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 opened for questions. This call is being recorded today, July 29, 2019. 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 Q2 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 Vazjo, President and CEO and Brian Deneeve, 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 2.
In today's discussion, we will be referring to various non GAAP financial measures as noted on Slide number 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 Q2 2019 MD and A. I will now turn the call over to Brian Vazjo for his remarks starting on Slide 4.
Thanks, Randy, and good morning. Before I review the Q2, I'd like to start off by highlighting 2 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 price. 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 5.
Earlier this month, the Ontario ISO announced they were canceling further work on a capacity market after considering stakeholder feedback and concerns. The Ontario IASO 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 ISO, the recontracting outlook for Capital Power's 3 natural gas facilities, York Energy, East Windsor and Goraway is very positive. Turning now to the Q2, I'll briefly recap the highlights starting on Slide 6.
The highlight of the quarter was the acquisition of the Goreway facility, an 875 Megawatt natural gas facility in Ontario that is contracted until 2029. The acquisition closed on June 4, and we've had a successful integration of the asset to date. For the 6th consecutive year, we've increased the common share dividend. The 7.3% dividend increase is effective for the 3rd quarter dividend and represents an annualized 1 point or $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 625,000,000 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% to 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 7.
On June 18, 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 II have 100 percent dual fuel capability in mid-twenty 20, followed by Genesee I in the spring of 2021, while Genesee 3 will have up to 40% gas capability at that time. The total project cost estimated at $50,000,000 to completely transform Genesee 1 and 2 to dual fuel capability and up to 40% gas for Genesee III.
Adjusted funds from operations is estimated to increase by $10,000,000 in 2020 and $20,000,000 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% to 30 3 percent reduction in annual GHG emissions based on the Genesee units operating at 50% to 100% at a time on natural gas compared to operating on coal alone. Turning to Slide 8, I'll review Alberta power prices.
In the Q2, the average power price was $57 per megawatt hour, slightly higher than the $56 in the Q2 of 2018. In the 1st 6 months of the year, the average power price was $63 which was 73 or 37 percent 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 $60 a megawatt hour. Forward prices have trended upwards since the end of March and are up approximately 14% to 24% for 2020 2021.
I'll now turn the call over to Brian DeNeve. Thanks, Brian. Starting on Slide 9, financial results in the second quarter were in line with our expectations. I would characterize the 2nd 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 4 days longer than planned.
The longer outage in higher power prices contributed to higher net availability penalties. Revenue and other income were 366,000,000 dollars down 1% compared to the Q2 of 2018. Adjusted EBITDA was $191,000,000 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 Gorway and Arlington Valley acquisitions.
Normalized earnings of $0.14 per share was down compared to $0.20 per share in the Q2 of 2018. We generated AFFO of $85,000,000 that was up 12% year over year. AFFO per share was $0.82 up 11% from the Q2 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 763,000,000 dollars up 12% year over year.
Adjusted EBITDA was $393,000,000 up 2% compared to 2018. Normalized earnings of $0.44 per share were down $0.04 compared to $0.48 in 2018. We continue to generate strong AFFO, including $202,000,000 in the 1st 6 months that was up 25% year over year. AFFO per share was $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 Q1, up $7.12 in 20.20 2021, respectively. With higher forward prices, we have increased our hedging positions for 2020 to 2022. This includes selling forward an additional 108 megawatts in 2020 that increased our hedge position from 24% to 41% at an average contract price in the mid $50 per megawatt hour range. For 2021, we're at 4% hedged at an average contract price in the low $60 per megawatt hour range. And for 2022, we're 9% hedged at an average contract price in the low $50 per megawatt hour range.
This compares to current average forward prices of approximately $58 per megawatt hour for 20.20 dollars $60 for 20.21 dollars $55 for 2022. I will now turn the call back to Brian.
Thanks, Brian. I'll conclude our comments on our results to date by comparing our 6 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 $40,000,000 in the 1st 6 months and we continue to forecast an $80,000,000 to $90,000,000 range for the full year. Adjusted EBITDA was $393,000,000 in the first half of the year and we are forecasting to be at the high end of the 870,000,000 dollars to $920,000,000 target.
We generated $202,000,000 in AFFO in the 1st 6 months of the year and now expect to finish the year at the top end of our $485,000,000 to $535,000,000 target range. Slide 13 outlines our development and construction targets for 2019. We currently have 2 fully contracted wind projects under construction. This includes Whitlaw Wind in Alberta with commercial operations targeted for the Q4 of this year. The budget for Whitla is $315,000,000 to $325,000,000 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 $289,000,000 to $301,000,000 with a target to begin commercial operations in March of 2020. Once completed, these 2 wind projects will add 3 50 megawatts of long term contractor generation to our fleet. As we've exceeded our $500,000,000 of committed contractor growth capital in 2.19 with a $1,000,000,000 acquisition of the Gorway 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 for Climate Related Financial Disclosures or TCFD, approximately 25 percent of companies disclose information that is aligned with more than 5 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 4 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 2,030 from 2,005 levels, reducing CO2 emissions by 10% and our emissions intensity by 65% in 2,030 from 2,005 levels in spite of increasing our generation by 145 percent and investing in carbon capture and utilization technologies 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. And in February 2020, we are planning on releasing our 1st 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, we're
ready to start the Q and A.
