Welcome to Capital Power's second quarter 2019 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, July 29th, 2019. I will now turn the call over to Mr. Randy Mah, Director of Investor Relations. Please go ahead.
Good morning. Thank you for joining us today to review Capital Power's second quarter 2019 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 Vaasjo, President and CEO, and Bryan DeNeve, Senior Vice President and CFO. We will start with the opening comments and then open up the lines to take your questions. Before we start, I would like to remind everyone 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 risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide number two.
In today's discussion, 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 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 second quarter 2019 MD&A. I'm going to now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
Thanks, Randy, good morning. Before I review the second quarter, I'd like to start off by highlighting two very significant recent developments in the Alberta and Ontario power markets. On July 24, the Alberta government concluded its electricity market review and announced its decision to stay on the existing energy-only market path rather than creating a capacity market. In its decision, the government noted that Alberta's energy-only market is a proven system that has successfully attracted investment into the province and that an energy-only market will continue to provide Albertans with a reliable supply of electricity at affordable prices. Capital Power fully supports the government's decision and believe the energy-only market has demonstrated a track record of investment, competitive pricing, and affordable and reliable power for Albertans that will continue. From an investor perspective, we believe the decision provides immediate investor certainty and confidence in Alberta's electricity market system.
We also appreciate the timely and efficient manner in which the government consulted on and reached its decision on this issue. For Capital Power, we are well-positioned to compete in an energy-only market based on our market and commodity management expertise, a young, diverse and efficient fleet of assets, and a shovel-ready pipeline of development projects for which regulatory approvals have already been received. We believe Capital Power will perform better in a capacity market. Turning to slide five. Earlier this month, the Ontario IESO announced they were canceling further work on a capacity market after considering stakeholder feedback and concerns. The Ontario IESO reviewed their long-term planning outlook over the next 10 years, expect sufficient market capacity to exist in the market if resources are reacquired when their contracts expire.
The process to recontract assets has yet to be defined, but it's likely to include a combination of bilateral contract extensions and competitive processes. Given the physical locations and services provided to the IESO, the recontracting outlook for Capital Power's three natural gas facilities, York Energy, East Windsor, and Goreway, is very positive. Turning now to the second quarter, I'll briefly recap the highlights starting on slide six. The highlight of the quarter was the acquisition of the Goreway facility, an 875 MW natural gas facility in Ontario that is contracted until 2029. The acquisition closed on June 4th, and we've had a successful integration of the asset to date. For the sixth consecutive year, we've increased the common share dividend. The 7.3% dividend increase is effective for the third-quarter dividend and represents an annualized one point or a CAD 1.92 dividend per share.
Our dividend guidance continues to call for a 7% annual increase to 2021. To finance the acquisition of Goreway and other growth, we raised CAD 625 million in gross proceeds from a private placement debt financing and common and preferred share offerings. Finally, we've committed to increasing our equity investment in C2CNT from 5% - 9%. We also have options in 2020 that allows us to increase our equity interest to 40%. C2CNT is focused on transforming captured carbon into leading-edge materials. Moving to slide seven. On June 18th, we announced plans to expand the natural gas capability at the Genesee facility. This involves transforming Genesee 1 and 2 to 100% dual-fuel optionality. The transformation of the units to 100% dual-fuel will occur during regularly scheduled maintenance outages. Genesee 2 Have 100% dual-fuel capability in mid-2020, followed by Genesee 1 in the spring of 2021.
Genesee 3 will have up to 40% gas capability at that time. The total project cost is estimated at CAD 50 million to completely transform Genesee 1 and 2 to dual-fuel capability and up to 40% gas for Genesee 3. Adjusted funds from operations is estimated to increase by CAD 10 million in 2020 and CAD 20 million in 2021. Note that the financial impact is highly dependent on carbon cost and natural gas price assumptions. The transformation of the units to dual-fuel will also further reduce greenhouse gas emissions. We are estimating a 20%-33% reduction in annual GHG emissions based on the Genesee units operating at 50%-100% of the time on natural gas compared to operating on coal alone. Turning to Slide eight, I'll review Alberta power prices.
