Welcome to Capital Power's second quarter 2017 financial results conference call. At this time, all participants are in a listen-only mode. Following the presentation, the conference call will be open for questions. The call is being recorded today, July 26th, 2017. I will now turn the call over to Mr. Randy Mah, Senior Manager, Investor Relations. Please go ahead.
Good morning. Thank you for joining us today to review Capital Power's second quarter 2017 results, which were announced earlier this morning. The financial results and the presentation slides for this conference call are posted on our website at capitalpower.com. Joining me on the call are Brian Vaasjo, President and CEO, and Bryan DeNeve, Senior Vice President and CFO. We'll start the call with opening comments. Then conclude with a question and answer session. Before we start, I would like to remind listeners that certain statements about future events made on this call are forward-looking in nature and are based on certain assumptions and analysis made by the company. Actual results may differ materially from the company's expectations due to various material risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information on slide number two.
In today's presentation, we will be referring to various non-GAAP financial measures, as noted on slide number three. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP and therefore are unlikely to be comparable to similar measures used by other enterprises. These measures are provided to complement GAAP measures in the analysis of the company's results from management's perspective. Reconciliations of these non-GAAP financial measures can be found in the company's second quarter 2017 MD&A. I'll now turn the call over to Brian Vaasjo for his remarks, starting on slide four.
Thanks, Randy. Good morning. I'll start off by reviewing some of the significant events that have taken place recently. On June 13th, we completed the acquisition of the Decatur Energy Center for CAD 603 million. The Decatur facility is a 795-megawatt natural gas facility located in Decatur, Alabama that is fully contracted until December 2022. Based on its history and need for capacity in the region, we believe there's a very high probability of recontracting after 2022. The addition of Decatur is expected to be accretive to adjusted funds from operations by CAD 0.18 per share in the first full year of operations.
As part of the Veresen transaction, under which we previously acquired the two gas-fired Ontario plants in April, we have now completed the acquisition of the two waste heat generation facilities on June 1st, totaling 10 MW for CAD 8 million cash consideration, plus the assumption of CAD 18 million of project-level debt. The facilities are Savona and 150 Mile House, which are in British Columbia. Both facilities are currently under 20-year PPAs that expire in 2028. Turning to slide five. Another significant milestone for the company is the completion of our first wind development project in the U.S. Our Bloom Wind facility began commercial operations on June 1st and is located in Kansas. The construction of the 178 MW wind project was completed one month ahead of schedule, and construction costs came in below budget.
Bloom has a 10-year fixed price contract covering 100% of its output with a subsidiary of Allianz SE, a worldwide insurance and asset management group. Due to the U.S. tax attributes associated with the project, equity financing was provided by an affiliate of Goldman Sachs. We expect Bloom Wind to be the first of many U.S. wind development projects to reach completion. Moving to slide six. With the recent acquisitions of Veresen's thermal power business and Decatur Energy Center, in addition to the start-up of the Bloom Wind, I'd like to illustrate how this has diversified our geographical profile throughout North America. The chart shows our geographical breakdown based on adjusted EBITDA. At the end of 2016, 73% of Capital Power's adjusted EBITDA originated from Alberta. This was followed by 13% in Ontario, 9% in B.C., and 5% in the U.S.
With the addition of the six new facilities, you can see how we've achieved geographical diversification away from Alberta. In 2018, assuming there is no other changes in the current fleet, the expected adjusted EBITDA from Alberta will be reduced from 73% to 52% and will largely shift to the U.S., where adjusted EBITDA will increase from 5% to 22% of our new total. Furthermore, the recent acquisition commissioning of Bloom Wind has materially increased the company's contracted cash flows, as shown on slide seven. The chart shows the growth of our contracted adjusted EBITDA from 2012 to 2017. As you can see, our contracted adjusted EBITDA has increased 157% during this period, which translates into a 21% compound annual growth rate.
