Capital Power Corp

Good morning, and 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 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 second quarter 2019 MD&A. I will now turn the call over to Brian Vaasjo for his remarks, starting on Slide 4.

Thanks, Randy, and 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 then the 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 track record of investment, competitive pricing and affordable and reliable power for Albertans that will continue. From an investment perspective, we believe that 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 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 re-contract 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 re-contracting 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 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 today.

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 – or a $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 $625 million in gross proceeds from a private placement debt financing and common and preferred share offerings.

Finally, we 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 performing 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.

While Genesee 3 will have up to 40% gas capability at that time. The total project cost is estimated at $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 $10 million in 2020 and $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 who will also further reduce greenhouse gas emissions, we are estimating at 20% to 33% reduction in annual GHG emissions based on the Genesee units operating at 50% to 100% of the time of natural gas compared to operating on coal alone. Turning to Slide 8.

I'll review Alberta power prices. In the second quarter, the average power price was $57 per megawatt hour, slightly higher than the $56 in the second quarter of 2018.

In the first six months of the year, the average power price was $63, which was $73 – or 37% higher compared to 2018. We see a positive outlook for Alberta power prices based on current forward prices with 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% with 2020 and 2021.

I'll now turn the call over to Bryan DeNeve.

Thanks, Brian. Starting on Slide 9.

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 in Genesee 1 that lasted four days longer than planned. The longer outage in higher power prices contributed to higher net availability penalties.

Revenues and other income were $366 million, down 1% compared to the second quarter of 2018. Adjusted EBITDA was $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 $0.14 per share was down compared to $0.20 per share in the second quarter of 2018.

We generated AFFO of $85 million that was up 12% year-over-year. AFFO per share was $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 $763 million, up 12% year-over-year.

Adjusted EBITDA was $393 million, 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 million in the first six 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 first quarter, up $7 and $12 in 2020 and 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 hedged position from 24% to 41% at an average contract price in the mid $50 per megawatt hour range.

For 2021, we're 4% hedged in 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 2020, $60 for 2021, and $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 $40 million in the first six months, and we continue to forecast an $80 million to $90 million range for the full-year.

Adjusted EBITDA was $393 million in the first half of the year. And we are forecasting to be at the high-end of the $870 million to $920 million target.

We generated $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 $485 million to $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 $315 million to $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 $289 million to $301 million, with a target to begin commercial operations in March of 2020. Once completed, these two wind projects will add 350 megawatts of long-term contracted generation to our fleet.

As we've exceeded our $500 million of committed contracted growth capital in 2019 with a $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 for Climate-related Financial Disclosure, 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 outlined 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%, and 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. And 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, we're ready to start the Q&A.

Good morning, everyone. And Brian, I am maybe a little bit early on this, but congratulations on the retirement announcement.

Thank you very much.

Now if we can start off on the Alberta energy market, appreciate the comments you made in your prepared remarks. However, the government's been in a 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 upward price cap?

So in terms of the discussions with the Alberta government, you're quite right. They've been basically saying that they're going to continue with the track of the energy-only market.

And as such, we expect 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're 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, et cetera, et cetera.

So that part, we'll have to see, things settle down and what happens with the coal fleet, et cetera, 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.

Thanks. Good morning, guys.

My first question is 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 realizing 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 is 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 that prices and walk-in. So that's been a positive.

So we would continue to look to hedge forward two to three 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 Shepard?

So the status of the facility and recognize what they're doing is going through a slow ramp-up of capacity. And thus far, I can say that they are creating nano tubes 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 is close work being done with Lehigh Hanson who are looking at it in terms of its application just to Cement. And so there's ongoing testing that will take place, there's testing that's taking place right now in Washington State University around Cement and that will move to expansive 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 from me.

Yes. Good morning, everybody, and congratulations to Brian as well.

Outside of Alberta, just wondering if you could provide an update on the re-contracting 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 up 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 call 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 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. 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, would say in some cases that coal ash may have a future value where it was landfill before. So it's definitely – we don't have a considerable risk if how it's been managed and disposed and certainly could be an asset in the future.

All right. That’s great.

I’ll jump back in the queue.

Good morning, everyone, and best wishes to Brian and congratulations on retirement. Just maybe going back to hedging, just you did lock in a bit more in 2022, but the pricing came down.

Maybe just kind of where your thoughts are with just available liquidity? And do you guys feel comfortable enough locking in sort of in the low 50s with forward curve sort of next couple of years around 55 and pushing towards 60?

Yes. So as we mentioned earlier, we saw quite a rise in forward pricing and in particular for 2021 and 2022.

And that – we feel it was driven by policy announcements both on the energy-only market side, but also there is the element of – in 2022, the capacity market would have been in full swing and capacity payments would have truncated or taken the place in some of the energy payments. So we've seen those prices now rise and more reflect the all in price moving forward.

For us, we see long-run prices in Alberta. We'll be in that $50 to $60 range.

And as 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 extend so we can sell in that $52 to $58 price markers in the market.

I guess, I was just curious that you got more forwards in 2022, bring it down to low $50s, and didn’t really change the 2021 exposure. Just kind of curious of why no movement on 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, 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 only have 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 wanted to turn to the dual-fuel capability that 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 a dual-fuel capability before, I guess, "full conversion" and useful life of the assets.

And then I think with – can jump back into what you think the emission intensity will be, even if you ran on predominately 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 burning natural gas.

So the actual dual-fuel capability doesn't impact sort of in our view on the longevity of the facility in the longer term. Now in terms of the – 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 or 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.