In the second quarter, the average power price was CAD 57 per megawatt hour, slightly higher than the CAD 56 in the second quarter of 2018. In the first six months of the year, the average power price was CAD 63, which was 37% higher compared to 2018. We see a positive outlook for Alberta power prices based on current forward prices for 2019 to 2021. Forward prices are averaging CAD 60 a megawatt hour. Forward prices have trended upwards since the end of March and are up approximately 14%-24% for 2020 and 2021. I'll now turn the call over to Bryan DeNeve.
Thanks, Brian. Starting on Slide nine, financial results in the second quarter were in line with our expectations. I would characterize the second quarter as a busy quarter of maintenance activities that resulted in average facility availability of 92%. This included a major scheduled outage at Genesee 1 that lasted four days longer than planned. The longer outage and higher power prices contributed to higher net availability penalties. Revenue and other income were CAD 366 million, down 1% compared to the second quarter of 2018. Adjusted EBITDA was CAD 191 million, down 8% year-over-year. The lower adjusted EBITDA was largely driven by the major planned outage at Genesee 1, high Bloom Wind-adjusted EBITDA in 2018 due to a one-time adjustment for the renegotiation of the Bloom tax equity agreement in Q2 2018, and the disposal of K2 Wind in late 2018.
These factors were partially offset by strong performance from the Alberta commercial segment, higher environmental trading gains, and EBITDA from the Goreway and Arlington Valley acquisitions. Normalized earnings of CAD 0.14 per share was down compared to CAD 0.20 per share in the second quarter of 2018. We generated AFFO of CAD 85 million. That was up 12% year-over-year. AFFO per share was CAD 0.82, up 11% from the second quarter of 2018. Slide 10 shows our financial performance in the first half of the year compared to the same period in 2018. Revenues and other income were CAD 763 million, up 12% year-over-year. Adjusted EBITDA was CAD 393 million, up 2% compared to 2018. Normalized earnings of CAD 0.44 per share were down CAD 0.04 compared to CAD 0.48 in 2018. We continue to generate strong AFFO, including CAD 202 million in the first six months.
That was up 25% year-over-year. AFFO per share was CAD 1.97, up 27% from the same period in 2018. Turning to Slide 11, I'll provide an update on our Alberta commercial portfolio positions. As Brian mentioned, forward prices have trended upwards since the end of the first quarter, up CAD 7 and CAD 12 in 2020 and 2021, respectively. With higher forward prices, we have increased our hedging positions for 2020-2022. This includes selling forward an additional 108 MW in 2020. That increased our hedge position from 24%-41% at an average contract price in the mid-CAD 50 per MWh range. For 2021, we're at 4% hedged at an average contract price in the low CAD 60 per MWh range. For 2022, we're 9% hedged at an average contract price in the low CAD 50 per MWh range.
This compares to current average forward prices of approximately CAD 58 per MWh for 2020, CAD 60 for 2021, and CAD 55 for 2022. I will now turn the call back to Brian.
Thanks, Bryan. I'll conclude our comments on our results to date by comparing our six-month performance against our 2019 annual targets. As shown on Slide 12, our average facility availability was 94%, and we are on track to achieve the 95% annual target. Sustaining capital expenditures were CAD 40 million in the first six months, and we continue to forecast a CAD 80 million-CAD 90 million range for the full year. Adjusted EBITDA was CAD 393 million in the first half of the year, and we are forecasting to be at the high end of the CAD 870 million-CAD 920 million target. We generated CAD 202 million in AFFO in the first six months of the year, and now expect to finish the year at the top end of our CAD 485 million-CAD 535 million target range. Slide 13 outlines our development and construction targets for 2019.
We currently have two fully contracted wind projects under construction. This includes Whitla Wind in Alberta, with commercial operations targeted for the fourth quarter of this year. The budget for Whitla is CAD 315 million-CAD 325 million and is currently tracking over budget, largely due to foreign exchange impacts. We also have our Cardinal Point Wind project under construction in Illinois. The budget is CAD 289 million-CAD 301 million, with a target to begin commercial operations in March of 2020. Once completed, these two wind projects will add 350 MW of long-term contracted generation to our fleet. As we've exceeded our CAD 500 million of committed contracted growth capital in 2019, with a CAD 1 billion acquisition of the Goreway facility. To wrap up, I'll briefly talk about our sustainability reporting on slide 14.
