Welcome to Capital Power's Third Quarter 2018 Results Conference Call. At this time, all participants are in a listen only mode. Following the presentation, the conference call will be opened for questions. This call is being recorded today, October 29, 2018. I will now turn the call over to Mr.
Randy Ma, Director of Investor Relations. Please go ahead.
Good morning, and thank you for joining us today to review Capital Power's Q3 2018 results, which were released earlier this morning. The financial results and the presentation for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vazjo, President and CEO and Brian DeNeve, Senior Vice President and CFO. We will start with opening comments and then open 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 analysis made by the company.
Actual results could differ materially from the company's expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward looking information on Slide 2. In today's presentation, we will be referring to various non GAAP financial measures as noted on Slide 3. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore, are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement the GAAP measures, which are provided in the analysis of the company's results from management's perspective.
Reconciliations of these non GAAP financial measures can be found in our Q3 2018 MD and A. I'll now turn the call over to Brian Fazio for his remarks starting on Slide 4.
Thanks, Randy, and good morning. I'll start off by reviewing one of the highlights of the Q3. On September 6, we announced an agreement with Oaktree Capital Management to acquire the 580 Megawatt contracted Arlington Valley Gas Facility in Arizona for US300 million dollars The acquisition has the following strategic benefits. 1st, it provides immediate accretion with a 5 year average accretion of $0.22 or 6% on AFFO per share and $0.03 or 2% to earnings per share. 2nd, Arlington strengthens our contracted cash flow profile.
The facility is contracted until 2025 with a high probability of recontracting as confirmed through 3rd party assessments. We are also pursuing additional contracts for the output generated in the non summer toll months. 3rd, Arlington is a key addition to our U. S. Growth plans.
It's a well positioned asset in the attractive desert Southwest power market. And finally, Arlington provides geographic diversification outside of our core market of Alberta. Turning to Slide 5. The Arlington acquisition will initially be financed utilizing our credit facilities followed by permanent debt financing to take place at a later date. Given our existing balance sheet capacity, there is no need to issue equity.
We expect the closing of the acquisition to be completed before the end of this year. Overall, the acquisition is a low risk, long term cash generating investment, which provides an important platform for further potential growth in the desert Southwest. Moving to Slide 6, I'll briefly touch on the Alberta power market and its positive outlook. In the Q3 2018, the average spot price was $54 per megawatt hour, which is more than double the $25 per megawatt hour spot price in the Q3 of 2017. The forward prices for the remainder of 2018 and the full year 2019 to 2021 continue to reflect the positive dynamics in the market with prices around $50 and above.
Current demand growth of 3% to 4% in the provinces contributed to the upward trend for both winter and summer peak periods. As depicted in the Alberta peak demand chart, on August 10, a new record for summer peak demand of 11,169 Megawatts was recorded. We continue to have a positive outlook for the Alberta power market. And with our diverse fleet of assets in the province, we are well positioned to capture value. I'll now turn the call over to Brian DeNeve.
Thanks, Brian. I'll start off by providing an update on our Alberta commercial portfolio positions as shown in Slide 7. There have been only minor changes to our commercial hedging profile for 2019 to 2021 since the Q2 of 2018. For 2019, we are 55% hedged at an average contract price in the low $50 per megawatt hour range. For 2020, we're 22% hedged at an average contract price in the low $50 per megawatt hour range.
And for 2021, we are 4% hedged at an average contract price in the mid-fifty dollars per range. This compares to current average forward prices of $56 for 20.19, dollars 49 for 20.20 dollars 48 for 20.21. We continue to benefit from having nearly 500 megawatts of gas peaking in wind to capture the upside from low natural gas prices, higher power prices and price volatility. Turning to Slide 8. In the Q3, we had excellent operating performance with average facility availability of 98%.