For 2017, you can see the significant step-up in contracted adjusted EBITDA from the Bloom Wind project and the start of the annual off-coal compensation payments and contributions from the acquisitions. Turning to slide eight. This growth in contracted adjusted EBITDA provides the support for dividend growth. Based on Capital Power's outlook, we have announced a 7.1% increase in the quarterly dividend from CAD 0.39 to CAD 0.4175, effective with the third quarter dividend. We have also extended our 7% annual dividend guidance for an additional two years to the end of 2020. With the annual growth to the dividend, we expect the adjusted funds from operations payout ratio in 2017 to 2020 will be within a range of 45%-55%. Overall, the company is well-positioned to deliver on this consistent annual dividend growth.
On slides nine and 10, I'd like to provide a brief update on the Alberta power market. First, with respect to the capacity market, the government of Alberta's schedule for the transition of Alberta's energy-only market to a capacity market continues to be on track. The design is expected to be formalized in late 2018, early 2019. We expect the first capacity auction to take place in 2019 for delivery in 2021. There are five working groups providing feedback on key design elements based on a strong model that is being iterated from 2017 to June 2018. Capital Power is participating in four of the five working groups. For coal to gas conversion, the decision on timing of converting our coal units to gas depends on numerous factors such as carbon and natural gas pricing, supply-demand balance, regulatory framework for converted units, and the capacity market design.
When the time comes to convert the Genesee facility to natural gas, it has many competitive advantages such as its young age, condition, availability, and heat rate that are maintained after gas-fired conversion, with the efficiency translating into higher dispatch. The estimated cost for a simple gas conversion on our units is between CAD 25 million-CAD 50 million per unit. We expect there will be significantly lower operating and maintenance costs after the conversion to natural gas. Turning to slide 10, the Renewable Electricity Program. We have two proposed projects to bid in. Whitla Wind in Southern Alberta has been bid into the first round and is now competing in the third stage of the process. Halkirk 2 in East Central Alberta is well-positioned to participate in future procurement rounds. In July, we reached a partnership agreement with the Siksika Resource Development Ltd. to develop new generation in Alberta.
Under the agreement, Capital Power and Siksika will jointly develop power projects on the Siksika Nation Reserve located 100 km southeast of Calgary. The reserve is situated on 172,000 acres of land with excellent solar, wind, and natural gas project potential. This positions Capital Power very well for a number of future project developments. As a leading developer of new power generation in Alberta over the past decade, Capital Power has the expertise and track record to build Alberta's next generation of renewable and base load power generation. Moving to slide 11 and the Q2 results. This slide compares the availability operating performance of our facilities for the second quarter of 2017 and for the first half of the year, comparing it to the same periods a year ago.
We had excellent operational performance in the second quarter, with average availability of 94%, which was higher than the 90% from a year earlier. In the first six months of the year, the average availability was 96% compared to 93% a year ago. The 94% availability in the second quarter reflects the major scheduled outage at Genesee 1, which had 70% availability. There were also other planned outages at Cloverbar Energy Centre and Southport that reduced the availability for those facilities. I'll now turn the call over to Bryan DeNeve.
Thanks, Brian. I'll start on slide 12 with a review of our second quarter financial performance. Overall second quarter 2017 financial results were consistent with our expectations. This includes generating CAD 47 million in adjusted funds from operations and normalized earnings per share of CAD 0.27. Alberta spot prices in the second quarter averaged CAD 19 per megawatt hour, compared to CAD 15 per megawatt hour in the second quarter of 2016. Our trading desk performed well and captured 174% higher realized average price of CAD 52 per megawatt hour on our Alberta commercial assets versus the spot price. Despite the strong trading performance this quarter, it was even stronger in the second quarter of 2016 when the trading desk captured a 307% realized power price above the spot power price. Slide 13 shows our second quarter financial performance compared to the second quarter of 2016.