Based on the 2019 status report from the Task Force on Climate-related Financial Disclosures, or TCFD, approximately 25% of companies disclose information that is aligned with more than five of the 11 recommended disclosures. Only 4% of companies disclosed information that is aligned with at least 10 of the 11 recommended disclosures. In February, we published our inaugural climate change disclosure, and with today's launch of our online 2018 corporate sustainability report, we met all 11 recommended disclosures. The CSR continues to be fully compliant with the internationally recognized Global Reporting Initiative standards. In the report, we outline our four sustainability targets. Constructing all new natural gas generation units to be carbon capture and/or hydrogen-ready. Reducing CO2 emissions at Genesee by 50% by 2030 from 2005 levels.
Reducing CO2 emissions by 10% and our emissions intensity by 65% in 2030 from 2005 levels, in spite of increasing our generation by 145%. Investing in carbon capture and utilization technology such as C2CNT to eventually decarbonize our natural gas generation assets. Slide 15 shows our evolution on sustainability reporting. As mentioned, we added a climate change disclosure in February that was based on TCFD recommendations. Our online 2018 corporate sustainability report is fully compliant with the internationally recognized GRI standards. In February 2020, we are planning on releasing our first integrated report that combines our annual financial, environmental, social, and governance disclosures. I'll now turn the call back over to Randy.
Thanks, Brian. Carl, ready to start the Q&A?
Certainly. 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're 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 of Scotia Capital. Please go ahead.
Good morning, everyone. Brian, I am maybe a little bit early on this, but congratulations on the retirement announcement.
Thank you very much.
If we can start off on the Alberta energy market, appreciate the comments you made in your prepared remarks. The government's been relatively high level at this point. Can you get into what else you would like to see in the energy-only market, or what changes you would like, including a potential revision of the upwards price cap?
In terms of the discussions with the Alberta government, you're quite right. They've been basically saying they're going to continue with the track of the energy-only market. As such, we expect it to normally evolve in the way that was expected to be happening. Specifically, on point to your question, we do anticipate that at some point, the cap on power prices will be raised. I can tell you that in our consultations with the government, we expressly said that that was a necessary move for continuing to stay with the energy-only market. They are definitely aware that that's part of the decision to stay with the energy-only market. By the way, if I could just comment, because I had actually misquoted myself in my earlier comments. We expect to do very well in the energy-only market.
All right. That's helpful. Just to follow up on that, when you look at your development opportunities inside of Alberta, whether that be wind or additional gas capacity there as well, are you confident in the outlook there, or would you need to see some changes in the market before you put capital to work back in Alberta?
We are very comfortable with the market construct and the regulatory elements around the existing energy-only market. When it comes to building, it obviously ends up being our view of supply-demand balance and price reaction, et cetera. That part, we'll have to see things settle down and what happens with the coal fleet, et cetera, to understand whether there's actually need for new capacity in the market or not.
All right. I appreciate the color. I'll hop back in the queue. Thank you.
The next question comes from David Quezada of Raymond James. Please go ahead.
Thanks. Morning, guys. My first question here, just a follow-up on the energy-only market. Can you talk about how, if at all, it changes your attitude towards your hedge book, and if you will be revising that or changing your view of how you want that to develop over the next couple of years?
We would expect that our hedging strategy will continue as it has under the energy-only market to date. One of the things we have seen happen is there's increasing liquidity in the Alberta market, and part of that's driven by the fact of the government staying with the energy-only market. It drives the demand side to look for those opportunities to manage their prices and lock in. That's been a positive. We would continue to look to hedge forward two to three years as the opportunities present themselves. As you can see in our latest disclosures, we've been actively selling forward over the last couple of months.
Great. That's helpful. Thank you. Just my second one here. On the investment in C2CNT, I know you've got an option to increase that stake in 2020. I'm just wondering what the deciding factors will be there and how the testing has been going so far, Shepard.