This contributed to solid financial results in the quarter that exceeded management's expectations. We generated 150 $6,000,000 in adjusted funds from operations, which is the highest AFFO quarter since Q2 2015 when comparative information was first reported for AFFO. On a year to date basis, we have generated $317,000,000 in AFFO, which accounts for 83 percent of the $380,000,000 midpoint of the guidance range. Despite the strong year to date results, we are maintaining our guidance and continue to be on track to achieve full year AFFO above the midpoint of our $360,000,000 to $400,000,000 annual guidance range. Our outlook for Q4 2018 will include the impacts from major planned outages at Genesee III indicator.
We also expect sustaining CapEx will be higher compared to Q4 2017. Slide 9 shows our Q3 financial performance compared to the Q3 of 2017. Revenues and other income were $389,000,000 up 12% year over year. Adjusted EBITDA before unrealized changes in fair values was $173,000,000 up 7% from the Q3 of 2017. The increase was primarily due to strong results in the Alberta contracted facilities segment from a higher rolling average pool price that benefited availability incentive and excess energy revenues.
Normalized earnings of $0.35 per share were up 25% compared to $0.28 in the Q3 of 2017. As mentioned, we generated strong adjusted funds from operations of $156,000,000 which was up 16% year over year. The FFO on a per share basis was $1.52 compared to $1.30 in the Q3 of 2017. Turning to Slide 10, which shows our year to date financial results compared to the same period in 2017. Revenues and other income were $1,100,000,000 up 20% from 2017.
Adjusted EBITDA before unrealized changes in fair value was $547,000,000 up 30% primarily due to the assets acquired and developed in the Q2 of 2017. After 9 months, we reported normalized earnings of $0.87 per share, which is similar to the $0.88 in 2017. Adjusted funds from operations of $317,000,000 was 19% higher than the $267,000,000 in 2017. And AFFO on a per share basis was $3.07 up 15% compared to $2.68 in the 1st 9 months of 2017. Overall, year to date performance is reflecting double digit increase in revenues, EBITDA, AFFO and AFFO per share.
I will now turn the call back to Brian.
Thanks, Brian. I'll conclude our comments by providing a status update on our year to date progress versus our 2018 annual operational and financial targets as shown on Slide 11. In the 1st 9 months, average facility availability was 96%, slightly ahead of our 95% annual target, but we expect to be on track with our annual target. Our sustaining capital expenditures is currently $54,000,000 and we expect full year results will be slightly higher than the CAD 85 1,000,000 target. We reported CAD177 1,000,000 in facility operating and maintenance expense versus the $230,000,000 to $250,000,000 annual target.
We are on track to meet the full year target. We generated $317,000,000 in AFFO in the 1st 9 months compared to the $360,000,000 to $400,000,000 annual target range. As Brian mentioned, we continue to expect our 2018 AFFO to be above the midpoint of the range. Slide 12 outlines our construction and development targets for 2018. We currently have 2 wind projects under construction.
For New Frontier, we are on target for completing the project within its $182,000,000 budget and for a COD in December of this year. For Whitla Wind, the project received AUC approval in August and we've commenced physical construction of the project. The budget is $315,000,000 to $325,000,000 with the COD expected in the Q4 of 2019. On the development side, our goal is to execute contracts for the output of 1 to 3 wind projects. Earlier this year, we executed a contract for Cardinal Point Wind in Illinois, and we are targeting commercial operations in March of 2020.
We have a strong pipeline of growth opportunities in both Canada and the U. S, and we continue to make progress wind development opportunities to create value and strengthen our contracted cash flow profile. I'll now turn the call back over to Randy.
Okay. Thanks, Brian. Operator, we're ready to start the Q and A session.
Thank you. We will now begin the question and answer session. The first question comes from David Quezada with Raymond James. Please go ahead.
Thanks. Good morning, guys. My first question here, just on the upcoming midterm elections in the U. S, are there any specific jurisdictions that you're keeping an eye on or any potential impact that you could foresee there?