Revenues and other income were CAD 201 million, down 11% from the second quarter of 2016. Adjusted EBITDA before unrealized changes in fair values was CAD 125 million, up 2% from the second quarter of 2016. Normalized earnings of CAD 0.27 per share were down 10% compared to CAD 0.30 in the second quarter of 2016. As mentioned, we generated adjusted funds from operations of CAD 47 million, which was down 41% on a year-over-year basis. The lower FFO was due to higher costs and net financing expense, sustaining CapEx and preferred share dividends, as well as the lower realized power price and lower generation from the Southport facility. Slide 14 shows the financial results on a year-to-date basis. Revenue and other income were CAD 439 million, down 4% from 2016. Adjusted EBITDA, before realized changes in fair value, was CAD 259 million, up 3% from the same period in 2016.
Normalized earnings of CAD 0.61 per share were down 3% compared to CAD 0.63 in 2016. The lower AFFO in the first six months is due to higher net financing expense, sustaining CapEx and preferred share dividends, as well as lower trading gains from portfolio optimization and lower generation from Southport. On slide 15, I'll review the financial outlook for the remainder of 2017. The last half of the year will include full AFFO in the EBITDA contributions from the acquisitions of Veresen's thermal power business, Decatur Energy, and Bloom Wind. In the third quarter, AFFO will include the CAD 52.4 million annual off coal compensation payment from the Alberta government. Our updated commercial hedging profile for 2018 to 2020 is shown on the slide. For 2018, we are 66% hedged at an average contract price in the high CAD 40 per megawatt hour range.
For 2019, we're 45% hedged at an average contract price in the lower CAD 50 a megawatt hour range. For 2020, we're 29% hedged at an average contracted price in the high CAD 40 per megawatt hour range. If you compare 2018 to 2020 forward prices from the first quarter, you'll have noticed that forward prices have increased CAD 6 to CAD 7 per megawatt hour. This is due to higher than expected demand growth in Alberta, the retirement and mothballing of Sundance units one and two, and the Balancing Pool's plan to terminate all the Sundance PPAs. I'll conclude comments by reviewing our year-to-date performance versus our annual revised targets, starting on slide 16. In the first half of the year, average availability was 96%, which is slightly ahead of our 95% target.
Our sustaining CapEx in the first six months was CAD 34 million, compared to the CAD 80 million revised annual target. We reported CAD 104 million in operating maintenance expenses in the first half of the year, compared to the CAD 215 million-CAD 240 million target. We generated CAD 138 million in adjusted funds from operations in the first six months. Taking into account the various items that I mentioned in outlook for the remainder of the year, we are on track to reach the midpoint of the revised annual target range of CAD 340 million-CAD 385 million. To conclude, slide 17 shows our growth targets for 2017. As Brian mentioned, we completed the construction of the Bloom project ahead of schedule and with construction costs below budget. Our other growth target includes the execution of contracts and the output of two new wind developments.
We continue to make progress on our development pipeline in the U.S. and Alberta. The Whitla Wind project has advanced to the 3rd stage of the process under the Renewable Electricity Program, as previously mentioned. I'll now turn the call back to Brian.
Thanks, Bryan. Operator, we're ready to start the Q&A session.
Thank you. We will now begin the Q&A 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 is from Robert Hope of Scotiabank. Please go ahead.
Good morning, everyone, thank you for the update on the Alberta power market. Just wanted to get your thoughts, just given that the United Conservative Party is polling well, being potentially led by Jason Kenney, who is pro-coal and anti-carbon tax. I'm just wondering, how do you account for this in your longer-term strategic planning for the business?
What we've actually done as a company is we've taken a look at a whole, I'll call it array of longer-term outcomes as it relates to, I'll call it, decarbonization. On that path, these various scenarios range from accelerating what's here today to slowing down to temporary stops. What we've done is basically we've developed strategy within the context of, I'll call it significant uncertainty in picking those paths that make the most sense going forward. As it relates specifically to Alberta, when we look at investment, certainly continuing to build renewables, and we expect that certainly with a change in government, there may be some changes. Ultimately, renewable energy will be needed in Alberta, therefore our efforts and the work that we're doing certainly will be utilized in the future.