The status of the facility is, and recognize what they're doing is going through a slow ramp-up of capacity. Thus far, all I can say that they are creating nanotubes in the test facility in Calgary. Thus far it's very successful. What we're looking for is, of course, the ramp-up to a much larger level of production that is cost-effective. As I think you probably know, the main benefit of this technology is to dramatically reduce the cost of C2CNT and broadly increase its application to other products. We need to see that on track. The second thing is that right now there's close work being done with Lehigh Hanson, who are looking at it in terms of its application to cement. There's ongoing testing that'll take place.
There's testing that's taking place right now at Washington State University around cement, and that will move to extensive tests with Lehigh here in Alberta to produce much improved cement in terms of its strength and other characteristics.
Great. That's very helpful. Thank you. That's it for me.
The next question comes from Patrick Kenny of National Bank Financial. Please go ahead.
Yeah. Good morning, everybody, and congratulations to Brian as well. Outside of Alberta, just wondering if you could provide an update on the recontracting discussions at the Island facility and perhaps Decatur, and whether or not you see any change in the underlying economics once those two contracts roll over.
I can say at this point, the situation continues to be positive. Discussions are ongoing. It's probably too early to comment on economics, and certainly being in discussion, don't necessarily want to show our hand. At this point, again, discussions continue to be positive, and we continue to be very optimistic on both fronts.
Okay, that's great. With your new sustainability report fresh off the press here, I'm wondering if you could provide us with a refresh on the estimated reclamation cost for the coal mine and also how you're managing any liability risk around coal ash or any other airborne contaminants.
For the most part, nothing has changed on that front, Pat. For our reclamation costs, we reclaim the mine as we go. That's kind of business as usual. Certainly the decommissioning of the equipment and the buildings related to the mine, there's always some changes in the magnitude of that number just as based on interest rates and how that flows into the calculation. Effectively, there hasn't been much change in that overall number.
Any comment on the potential coal ash liability longer term?
No. Not aware that that's a concern from our end. Certainly would say in some cases that coal ash may have a future value where it was landfilled before. We don't have a concern about risk of how it's been managed and disposed. Certainly it could be an asset in the future.
All right. That's great. I'll jump back in the queue.
The next question comes from Mark Jarvi of CIBC Capital Markets. Please go ahead.
Good morning, everyone, and best wishes to Brian, and congratulations on retirement. Just maybe going back to the hedging, you did lock in a bit more in 2022, but the pricing came down. Maybe just what your thoughts are was just available liquidity and what you guys felt comfortable enough locking in sort of in the low CAD 50s, with forward curves sort of next couple of years around CAD 55 and pushing towards CAD 60.
Yeah. As we mentioned earlier, we saw quite a rise in forward pricing and in particular for 2021 and 2022. That, we feel was driven by policy announcements both on the energy-only market side, but also there's the element of, in 2022, the capacity market would've been in full swing, and capacity payments would've truncated or taken the place of some of the energy payments. We've seen those prices now rise and more reflect the all-in price going forward. For us, we see long-run prices in Alberta will be in that CAD 50-CAD 60 range, and is representative of the cost of new generation. We feel that's a very good place to land in terms of selling forward. You would continue to see us reducing our length to the extent we can sell in that CAD 52-CAD 58 price markers in the market.
I guess I'm just curious that you added some more forwards in 2022, bringing it down to low 50s. Didn't really change your 2021 exposure. Just kind of curious of why no movement on 2021 if there's more liquidity.
Yeah.
a bit more in 2022 at the lower prices.
Yeah. What happened there was in 2021, as you know, we look for opportunities to arbitrage in the market. In 2021, earlier this year, there was liquidity there where the price was materially below our expectations for that year. We actually ended up buying power for 2021 and then subsequently reselling it. As a result of those buys and sells, that's why we're only at 4% for 2021. 2022, there wasn't that liquidity or opportunity to buy at those lower prices. What you've seen is mainly just the sale of power into 2022 since Q1.
Okay. I want to turn to the dual-fuel capabilities at Genesee, just curious to see if you guys, if any more updated discussions or what your view is in terms of extension of life and how that plays into having the dual-fuel capabilities before, I guess, quote-unquote, full conversion and useful life of the assets? The other thing was kind of jump back into what you think the emissions intensity will be, even if you ran on predominantly natural gas for those facilities?