Generally, we're watching, of course, the jurisdictions that we are have existing operations in. And we don't see that there'll be any by state any significant changes that will differing trends in the U. S. Towards some the Republicans on one hand having certain approaches to dealing with emissions, etcetera, while the Democrats have sort of a perspective on the other side of the spectrum. There may be some broader implications on a national basis as opposed to simply on a state basis, but we are watching it quite closely.
Okay. That's helpful. Thank you. And I guess just to follow that up on the Alberta side with the election next year, any thoughts or if you had any discussions with the UCP if they potentially come in power and any changes they might make to the power market after that election?
So our general expectation is that the regardless of the outcome of the election, we don't anticipate that it will have substantive changes to Capital Power's operations in the province.
The next question comes from Rob Hope with Scotiabank.
Good morning, everyone. Maybe just in terms of the Alberta coal units, just given the continued softness in the market there, just want to get a sense of how much gas you've been able to put through your coal units and whether there's been any change in your thinking on long term gas supply to those units as well as the conversion to gas ultimately?
So I'll speak to the longer term expectations around our evolution of coal to natural gas, and Brian will speak to the shorter term, so what we've been did in the Q3. So on a broader basis, we continue to look at the right time to take various steps to move our coal plants to enable them to coal fire more and more natural gas. As you may recall, we had announced that we are supporting a large natural gas pipe coming to the facility. That was in the end of 2019. We've since updated that due to construction timing and that's moved to early 2020.
And again, we continue to look at the right time to make the next levels of investment. The next significant one would be actually putting in the, I'd say, the plumbing to fully accept that natural gas capacity to the units, and we're looking at appropriate timing around that. We generally haven't changed our perspective or our approach and are looking to optimally make those investments that lead to the greatest economics associated with the coal firing of natural gas to coal and ultimately at some point converting the units fully to natural gas. And so just
in Q3 of 2018, we continue to see quite significant volatility in actual natural gas prices, number of days where the average price settled below $1 a GJ. During those periods, we're able to have natural gas comprise approximately 20% of our fuel input to our coal units, which of course we optimize when those opportunities present itself. We foresee that those opportunities continuing to be there over the next year or 2, just given where forward gas prices are.
Okay. I appreciate the color there. And then just taking a look at your 2018 guidance, just want to get a sense of what the moving parts are there. In the MD and A, you said that the quarter was above your expectations similar to Q2. And yet we're still pointing towards the upper end of the guidance.
Are we more towards the upper end of the guidance? Or are you look or
are there
other offsetting factors there?
We certainly are pushing more towards the upper end of the guidance. The we are being mindful of the fact that one of the factors we have to keep in mind is Arlington will close at the end of November. The certainly, the December, the revenue isn't that large in that facility given the toll is a summer toll. So we're taking that into account when we look forward to Q4. We're also mindful of the fact that we have a couple more outages in Q4.
One is just wrapped up at Genesee III and we have one at Decatur. So those are also elements. But certainly, at a 30,000 foot level, we would see that moving further up towards the top end of the guidance top end of the range, sorry.
All right. Thank you.
The next question comes from Mark Jarvi with CIBC.
Good morning. I wanted to touch base on the Alberta contracted segment. There was a more significant increase in adjusted EBITDA like plus $13,000,000 year over year versus the increase in the revenue. Maybe you can just help us understand why you got a bit more of an uplift on the EBITDA just versus the revenue? I know availability incentives were strong, but maybe you can provide some more color there.
Yes. I think one of the factors contributing to that is being able to take advantage of low natural gas prices. So certainly, that's reducing our fuel cost and increasing EBITDA relative to the revenue we're seeing.
Would that be the primary factor or is there anything else kind of impacting that segment?
Yes. The other factor we would see is just is the availability of the units. So very strong availability means that we're getting higher availability incentive payments than what would be on an expected basis during the period.
Okay.
