multiple will go higher, your stock will go higher, effectively driving your yield down. Why then not the decision to be buying back the stock today and bid Whitla into rounds two, three, four?
So Robert, are you, in terms of bidding in future rounds, two, three, four, the trade-off of that versus buying back shares today?
Yeah. Just kind of what went into the decision to decide to bid Whitla in at that level into Round one versus bidding it in a later round, using that excess cash to buy back the stock, which you're viewing as inexpensive, and you're expecting your valuation to go higher as the market becomes clearer, but therefore your yield lower?
Yeah. Well, I think part of it is, Robert, is that the capital expenditure on something like Whitla is not until 2019. Certainly when we look at cash available, I think in the lumpiness of growth we were talking about, that's more on the acquisition side. The fact that we're proceeding with Whitla doesn't preclude ability to buy back shares under the NCIB necessarily.
Okay. That's great. Thank you.
Once again, if you have a question, please press star and then one. Our next question comes from Mark Jarvi of CIBC Capital Markets.
Yeah, I just wanted to clarify one thing in terms of Whitla 2 and Halkirk 2, whether or not you're in a position to bid those into both the second and the third phase or just solely the third phase.
I think as it sits today, I think we could be in position to do either. Part of it is the decisions that we make and discussions that we have over the next number of months.
Okay. Thanks for clarifying.
This concludes the question and answer session. I would like to turn the conference back over to Mr. Mah for any closing remarks.
Okay. If there are no more questions, we will conclude our call. Thanks again for joining us today and for your interest in Capital Power. Have a good day.
This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.