Thanks guys.

Hi, thanks. Good morning.

I just wondered your comment around whether there's a question on your response to the price cap in Alberta? Is that linked to anyway to the OPEC regulations?

Or are you just expecting the 999 to go up?

I mean, certainly as a result of PPA's coming off and so on and so forth, there'll be other changes take place in the market more around market concentration issues. But the price cap moving up, I think, is strictly an economics determination and what through modeling is expected to result in price – our overall price signals, average price signals that will move generation to be in the market in a timely manner.

Yes, just the price cap – current price cap of 999 is been in place since the late '90s in the energy-only market in Alberta. So there has been an 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 a real terms to what it was previously.

Okay. And you’d we expect that for a energy-only market, that you will see an increased volatility and opportunity for economic up honing?

We certainly see increase volatility. And want to keep in mind of course, we're staying in the energy-only market.

So it not like we went to capacity market and we're coming back out of it. We're – we've always been there.

I think what you're going to see though in terms of increase 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 in the competitive retail contract and where 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 meant, what you mean what you expected to do on that market?

No actually, if I could comment on that. There is – and just maybe to connect a couple of thoughts year.

The previous Alberta government made the decision to go to the capacity market. And as we went through that, think we demonstrated in previous discussions very broadly speaking, the overall economics is somewhat similar.

Although as there's a maybe propensity to over procure, which results in our increased costs 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 report a little quantification around that, and again, very dependent on assumptions and other things but we would expect that an energy-only market, our trading performance will be somewhere in the order of $5 million to $10 million better.

And we're probably more upside than downside.

Okay. That's great.

Can I ask secondly the – you're contracted growth targets. You've done more than expected this year.

Maybe can you comment on your balance sheet? And may be acquisition, outlook, renewables, and just what you're expecting in the second half and in 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'd 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 Goreway acquisition and that was almost double your annual target. But you feel that you, let's say, you did something in two months, you have the balance sheet capacity to do it?

Yes. And I think a part of it is driven by the fact that with Goreway, we actually raised $150 million of common equity as well as $150 million of preferred shares.

Okay.

So I would say roughly half that growth related to Goreway was funded by internally generated cash, but the balance was funds we raised in the equity markets. So as we look forward on the net-net basis, we can fund $500 million a year by internally generate cash.

And that capability remains as we move forward because we did cap the equity market.

Okay. That's great.

Thanks everybody.

Thank you. Good morning.

And I know it's only been a few day, since the Alberta government hit the announcement on the energy-only market, but what's your anticipation on a longer duration basis with the volatility that we've talked about just on this call in the market, if we see that volatility that you believe you'll see more peakers in the market?

Yes. Definitely stay within the energy-only market will probably push the economics more towards peakers than baseload or with mid-merit generation assets.

And that kind of market construct, if you wind up with and peakers coming in effective shavings from 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 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?

The capacity market that was proposed was a one-year term for the capacity payment and so yes, there were some reduction in overall revenue volatility under the capacity market. But when you look at the energy-only market and, in particular, our history, we probably removed about half of all volatility through our just selling forward two to three 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&A, you've got $340 million as the total project cost that you're estimating.

And that's really just the FX impact from the prior $315 million to $325 million range?

So there's actually, Andrew – there's actually a bit of actual, I'll call it overage that is not associated with foreign exchange. And that's primarily related to an increase in interconnection cost in the order of $2 million to $2.5 million.

So it's not pure, just foreign exchange.

Okay. Appreciate the clarification.

Thank you.

Good morning. I know 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, why is this, 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 gets finalized by the new provincial government, depending where they ultimately land that, we can 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 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 view – and when you add capacity in those large chunks, you do have to take into consideration, their impact on the market.

So on sort of a straight basis in longer-term pricing, between $50 and $60 definitely supports the construction of those facilities.

Okay. So in terms of then your outlook at $50 to $60, in 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 Bryan was committing 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 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 is either very dramatic increases in supply or again, fairly dramatic reductions in supply that certainly with the age of a coal fleet can be creating those opportunities.

So just a 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.

And 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. And I'm just wondering what outcomes factor into that view?

Is it just that you're expecting it to be recontracted? 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 three 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, certainly supports those considerations. How would it actually translate into economics?

Our view continues to be, 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 a very material erosion.

Great. Thank you very much.

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 recognized 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 our contracts and commitments that would begin this year. But I had to say the probability of that is a declining.

There's been a tremendous amount of activity. There is certainly starting to be constraints in the market around supply, et cetera, for being complete in time for – before the step down in the PTCs.

On the other hand, and we're starting to see a little bit of a ramp up in terms of interest, I'll call it, on the other side. So we would expect that through the next year or two, 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 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 super critical unit beyond 40% gas.

So we're continuing to look at it from a technical perspective and where it sort of fits of in our planning. And again, we will 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 to 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.

Thanks, and congrats to you also Brian on the 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, yes, we would've seen the availability incentive payment approximately $8 million higher than what we would have expected just given the higher prices.

Now having said that, the higher prices also benefited the balance of our Alberta portfolio, which offset large part of that negative variance.

Got it. And then I just wanted to go back to – it was a response to a question from Rob Kwan, just in terms of the assumptions that you're making for carbon cost in the Genesee AFFO forecast specifically, are you using that $30 per ton 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 less than $25 million.

Okay. That’s good.

This is very useful for framing it for us. Thank you.

That’s all for me.

Operator, are there any more questions?

Okay. 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.