And then I'm just wondering if you guys can comment, you talked about closing of Arlington in November. When do you guys think of in place the permanent financing, the debt? You also do have some 2019 maturities. So just wondering what you guys are thinking in terms of accessing the debt markets and timing for that?
With the Arlington acquisition, we have moved forward our timeframe on going to the debt market. So very, very possible we'll be coming to market in Q4 of this year and looking for something anywhere from $250,000,000 to $400,000,000 of medium term notes.
Okay. That's helpful. And then there was some article suggesting that you guys are either completed or close to wrapping up some tax equity for New Frontier. Just wondering anything in terms of pricing for that relative to where you guys were in the market a year ago and when do you think the proceeds will come in from the tax equity for New Frontier?
Yes. So we would see the proceeds coming in shortly after commissioning of that facility, which continues on track for December of this year. And in terms of the agreement, the rate being provided to the tax equity provider is consistent with what we've seen at Bloom.
Okay. That's it for me. Thank you.
The next question comes from Ben Pham with BMO Capital Markets.
Okay. Thanks. Good morning. One couple of questions on our own tenant. You mentioned potential new growth opportunities in the Desert Southwest and Desert Southwest, sorry.
And is that does that thought process, is that around more M and A you're thinking in that region organic? And then maybe touch a little bit on the recontracting prospects. I know it's 7 years from now, but maybe supply demand and potential buyers of the power at that time.
So Ben, the in respect of the opportunities for growth, it's both from an organic perspective. We certainly with the land position that comes with it, certainly see potentially some opportunity from the solar perspective. It's a good resource. It's already part of the lands that we that came with it. We are leasing for an operating solar facility that's there.
In addition to that, on the natural gas side, there continues to be some increasing demand in the area for responsive generation, which can potentially provide for some brownfield opportunities. In addition to that, from an M and A perspective, I mean, although we've been active looking in the market for a considerable period of time, and in fact, we had a business development office in Phoenix for a couple of years. There's you certainly understand the market much better if you have assets there and you're looking at what's happening to prices and the dynamics on a day to day basis. So certainly can provide, I'll say, a better opportunity and I'd say perhaps even a lower risk opportunity in respect of M and A activities.
And the recontracting side of things?
So one of the things that in respect of Arlington is as the market has evolved, particularly with renewables coming into the market quite significantly, Different assets have been utilized in different ways. And obviously, with the nature of the contract that's there, what's happening is that the you're seeing a significant summer peak. And the expectation is the appropriate economic approach to keeping costs down is to continue with that kind of activity of contracting summer peak from reliable natural gas facilities. And when we went through the process and had 3rd party advice and, of course, analyzed it ourselves, we saw that, that actual approach is the appropriate approach and certainly should result in that facility being recontracted, if not once, twice again. So just see in the longer term that it's got a very, very high probability of being recontracted based on where it is in the market today and a continuation of providing that kind of energy to serve the summer peak.
Okay. So you don't see nat gas playing out the same way you're seeing California where renewables ramping up, vive gas is still there, but maybe not as strong as some folks have been expecting?
No, we don't see that playing out the same.
Okay. And then maybe one more thing. Can I ask on the M and A side? I understand the angle on renewables. On the gas side, it seems like you've been looking at more in the 5 to 7 year contracted context and then look to re contract later on.
So I just I want to clarify capacity payment market. Is that still merchant like cash flows for you guys when you think about contracts?
So that, of course, depends on the term. So if you're looking at, say, capacity payments in Alberta, which are expected to be 1 year, we wouldn't be considering those as being contracted. In the Arlington case, we're looking at capacity payments that or the term of capacity arrangement for the non summer period to be equivalent in length to what the contracts are today, and we would consider that long term.
So What about like New England or PJM for your capacity payment? Is that still in the merchant bucket to your
Yes, in all likelihood. We look at some of the rating agency considerations when they look at it. And they're typically you need to be sort of in the 5 year ish range to be considering something contracted.