The most fundamental and significant thing that's happening in the Alberta market and that's unaffected to a significant degree by governments in the shorter term is the significant increase in demand that we're seeing in the province. That will have the greatest impact on both
What happens from a development perspective and what happens in respect of the future of the Alberta power market. Certainly, provincial natural or carbon policy has some impact, also, you do have the impact in the overlay of the federal positioning on it. We look at their strategy and approaches in the long term and specific political outcomes in the shorter term. Again, we believe that the approaches that we're taking are resilient to whatever governments come to pass.
All right. That's very helpful. Just a similar question, just in terms of the working groups and the capacity market designs that have been put forward, are these largely as you would've anticipated before, or are there any sticking points that you're seeing right now?
Well, it's certainly early days. We're not seeing any real sticking points. We think that the overall process, although, is definitely cumbersome by design, but the design is to engage a broad sector of interest in the power market. The going through iterations associated at different stages and different timeframes certainly provides for ensuring what is one of our biggest concerns is that decisions are made in a vacuum, and there's unintended consequences with other elements of the process. The way it's mapped out, we see that minimizes the risk of that happening.
All right. That's helpful. Thank you.
The next question is from Patrick Kenny of National Bank Financial. Please go ahead.
Yeah. Good morning, guys. Just back to the bump in forward Alberta prices here in light of the Balancing Pool's plan to terminate the Sundance PPAs. Maybe you can talk about how you might be in a position from a trading perspective to take advantage of the Sundance supply, potentially coming off here a couple of years earlier than expected. Does this impact your outlook for Genesee 1 and 2 at all, just in terms of your decision to burn coal right up until 2029 versus convert to gas? Maybe also you can dovetail any comments on G4 and G5.
In terms of the Sundance units going back to TransAlta, that certainly is a bullish catalyst for the market. We continue to hold length in 2018 and 2019. Certainly, as we manage our projections of pricing and look forward, that is a factor we're taking into account. Certainly, there's a lot more upside now with this than downside in our view in Alberta. As we continue to see upward movement in forward prices, we'll have the opportunity to increase our average hedge price as we take advantage of that. The other thing on the PPA front. The Balancing Pool, in their release, made it clear that it also makes sense to potentially push back Battle River 5 and potentially Keephills 1 and 2. Of course, those are still tied up in discussions between the government and ENMAX.
We believe as that gets sorted through, we'll see the Balancing Pool take a similar position with those PPAs, which will be a further catalyst for pricing in Alberta. When it comes to coal to gas conversion, the higher pricing isn't really a driver in that decision. The biggest driver, as Brian mentioned earlier in his comments, is going to be where CO2 pricing lands and where natural gas pricing lands and also some of the design elements of the capacity market. All of those are going to be factors in terms of the timing of when we do the conversion. Of course, we'll be monitoring all those factors, and that'll inform our decision on the timing. At the end of the day, the lead time for the coal to gas conversion requires about 12 to 18 months to get the parts.
Certainly, the downtime in the plan is at most, a couple of months. As we see factors change in the market, it's not a huge lead time for us to make those changes to the unit and take advantage of that conversion. In terms of Genesee 4 and 5, the strong demand growth we're seeing in the province. It'll be interesting to see as the owner gets back those units, as TransAlta gets back Sundance, and some of the decisions we may see them make over the next 12 to 18 months. That could affect our projected timing for Genesee 4 and 5. Certainly, we could still see that unit being needed in Alberta as early as 2021. We're in a position to move forward with that development. It's a development project that we'll be looking to potentially bid into the capacity market in 2019.
Got it. That is great color. Thanks, Bryan. In your disclosure here, you mentioned a reduction in scope to the Genesee 4 & 5 project. Just wondering if we can get a bit more color on those changes, and if you can confirm from back in your investor day, you were talking about a CAD 35 million annual savings on compliance costs. Has that changed at all?