Certainly. We will now begin the question and answer session. The first question comes from Robert Hope of Scotia Capital. Please go ahead.
Good morning, everyone. And 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. However, 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?
So 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. And as such, we expected it to normally evolve in the way that was expected to be happening. And that specifically, on point to your question, we do anticipate that at some point, the cap on power prices will be raised. And I can tell you that in our consultations with the government, we expressly said that, that was a necessary move for moving or continuing to stay with the energy only market.
So they are definitely aware that that's part of the decision to stay with the energy only market. And 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. And then just a 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 kind of some changes in the market before you put capital to work back in Alberta?
So we are very comfortable with the market construct and sort of 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, etcetera, etcetera. So that part, we'll have to see things settle down and what happens with coal fleet etcetera, etcetera 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. Good 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. So it drives the demand side to look for those opportunities to manage their prices and lock in. So that's been a positive. So we would continue to look to hedge forward 2 to 3 years as the opportunities present themselves.
And 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. And then 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 at Sheppard?
So the status of the facility is and recognized what they're doing is going through a slow ramp up of capacity. And thus far, well, I can say that they are creating nanotubes in the test facility in Calgary. So it's thus far, it's very successful. What we're looking for is, of course, the ramp up to much larger level of production that is cost effective. And 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.
So need to see that on track. The second thing is that right now there's close work being done with Lehigh Hansen who are looking at it in terms of its application to cement. And so there's ongoing testing that will 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.
Yes, good morning everybody and congratulations to Brian as well. Outside of Alberta, I was 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?
So 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. So at this point, again, discussions continue to be positive and we continue to be very optimistic on both fronts.
Okay. That's great. And then with your new sustainability report fresh off the press here, 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?
So for the most part, nothing has changed on that front, Pat. So for our reclamation costs, we reclaim the mine as we go. So that's kind of business as usual. Certainly, the decommissioning of the equipment in 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. But effectively, there hasn't been much change in that overall number.
And any comment on the potential coal ash liability longer term?
No. Not aware that we would that's a concern from our end. Certainly, I would say in some cases that coal ash may have a future value where it was landfilled before. So it's definitely we don't have a concern about risk of how it's been managed and disposed. And 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.
Just maybe going back to the hedging, just you did lock in a bit more in 2020 2, but the pricing came down. Maybe just kind of what your thoughts are, was it just available liquidity and what you guys felt comfortable enough locking in sort the low-50s with forward curve sort of next couple of years around 55 and pushing towards 60? Percent?
Yes. So as we mentioned earlier, we saw quite a rise in forward pricing and in particular for 2021 2022. And 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 have been in full swing and capacity payments would have truncated or taken the place of some of the energy payments. So 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 $50 to $60 range and is representative of the cost of new generation.
So we feel that's a very good place to land in terms of selling forward. So you would continue to see us reducing our length to the extent we can sell in that $52 to $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 in 2021 if there's more liquidity, but willing to lock in a bit more in 2022 at the lower prices?
Yes. So what happened there was in 2021, as you know, we look for opportunities to arbitrage in the market. And in 2021, there earlier this year, there was liquidity there where the price was materially below our expectations for that year. So we actually ended up buying power for 2021 and then subsequently reselling it. So as a result of those buys and sells, that's why we're only up 4% for 2021.
2022, there wasn't that liquidity or opportunity to buy at those lower prices. So what you've seen is mainly just the sale of power into 2022 since Q1.
Okay.
And then I want to turn to the dual fuel capabilities at Genesee and just curious to see if you guys have 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, full conversion and useful life of the assets? And then the other thing was kind of back into what you think the emissions intensity will be, even if you ran on predominantly natural gas for those facilities?
So in terms of the capability in 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 the natural burning natural gas. So the actual dual fuel capability doesn't impact sort of in our view of the longevity of the facility in the longer term. Now in terms of that in 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. So from almost every perspective, we see it as a very promising approach to dealing with the realities of again the economics in the carbon market going forward.
And then just on the emissions, is the 20% to 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?
So that is the full gamut, 50% to 100% dual fuel reduction. So 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'm just wondering your comment around well, there's a question and then your response to the price cap in Alberta. Is that linked in any way to the OPEC regulations? Are you guys just expecting the $9.99 to go up?
I mean, 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. But the price cap moving up, I think, is just strictly an economics determination and what through modeling is expected to result in price overall price signals, average price signals that will move generation to be in the market in a timely manner.
Yes. And just the price cap, current price cap of $9.99 has been in place since the late 90s in the energy only market in Alberta. So there has been no adjustments for inflation. So effectively, it's going down in real terms. So at a minimum, we'd expect to see an adjustment to get back in real terms to what it was previously.