All right. Thanks a lot, Brian. Thanks, everybody.
The next question comes from Andrew Kuske with Credit Suisse.
Thank you. Good morning. Question partly relates to Slide 12 in your deck and just how you've lined up the construction of really 3 major wind projects coming up over the next few years. How do you think about just your construction group? How many projects you can actually handle?
And is this really a purposeful dovetailing that you've maxed out the capacity of the group? Or is there more that could be done?
Actually, Andrew, it's worked out extremely well in terms of how these three projects have come together because as you can see from the timing, they are spread out over time and that allows us to focus resources, particular resources such as procurement at, again, particular points in time and our construction capability. So it actually has helped in terms of spreading our capacity out. We clearly would be able to take on 1 or 2 wind projects in the nearer term on top of these 3.
Okay, that's helpful. And then maybe just a little bit different, Lee, if we look in Ontario, you've got a project, the North Dumfries project. It's an interesting load pocket. How do you think about the potential for that project? Where are you in the process?
And what kind of framework are you looking for in the province of Ontario?
So we've got a number of natural gas opportunities. We've got, I'll call them, greenfield opportunities. We keep them on a low cost basis available. We've got them in British Columbia. We've got them in Arizona.
We've got them in Ontario. And those are basically expected at some point in time may become a contracted facility depending on supply demand balance and whatever else happens in the jurisdiction. So when we look specifically at Ontario and certainly with the change in government and some of the policies, there may well be opportunities for further natural gas investment in Ontario in, I would say, the midterm as opposed to necessarily the immediate near term. So and again, we'll keep opportunities alive. And again, depending on where things go politically and economically with the possibility of those projects moving forward.
Okay, that's great. Thank you.
The next question comes from Patrick Kenny with National Bank Financial.
Hey, guys. So now with 2 pipelines being connected into Genesee, just wondering if you can comment on any volume commitments you might have on a combined basis in terms of what that might imply from a minimum co firing percentage at Genesee post 2020?
So I think, Pat, we're upgrading the capacity to Genesee. But yes, to the extent that, that larger pipe will be available early 2020, it does provide us the option to potentially increase coal firing not only up to a higher percentage, but potentially full conversion at the facility. Right. We have the economics to market.
Right. Is there any minimum coal firing percentage that we should assume just given any underlying contracts for those 2 pipelines?
No. No, we'll have full optionality to go coal or gas.
Okay, got it. And then just more in the near term here on the hedging policy, I mean, now that you've added Arlington and you have some other contracted cash flows coming online organically, wondering if you feel a bit more comfortable leaving the Alberta baseload position a little more open going forward? Or should we expect the current 55% hedged rate for 2019 to move up closer to fully hedged as you roll into next year kind of similar to 2018 here? Yes.
A lot of it will depend on just the liquidity in the market for 20 19 and where those forwards are trading at, Pat. Certainly, as we see forwards moving up towards $60 that subject to liquidity would result in us looking to decrease the amount of length in the Alberta market.
Got it. Okay. And then yes. Sorry, just last question here, if I could. Just curious, what was the downtime at Cloverbarn in the quarter?
Was this planned, unplanned maintenance? And then maybe just an overall comment on your expected availability and utilization rates for the peaker plants through, say, 2019?
So yes, we expect the utilization of Seabed will continue at similar levels through 2019 as what we've been seeing in 2018.
And any comment on the downtime in Q3?
Sorry, what can you repeat that part of the question, Pat?
I was just curious what was the downtime caused by? And I couldn't recall if it was planned or unplanned maintenance.
Yes. That was some unplanned maintenance in Q3 for Seabed. That has been fully addressed, and we would expect strong availability from those units on a go forward basis.
Great. Thanks,
Our next question comes from Robert Kwan with RBC Capital Markets.