In terms of the capability and life extension, as of the end of the next decade and consistent with the agreement that we have with the Alberta government, we'll no longer be able to emit coal-based emissions from those facilities. We can, of course, continue on burning natural gas. The actual dual-fuel capability doesn't impact sort of in our view, the longevity of the facility in the longer term. In terms of the short term between now and the end of the next decade, we see that obviously moving to being able to go dual-fuel enhances both the economics associated with the facilities, but also decreases the overall total emissions that we expect to happen between now and the end of the decade.
From almost every perspective, we see it as a very promising approach to dealing with the realities of, again, the economics and the carbon market going forward.
Just on the emissions, is the 20%-33% reduction depending on how much gas you substitute in, implying that you're kind of in a 0.6, maybe a bit over that tons per megawatt hour in CO2 emissions? Is that sort of what you're implying with those CO2 or the greenhouse gas reduction numbers?
That is the full gamut, 50%-100% dual-fuel reduction. Your assumptions are correct.
Okay. I'll leave it there for now. Thanks, guys.
The next question comes from Ben Pham of BMO Capital Markets. Please go ahead.
Hi. Thanks. Good morning. I just wonder your comment around, well, there's a question and your response to the price cap in Alberta. Is that linked in any way to the AESO regulations? Are you guys just expecting the CAD 999 to go up?
Certainly as a result of PPAs coming off and so on and so forth, there'll be other changes that take place in the market more around market concentration issues. The price cap moving up, I think is strictly an economics determination and what through modeling is expected to result in overall price signals, average price signals that'll move generation to be in the market in a timely manner.
Yeah. Just the current price cap of CAD 999 has been in place since the late '90s in the energy-only market in Alberta. There has been no adjustments for inflation, so effectively it's going down in real terms. At a minimum, we'd expect to see an adjustment to get back in real terms to what it was previously.
Okay. You expect that with an energy-only market, that you will see increased volatility and an opportunity for economic withholding?
We certainly see increased volatility. You want to keep in mind, of course, we're staying in an energy-only market, so it's not like we went to a capacity market and we're coming back out of it. We've always been there. I think what you're going to see, though, in terms of increased volatility is just the natural tightening of supply and demand in the Alberta market and the fact that as the PPAs and in units get handed back to entities who operate those assets in a commercial manner. Certainly that volatility results in the most optimal use of assets in the Alberta market in real time. Certainly, the other positive we're seeing is on the customer side. Customers are able to manage that volatility by entering a competitive retail contract or large industrials looking at other alternatives to manage their prices.
Yes, we'll see higher volatility and certainly that's going to drive the optimal use of assets and decisions around them, but also more hedging on the demand side.
Okay. That's what you mean by you expect to do well in that market?
No, actually, just if I can comment on that. Just maybe to connect a couple of dots here. The previous Alberta government made the decision to go to the capacity market. As we went through that, I think we demonstrated in previous discussions where broadly speaking, the overall economics is somewhat similar. As you know, there's maybe a propensity to over-procure, which results in overall increased cost to consumers. That issue aside, because of that volatility in the way the market develops, we believe, I'll just characterize it as our share of the market economics will be a little bit disproportionate. We've done very well from the trading perspective over time, and we expect to do so as we go forward in the energy-only market.
To put a little quantification around that, and again, very dependent on assumptions and other things, but we would expect that in an energy-only market our trading performance would be somewhere in the order of CAD 5 million-CAD 10 million better and with probably more upside than downside.
Okay. That's great. Can I ask then secondly, your contracted growth targets, you've done more than expected this year. Maybe can you comment on your balance sheet and maybe acquisition outlook, renewables, just what are you expecting in the second half and into 2020?
As we go through the balance of the year, we continue to look at different opportunities, whether they be on the renewable side, contracted renewables, or whether they be on the contracted natural gas side. Again, we keep looking for good opportunities and certainly see that we have a strong balance sheet and access to capital as demonstrated in the last quarter.
You have more room. You did the Goreway acquisition, and that was almost double your annual target, but you feel that, let's say you did something in two months, you have the balance sheet capacity to do it?