No. The benefits in our projections of them hasn't changed. What has changed is there's some elements of that as we've gone underway, there's some pricing reductions actually we're experiencing that is reducing our projected capital expenditures necessary, which is a positive thing. The other factor that's happened is some of the bigger expenditures, upon further analysis, it doesn't make sense for us to make commitments on that until 2018 as opposed to 2017. That's pushed out some of those capital expenditures. Certainly the scope of the benefits and emission reductions remain the same.
Got it. Thanks for that. I'll jump back in the queue.
The next question is from Ben Pham of BMO Capital Markets. Please go ahead.
Okay, thanks. Good morning. I had a question about your extension of dividend CAGR through that decade. You look at slide seven, highlighted the contract that cash was, and that provides a pretty credible picture to support that. I'm more curious, though, just as you thought about extending that guidance more to the 2020 outlook and a lot of moving parts there that you've probably looked at. This slide seven, a couple of those wedges start to roll over to the merchant side, and you have some contract expiries as well to think about. Maybe just walk through that process a bit more, some of the puts and takes you looked at post-2020 and the range of payout ratios that you felt comfortable with when you extended the guidance.
In terms of the extension through 2020, as you mentioned, Ben, we have a very good line of sight on how things will unfold financially, and we're very comfortable that with that guidance we've provided, we'll be within that 45%-55% payout ratio during that period. As we look beyond 2020, certainly there's some additional uncertainty, and one of them will be the implementation of the capacity market and what that'll mean for our merchant length in Alberta. We've done a lot of sensitivities on the capacity market and how that design could look, but generally, there's boundaries there. Effectively, the government's commitment is that existing facilities will be treated fairly with new builds in the capacity market. That will result in price signals that will support new builds.
When we look specifically at Genesee 1 and 2, it rolls off of a PPA that's paying CAD 40 a megawatt hour. We certainly will be responsible for carbon pricing on top of that. With merchant pricing all in the CAD 55-CAD 60 megawatt hour range, we see stable margins off of Genesee 1 and 2 coming off of 2020. That gives us comfort that as we roll into 2021, we'll remain within a payout ratio of 45%-55%. When we look further beyond that, we do have recontracting in terms of Island Generation in 2022, as well as Decatur. As we've mentioned previously, Decatur, we're very comfortable in the prospects of recontracting for that facility. Island Generation being that it's needed for supporting the grid on Vancouver Island, we also believe that'll be an asset that has a high probability of recontracting.
We don't see the recontracting as an exposure relative to our ability to support the dividend beyond 2020.
Can I clarify, Bryan, the capacity payments, are you planning to treat that as contracted cash flows?
There's still details to be worked out in terms of the term of the capacity payments in the capacity market. That's one of the areas under discussion. Generally, as we look forward, we wouldn't view those capacity payments in the same vein we would those under a long-term PPA. Having said that, to the extent there is a three to five-year term on the capacity payments, that will provide more certainty and stability around cash flow. Certainly a positive.
Okay. My other question is to key off another question, the forward curve, and you highlighted the CAD 6-CAD 7 move, and I'm just curious, you guys have been looking at the market for a long time now, do you think that that move was warranted? How does that kind of compare to just the way you guys have hedged this year in 2018, 2019, and 2020?
Well, one of the things that certainly you've seen this year is, although we've increased our hedge position in 2018, 2019, 2020, quarter-over-quarter, it hasn't been dramatic. A large part of that is due to the fact that we felt forwards in Q1 were understated of the true value of power in those years. We took some select opportunities to lock in some additional length. Generally, where forwards are is more in line with our expectations. Certainly now with the strong Alberta load growth and some of the decisions being made on the older units, certainly we see a lot more upside than downside in the Alberta market, and we'll be looking to take that advantage of that as we continue to hedge out our length in Alberta. All right. Thanks, Bryan. Thanks, everybody.
The next question is from Andrew Kuske of Credit Suisse. Please go ahead.