Good morning. If I could just start with the quarter on Alberta Commercial. Having comparing to last year, both quarters were 100% hedged, but you did have better prices and volumes, although I guess some higher carbon costs this quarter. Were there any other moving pieces? And can you characterize the proprietary trading gas performance this year versus last year?
So in terms of the trading desk performance, there's a couple of elements moving here. When you look at our Page 12 of our MD and A, we do have a portfolio optimization. You'll see in 2018, we had $21,000,000 versus $96,000,000 in the same quarter in 2017. That line can't be looked at in isolation in terms of the performance of the trading group. What will happen is as power prices have risen in Alberta, that shifts dollars from the optimization bucket to the asset buckets above.
So when we look at 2018, our overall capture dollar per megawatt hour for the Alberta portfolio has been higher than 2017. And we project it will continue to go higher as we look forward to stronger pricing in the future. So generally, our trading desk has performed at a similar level this year as it has in previous years.
Okay. And that's included for the quarter?
Yes.
Okay. If I can turn to some comments you made on the PPA. Obviously, the wrap was a big part of the quarter, but you also talked about lower gas and the co firing. And so I'm wondering, are you is does the PPA set up that that full benefit flows to you and is not indexed? And then as well, do you also capture the change in law provision around carbon?
Is that for you? Or is that still just a pass through based on how much gas gets burned?
Yes. So the in terms of the carbon intensity, that for the most part is a benefit to the balancing pool as a buyer. Although we do have an agreement to share some of the benefits of being able to optimize the heat rate at the facility. But for the most part, the GHG benefits do flow through to the balancing pool. In terms of being able to utilize lower cost fuel with natural gas, that's predominantly to our benefit.
So the energy payments that we receive under the PPA are all based on, as you know, formulas set in advance that basically reflect a coal fired operation.
Got it. And maybe if I can just finish with Arlington, there was some talk earlier just around elections as well as things that are going on within the state. I'm just wondering how did the ballot Proposition 127 factor into your evaluation of both the acquisition but as well the re contracting potential?
So that proposition in term which would move the state to a much higher renewable percentage, the potential impact of that was something we built in and it was a scenario we considered. At the end of the day, the way we see Arizona is the economics are driven primarily around solar renewables as opposed to other renewables such as wind. So as you continue to bring on more and more solar, that certainly decreases the net demand during those hours, but doesn't address, of course, the off peak hours when the sun isn't shining. So even with that very high penetration, with it coming in the form of renewables or in the form of solar, sorry, we still see a need for natural gas to firm up in the off peak hours.
And you like how Arlington fits both location and I guess setup wise versus other gas resources then in the state?
Yes. Certainly, Arlington has a very competitive heat rate and a big part of our analysis was where it will sit in the supply curve and we're very comfortable on its efficiency relative to other units in the state.
Okay, that's great. Thank you very much.
The next question comes from Jeremy Rosenfield with Industrial Alliance Securities.
Thanks. Just a couple
of questions around renewal RFPs. First, on Saskatchewan, there was the results from the RFP last week. I'm wondering if you can just comment on that and where you sit in terms of future Saskatchewan wind RFP? And then also on the Alberta REP rounds 23, which are closed here, time lines and any expectations that you have there?
So in terms of Saskatchewan, we didn't participate. We continually monitor Saskatchewan. And as opportunities come up, particularly around land positions, we do look at them. But generally, we're not overly active in Saskatchewan. In Alberta, just one of the elements of the REP process is that if you're involved in it, you can't talk about it.
And that's very, very strict rules around that. So but could comment, certainly expect and I think it's no surprise, but we do expect it to be quite competitive both 23.
Okay. That's it for me. Thanks.
There are no more questions.
Okay. This concludes the 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 joining us today. Please mark your calendars for our upcoming annual Investor Day event, which will be held on December 6 in Toronto. More details on the event will be announced shortly. Thank you for your interest in Capital Power.
Have a good day, everyone.