I think part of it is driven by the fact that with Goreway, we actually raised CAD 150 million of common equity as well as CAD 150 million of preferred shares. I would say roughly half that growth related to Goreway was funded by internally generated cash, but the balance was funds we had raised in the equity markets. As we look forward on a net net basis, we can fund CAD 500 million a year by internally generated cash, and that capability remains as we move forward because we did tap the equity market.
Okay. That's great. Thanks, everybody.
The next question comes from Andrew Kuske of Credit Suisse. Please go ahead.
Thank you. Good morning. I know it's only been a few days since the Alberta government made the announcement on the energy-only market. What's your anticipation on a longer duration basis with the volatility that you've talked about just on this call, in the market? If we see that volatility, do you believe you'll see more peakers in the market?
Yeah, definitely staying with the energy-only market would probably push the economics more towards peakers than base load or mid-merit generation assets.
In that kind of market construct, if you wind up with peakers coming in, effectively shaving some of the peak and with the volatility will dampen a little bit. How do you think about just the balance sheet that you've got and really just sort of industry role with no capacity payments? Does that mean the balance sheets have to be a little bit less levered in the market? Or how do you think about that, just conceptually?
Yeah. The capacity market that was proposed was a one-year term for the capacity payment. Yeah, there was some reduction in overall revenue volatility under the capacity market. When you look at the energy-only market, in particular our history, we've probably removed about half the volatility through our just selling forward two to three years. Generally, the financability from our perspective is virtually the same under the energy-only market versus what was proposed under the capacity market.
Okay. That's helpful. Maybe just one final question, just on Whitla. I think in the MD&A you've got CAD 340 as the total project cost that you're estimating, and that's really just the FX impact from the prior CAD 315-CAD 325 range.
There's actually, Andrew, a bit of actual, I'll call it, overage that's not associated with foreign exchange. That's primarily related to an increase in interconnection costs in the order of CAD 2 million-CAD 2.5 million. It's not pure just foreign exchange.
Okay. I appreciate the clarification. Thank you.
The next question comes from Robert Kwan of RBC Capital Markets. Please go ahead.
Morning. I know it's early, but all the best, Brian, for the retirement. I guess, first, just starting with the Alberta price expectations. I'm just wondering, what are your carbon cost per ton expectations, price and framework-wise, especially as it relates to adding 2022 hedges?
Our fundamental forecast, we generally we're reflecting roughly CAD 30 per ton based on the current program that's in place. Certainly, as we see the TIER framework get finalized by the new provincial government, depending where they ultimately land, that we could end up fine-tuning that. Yeah, generally, it'd be around that CAD 30.
Okay. You had the comment that you're expecting kind of CAD 50-CAD 60 MWh range over, say, the longer term. Just wondering how does that range then factor into your thought process on G4 and G5 as well with respect to that? Is there still a JV with ENMAX on those units?
Yeah, there continues to be a JV and certainly a view. When you add capacity in those large chunks, you do have to take into consideration their impact on the market. On sort of a straight basis, in longer-term pricing, between CAD 50 and CAD 60 definitely supports the construction of those facilities.
In terms of then your outlook at CAD 50 - CAD 60 , your last statement there, Brian, and even I know there was an earlier question around peakers, but I believe what you were looking at was fast response technology. Does the market framework then, as you see it in your expectations, kind of bring the G4, G5s to the front burner?
It definitely improves the outlook for it. I think as Bryan was commenting earlier in the discussion, it may well be the best increments to the market over the next little while may well be peaking facilities as opposed to large mid-merit or base load units. Part of it will be seeing a bit how the market develops. We look at that capacity being there in the event that there's either very dramatic increases in supply or again, fairly dramatic reductions in supply that certainly with the age of the coal fleet can be creating those opportunities.
Yeah. Just to follow up on Brian's comments, if we see more retirement of the older coal-fired assets, that will start creating more of a need for a mid-merit unit.
Got it. Okay. If I can just finish with Ontario. There was a comment earlier on the call that you see a very positive recontracting outlook in Ontario. I'm just wondering what outcomes factor into that view. Is it just that you expect the units to be recontracted, or are you expecting similar EBITDA and cash flow or something in between?