Good morning. Really the question is for either of the Bryans, really relates to the capacity market. When we've seen these transitions in the past from a competitive market or a regulated construct to a capacity market, seems to favor the generators in really the first iteration. I'm just wondering how you think about the market transition on a longer-term basis from where we are today to capacity market, then thinking about the long-term outlook that the AESO just put out when a market possibly comes more competitive and on, obviously, a skew of renewables that comes into it.
Well, certainly there's a build-out of renewables, and as those renewables get built, it'll put some downward pressure on energy pricing. Looking forward, if we continue to see demand growth as we have, need for new capacity as early as 2021, you're going to see a combination of energy prices and capacity prices that are going to have to provide signals to incent new thermal generation to come online to maintain the reserve margin that ISO will be targeting. At the end of the day, the all-in pricing, we are very comfortable that we'll see in the sort of CAD 55-CAD 60 range, which is what'll be needed for new natural gas builds in the province.
Maybe just as a follow-up, when you think about your incumbent position right now in Alberta, do you view yourselves as having effectively the best of both worlds? Because you've been doing a lot of out-of-Alberta investment in the last little while, whether building new things or buying things, but you still have this ongoing optionality of just funneling capital back into the province if the price signals exist appropriately.
Andrew, I think you've somewhat hit the nail on the head. From our perspective and definitely with the shift of cash flow coming from outside of Alberta and even within Alberta, the contracted cash flow around the Shepard facility, et cetera, we're finding ourselves to be in an excellent position of continuing to provide investors with the growth coming from the contracted cash flow side and providing them with certainly some upside and optionality around what may well happen in Alberta. Not just from the pricing side and what may happen in the market, but in terms of assets that we hold and assets that we are positioned to develop. There's a tremendous amount of optionality, again, around the price side, but also around what can happen in terms of builds in the province.
Certainly if the province moves to being a very positive environment from a constructive environment from both a pricing and a demand perspective, we can see significant opportunities for Capital Power in Alberta, both on the investment and certainly on the uplift in terms of financial results.
Okay, that's great. Thank you.
The next question is from Mark Jarvi of CIBC Capital Markets. Please go ahead.
Morning, guys. Question on the prospects for securing new contracts in the U.S. Just wondering what sort of the gating items are and what controls the process, whether or not you guys have a lot of control over the timelines, if it's sort of exclusive negotiations, sort of like the Bloom contract, or you're looking at more RFP opportunities.
All of the above. We're extremely active on a number of projects, looking at both bilateral arrangements associated with more financial players that, again, ultimately end up providing power to an offtaker or to somebody who is in need of power. There continues to be RFPs associated with utilities or significant load requirements, such as, often you hear about Microsoft and Walmart and others. There's an array of different opportunities that are available to renewable generators in the U.S. In terms of gating, certainly there's formal RFP processes that we participate in. In some cases, we're generating our own opportunities by offering the facilities and seeing what sort of interest there is out there on any of these fronts. We've had some success from that perspective.
We continue to be very bullish and certainly expect that in the nearer term that there'll be some positive announcements from us in respect of meeting our objective of two new contracts on the renewable side this year.
Okay. Going back to the CapEx, the MD&A talks about maybe sustaining CapEx and Genesee performance standard spending being below the original target. Can you maybe quantify that or give us a bit of color how much lower than the initial target you might be?
I think for 2017, our projections was about CAD 10 million for GPS. I think our expectations are substantially lower because about half of that is being deferred into 2018. Again, that's because we determined that from a timing perspective relative to our planned outages, it didn't make sense to make those commitments in 2017, but rather 2018.
Spending on things outside of the GPS?
We're more or less on target for the year.
Okay. Then just circling back on your comments around the load growth. The AESO came out with their long-term forecast about a week ago. They're quite conservative, looking at sub 1% sort of CAGR over the next several years. What is it? Do you think they're just being overly conservative, or what gives you a bit more comfort that you guys see more constructive load growth than what they've just put out?