Okay. And 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. And 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 to operate those assets in a commercial manner.
So certainly that volatility results in the most optimal use of assets in the Alberta market in real time. And 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. So 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.
Well, actually, just if I can comment on that. There's and just maybe to connect a couple of dots here. The previous Alberta government made the decision to go to the capacity market. And as we went through that, I think we demonstrated in previous discussions where broadly speaking, the overall economics is somewhat similar. Although, as you know, there's maybe a propensity to over procure, which results in overall increased cost to consumers.
But 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 $5,000,000 to $10,000,000 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?
So 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. So 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.
So you have more room. You did the Goroy acquisition and that was almost double your annual target, but you feel that you let's say you did something in 2 months, you have the balance sheet capacity to do it?
Yes.
And I think part of it is driven by the fact that with Gourmet, we actually raised $150,000,000 of common equity as well as $150,000,000 of preferred shares. So I would say roughly half that growth related to Gorway was funded by internally generated cash, but the balance was funds we had raised in the equity markets. So as we look forward on a net net basis, we can fund $500,000,000 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. And I know it's only been a few days since the Alberta government made the announcement on the energy only market. But 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?
Yes, definitely, staying with the energy only market would probably push the economics more towards peakers than baseload or mid merit generation assets.
And then 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 will with no capacity payments? Does that mean the balance sheets have to be a little bit less labored in the market? Or how do you think about that just conceptually?
Yes. The capacity market that was proposed was a 1 year term for the capacity payment. And so yes, there was some reduction in overall revenue volatility under the capacity market. But 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 2 to 3 years. So generally, the financeability from our perspective is virtually the same under the energy only market versus what was proposed under the capacity market.
Okay. That's helpful. And maybe just one final question just on Whitla. I think in the MD and A, you've got $340,000,000 is the total project cost that you're estimating, and that's really just the FX impact from the prior $315,000,000 to $325,000,000 range?
So there's actually, Andrew, there's actually a bit of actual, I'll call it, overage that's not associated with foreign exchange. And that's primarily related to an increase in interconnection costs in the order of $2,000,000 to $2,500,000 So 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.
Good morning. No, it's early, but all the best, Brian, for the retirement. Yes, 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?
So our fundamental forecast, we generally we're reflecting roughly $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. But yes, generally it'd be around that $30
Okay. And then you had the comment that you're expecting kind of $50 to $60 a megawatt hour 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?
Yes. There continues to be a JV and certainly a view and when you add capacity in those large chunks, you do have to take into consideration that their impact on the market. So on sort of a straight basis and longer term pricing, between $50 $60 definitely supports the construction of those facilities.
Okay. So in terms of then your outlook at $50 to 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, G5 to the front burner?
So it definitely improves the outlook for it. But I think as Brian 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 merit or baseload units. So part of it will be seeing a bit how the market develops, but 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. Yes. So 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 Midmare 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 re contracting outlook in Ontario. And I'm just wondering what outcomes factor into that view. Is it just that you expect the units to be re contracted? Or are you expecting similar EBITDA and cash flow or something in between?
So those units, I think as we've discussed a number of times, the 3 units are extremely well positioned and have recognizable significant value in the Ontario market even a decade from now. And so we think that suits us extreme or 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, How it actually translates into economics? Our view continues to be that we'll see positive economic outcomes. But 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 or 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.
Great. Thank you very much.
The next question comes from John Mould of TD Securities. Please go ahead.
Good morning. I'd like to start on your U. S. Development efforts and I know we covered that a little earlier, but maybe just from a different angle. I recognize you've exceeded your committed capital target for the year, but 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?
So 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. But I'd have to say the probability of that is declining. There's been a tremendous amount of activity. There is certainly starting to be constraints in the market around supply, etcetera, for being complete in time for 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.
So we would expect that through the next year or 2, we'd continue to see or we'd see a ramp up in our activity in terms of new renewable opportunities in the United States.
Okay. And then maybe just moving back to Genesee, the transformation there on Genesee III, 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?
So we're continuing to look at it from a 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. And 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.
The next question comes from Jeremy Rosenfield of Industrial Alliance Securities. Please go ahead.
Yes, thanks. And congrats to you also Brian on their retirement. Just on Genesee specifically in the quarter, there were the availability penalties. And I'm just wondering if you were able to quantify to any degree what the penalties were specifically in Q2?
Yes. So for the Genesee outage, we would have seen the availability incentive payment approximately $8,000,000 higher than what we would have expected, just given the high prices. Now having said that, the higher prices also benefited our the balance of our Alberta portfolio, which offset a lot large part of that negative variance.
Got it. Yes.
And then 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 $30 per tonne carbon cost assumption in that forecast?
Yes.
Okay, perfect. And 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 investments in that technology at this point?
If you
were to fully exercise the options that is?
Yes. It's in the order of magnitude of of magnitude of less than $25,000,000
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.
If there
are no more questions, we'll conclude our conference call. Thank you for your interest in Capital Power. Have a good day, everyone.