Those units, I think as we've discussed a number of times, the three units are extremely well-positioned and have recognizable significant value in the Ontario market, even a decade from now. We think that positions us extremely well for negotiations or discussions that can take place at that time. The fact that they will, in our view, definitely be needed by the Ontario market and certainly the announcement and continuation of the existing regime certainly supports those considerations. How it actually translates into economics, our view continues to be that we'll see positive economic outcomes. Again, it's a factor of negotiation at the time and other developments in the market.
Okay, just in terms of the positive economic outcomes, is that just positive to what you budgeted? Presumably not positive to where the contract is right now, though.
When we look at Ontario over the longer term, and we look at beyond the current PPAs, given their, as Brian was saying, the need for them in their geographic location, we would expect some erosion relative to the current EBITDA numbers, but certainly not very material erosion.
Got it. Great. Thank you very much.
The next question comes from John Mould of TD Securities. Please go ahead.
Morning. I'd like to start on your U.S. development efforts. I know we covered that a little earlier, maybe just from a different angle. I recognize you've exceeded your committed capital target for the year, I'm just wondering where you're at with your development efforts in the U.S. wind market, the kinds of opportunities you're seeing, and how you're thinking about the near-term potential for further investments there beyond Cardinal Point in the context of the coming PTC step-downs beginning at the end of 2020.
We continue to look at opportunities in our pipeline for pulling the trigger on developments that could start this year or contracts and commitments that could begin this year. I'd have to say the probability of that is declining. There's been a tremendous amount of activity. There are certainly starting to be constraints in the market around supply, et cetera, for being complete in time before the step-down in the PTCs. On the other hand, we're starting to see a little bit of ramp-up in terms of interest, I'll call it on the other side. We would expect that through the next year or two, we'd continue to see a ramp-up in our activity in terms of new renewable opportunities in the U.S.
Okay. Maybe just moving back to Genesee, the transformation there on Genesee 3, how are you thinking about the engineering work required there and the timeline for making a final decision about increasing the dual-fuel capability of that supercritical unit beyond 40% gas?
We're continuing to look at it from the technical perspective and where it sort of fits in our planning. Again, we're very actively looking at that and should be coming to a conclusion in the reasonably near term.
Okay, great. Maybe one just quick question on your guidance commentary. You referenced tracking to achieve the top end of your range, and that's modestly up from referencing the upper end of your range at Q1 with Q2 in line with your expectations. Is that increased comfort just because we're through another quarter or similar what you said on the Q1 call? Were you able to lock in some higher prices for the second half of the year?
It's a combination of both of those.
Okay, great. That's all I had. Thank you very much.
Once again, if you have a question, please press star then one. The next question comes from Jeremy Rosenfield of Industrial Alliance Securities. Please go ahead.
Yeah, thanks. Congrats to you also, Brian, on the retirement. Just on Genesee, specifically in the quarter, there were the availability penalties, and I am just wondering if you were able to quantify to any degree what the penalties were specifically in Q2.
For the Genesee outage, we would have seen the availability incentive payment approximately CAD 8 million higher than what we would have expected, just given the high prices. Now, having said that, the higher prices also benefited the balance of our Alberta portfolio, which offset a large part of that negative variance.
Got it. Yeah. I just wanted to go back to, I think it was a response to a question from Rob Kwan, just in terms of the assumption that you're making for carbon costs in the Genesee AFFO forecast specifically. Are you using that CAD 30 per ton carbon cost assumption in that forecast?
Yes.
Okay, perfect. Maybe just one final one on the C2CNT initiative. Do you have an estimate, or is it maybe too early in terms of the potential for the total investment in that technology at this point? If you were to fully exercise the options, that is.
Yeah. It's in the order of magnitude of less than CAD 25 million.
Okay. That's good. That's very useful for framing it for us. Thank you. That's all for me.
Operator, are there any more questions?
There are none at this point, sir.
Okay, if there are no more questions, we will conclude our conference call. Thank you for your interest in Capital Power. Have a good day, everyone.
This concludes today's conference call. You may disconnect your lines.