Well, our comments have been driven primarily on the normalized demand growth we've seen over the last 10 months in Alberta, and in the first half of this year, running at about 3.5%. Longer term, we don't expect it's going to stay at 3.5%. It'll certainly start to temper as we roll into 2018. We still see it being in the 1%-2% range. Some of the examples we see out there are just loads that are looking to locate in the province and that we're seeing on the commercial side that we're in discussions with. A lot of our commentary is based, obviously, on what we've seen actual demand growth has been over the last 10 months, but also what we see happening in terms of new development.
Great. Thanks for taking my questions, guys.
The next question is from Robert Kwan of RBC Capital Markets. Please go ahead.
Good morning. You talked about expecting a finalization or formalized capacity market or in that late 2018, early 2019 timeframe. I'm just wondering, though, do you expect to get a decent amount of granularity on some of the more technical aspects ahead of that, such that you can make some decisions, whether that's around coal to gas or G4, G5?
The general theory in terms of the way this is moving forward, Robert, is the granularity will essentially be there by about the middle of next year. From 2018 until 2019, we'll be actually putting the regulations in place and enabling the auction process. We're very hopeful that there'll be a significant level of granularity available to us as we go through these processes. In seeing the direction that discussions and policies are going, we're hopeful that some of the bigger picture issues will be somewhat resolved by the end of this year. Then as we go through the first half of next year, a fair amount of granularity will be resolved. There are some issues, such as around auxiliary services and so on, that by decision, the AESO is pushed off onto later processes of determination.
Again, we do expect that there'll be a significant amount of clarity that'll happen over the next calendar year.
Okay, when you look at some of the different things around coal to gas that you outlined, does that mid-2018 granularity get you comfortable enough if it kind of falls the way you think with respect to some of the other aspects, whether it's carbon and gas pricing or how you're going to be viewing supply-demand?
We are expecting, to be kind of blunt, any reasonable capacity market would be supportive of continuing in coal or converting the units from coal to natural gas. It's more a case of if there's a bust in the process, we might have an issue. Again, any reasonable market going forward would support the conversion of our facilities at the appropriate time. I think, as Bryan identified, the major issues will be around natural gas pricing, and around the cost of carbon or the realized cost of carbon that will be in place through the next decade.
Got it. Okay. I guess, turning to the renewables call, can you just comment on the state of potential projects within this new partnership? Is there anything that's actually been scoped out, or is it pretty much a blank slate at this point? Whitla has bid in, but it sounds like Halkirk 2 was not. I'm just wondering if there's some color there in terms of whether it was ready or was it a strategic decision to wait to see if you can get some location-based premiums going forward.
It's actually the latter. Now again, given Halkirk's positioning, its real positive attribute is around the fact that the cannibalization of price is much lower at Halkirk than it is in Southern Alberta and in a case like Whitla. Again, the first round of renewables are not going to incorporate the cannibalization, i.e., the Alberta government is going to be paying that. We would see it definitely makes sense going forward for them to, either through zones or some other mechanism, recognize cannibalism, and a project like Halkirk 2 will become much, much more competitive. As it would stand just in straight-up competition, we do expect a very significant amount of competition here in this first round, from a lot of very good wind resources. We don't think that Halkirk 2 would've been competitive.
Okay, just the new partnership?
In terms of the new partnership, in terms of understanding the resource, the solar resource exists today. Certainly, we're looking at nearer-term opportunities around it. We will need probably two-plus years of wind data. It may be less, depending on timing, because one of the things in regards to the reserve is, it borders on two wind farms today. One of them being the Enbridge wind, the 300 MW that was the last significant wind farm built in the province. It has a good wind regime. It's a point of just understanding how good it is and the right placement and so on and so forth. That'll take a couple of years of study before we'd have anything, again, from the wind perspective. From a solar perspective, we're in a good position to respond to opportunities that come forward.
That's great. If I can just finish. There was a comment earlier on Island Generation and the potential to recontract that. I'm just wondering, is there generation at Island Generation right now that's not showing up in the numbers around voltage support? Or just given it's not really producing a whole lot, is there something you expect to change in the BC market as to why that's going to be needed then at that point?
It runs very, very little, and it's only operated for the most part when it's needed to back up the transmission links to the mainland. As far as its need in terms of providing that service, all our discussions with BC Hydro is that will continue as we look out in the future. We don't expect it'll ever have a high capacity factor. Again, it's there when they're doing maintenance on interties with the island or if there's significant issues with generation on the rest of the system.
Okay. That's great. Thank you.
The next question is from Avery Ha of TD Securities. Please go ahead.
Hi, good morning. Just with the recent move in the U.S. CAD FX rate, what are your thoughts on foreign exchange hedging, given your recent diversification efforts into the U.S.?
Generally, our approach has been to maintain a hedge position relative to the exchange rate with the U.S. We look at our projected cash flow margins from our U.S. facilities and what our financial obligations are with some of our U.S. debt placement that we have. We enter positions to basically neutralize our exposure. Effectively, for the most part, any moves we're seeing in the currency is not something that either harms or benefits us.
Okay, thanks for the color. Just moving on towards your power facilities in Alberta. Just with all the potential changes in the market and the importance of portfolio bidding down the road, how important is operating control and your ability to dispatch power from a facility going forward? I guess specifically, if there are any ownership clauses at your jointly owned facilities that allow you to somehow gain control over dispatch at the assets that you currently don't have control over.
Yeah. Having dispatch control will be almost as important in the capacity market as the energy-only market. Certainly, you want to have that ability because you'll still be bidding into an energy market just like we do today. Also you'll be bidding into the capacity component of it. Don't expect the control over the ability to do that offering will change as we roll into the new market. I think, on our JVs, you're going to see everybody want to maintain the control they currently have. I don't see much change on that front.
Okay, thank you.
As a reminder, it is star one to ask a question. The next question is from Jeremy Rosenfield of Industrial Alliance Securities. Please go ahead.
Yeah, thanks. Just a couple of cleanup questions. First, on Shepard, it was a little bit low in the quarter. I was wondering if there was anything specific that had restricted its performance Q2 here.
No, there was nothing physical restricting the performance. We believe that was primarily due to dispatch strategy that our partner, ENMAX, was exercising. Of course, we don't know the details behind that, just based on our observations in the market.
Okay. Just another item. Related to the acquisitions, I think in the disclosure, there was something related to costs in Q2, and I was just curious if there's the expectation that some of the costs related to the acquisitions might drag into Q3 results at all.
No, we don't expect that there are any. Integration has been completed for all the facilities. Certainly, any impact on G&A has been reflected in Q2, and I don't believe there's anything left that'll show up in Q3.
Okay, perfect. Just more from a higher level. With the recent acquisitions, just more strategically thinking in terms of, I guess, deploying more dollars into contracted gas assets, rather than the opportunities obviously in Alberta, you want to see how that market develops. If you look at that incremental dollar being deployed into Alberta versus into other markets, is it really going to continue to be situation specific, or do you still want to try to find additional contracted gas assets, let's say, in the U.S. market?
I think as we've been commenting over the last couple of years, our focus and our priority is on generating contracted long-term cash flow. Certainly, as we look at opportunities, and we see more and more contracted natural gas opportunities, we'll continue to move on those as well as continue, and we'll have the ability to both do that and participate in the Alberta market in terms of builds. Our definite preference for where we put our dollar, assuming reasonable returns on both sides, would continue to be more on the contracted side than it would be on the merchant side in terms of preference.
Do you see a lot of assets, let's say, coming to the market in terms of contracted gas assets that owners are either interested in selling or putting up for bids and that sort of thing?
Yep. We continue to see, I'd say, in the short to medium term, a continuation on that trend.
Okay. Good. That's it. Thanks.
This concludes the question and answer session. I would now like to turn the conference back over to Randy Mah for any closing remarks.
Okay. Thank you for joining us today and for your interest in Capital Power. Have a good day, everyone.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.