Fortis Inc. (FTS) Q2 2021 Earnings Report, Transcript and Summary

Welcome to the Fortis Q2 2021 Conference Call and Webcast. During the call, all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Thanks, Stales and good morning everyone. And welcome to Fortis' second quarter 2021 results conference call. I am joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the Senior Management team, as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our second quarter 2021 MD&A. Also, unless otherwise specified, all financial information reference is in Canadian dollars. With that, I will turn the call over to David.

Thank you, and good morning, everyone. The underlying long-term fundamentals of our company remained strong in the second quarter. We continue to see growth from our investments in our regulated utilities maintained reliable service through severe weather events across our footprint, effectively manage the safety of our employees, customers and communities even during this pandemic and started to see the green shoots of economic recovery across our jurisdictions. This solid foundation allows us to withstand and see-through headwinds like the impacts of foreign exchange volatility. Today, we also issued our 2021 sustainability update, which can be found on our website. The report highlights our priorities and progress on sustainability initiatives. Additionally, we announced that Fortis has signed on as a supporter of the taskforce for climate related financial disclosures or TCFD. With the easing of pandemic restrictions and the corresponding reopening of businesses and with a little help from warm weather, our second quarter sales have improved from last year. While uncertainty remains surrounding the pandemic. Increased commercial and industrial activity contributed to an overall increase in sales across our portfolio of utilities. As you may recall, UNS and our other electric segment have the most exposure to changes in sales. Favorable weather in Arizona and higher commercial and industrial sales contributed to a 3% increase in retail sales at UNS. For our other electric segment, sales were up 3% for the quarter, mainly driven by the ongoing recovery of the tourism industry in the Caribbean. Turning to Slide 6, the 2021 sustainability update details the progress we are making to support a cleaner energy future. Notably in 2020, we reduced our Scope 1 emissions by 15%, equating to removing over 400,000 vehicles from the road in just one year. This marks measurable progress towards our target to reduce carbon emissions 75% by 2035 compared to 2019 levels, Transitioning to renewables and building out the grid is at the heart of our long-term strategy. Our update also highlights that in 2020, we achieved our best safety performance and delivered top quartile reliability performance relative to our industry peers, and it also includes 50 new key performance indicators of which 14 align with a Sustainability Accounting Standards Board or SASB. We are pleased to report another step in our ESG journey by expanding our disclosures and solidifying our commitment to the TCFD recommendations by signing on as a supporter. We're continuing our climate scenario analyses to assess the resiliency of our energy delivery businesses, and we expect to provide a progress update in 2022. As Slide 8 highlights nearly all of our $19.6 billion five-year capital plan supports energy delivery and cleaner energy infrastructure. Through the first half of 2021, we make capital investments of $1.7 billion dollars in our systems. And for the full year our $3.8 billion capital plan remains on track. This balanced low risk plan supports our sustainability strategy and includes renewable generation such as wind, solar and battery storage interconnections of renewables and liquefied natural gas and renewable natural gas investments. The capital plan is expected to increase rate base by $10 billion from $30.5 billion in 2020 to over $40 billion in 2025 supporting an average annual rate base growth of approximately 6% through 2025. Slide 9, beyond our base capital plan, our teams continue to push forward with opportunities to expand and extend growth in our regulated utilities for the benefit of our customers. Since we covered this topic extensively last quarter, I will briefly discuss a few recent developments. First at ITC, the proposed Lake Erie connector transmission project continues to progress. In May, the Ontario government authorized the independent electric system operator or ISO to enter into contract negotiations. We are in the early stages of negotiation and the ISO is expected to report back to the government by the end of the year. Earlier this month, [Berk] issued an advanced notice of proposed rulemaking to solicit comments on regional transmission planning, cost allocation and generator interconnection processes. Overall, it's encouraging to see THE Commission's recognition that substantial investments in transmission infrastructure are needed to facilitate a lower carbon future and our teams are actively engaged in these processes. Lastly, at Fortis BC, reducing customer greenhouse gas emissions continues to be a priority. Recently, British Columbia amended their greenhouse gas reduction regulations to allow the increase in the production and use of renewable natural gas as well as hydrogen in the province. The revised regulation will advance the production and distribution of renewable natural gases and hydrogen that will utilize our existing natural gas infrastructure to reduce emissions, and decarbonize our economy. With 47 consecutive years of dividend increases, coupled with our low risk growth strategy, we remain confident in our 6% average annual dividend growth guidance through 2025. Now, I will turn the call over to Jocelyn for an update on our second quarter financial results.

Thank you, David. And good morning, everyone. For the quarter adjusted net earnings was $259 million, or $0.55 per common share $0.01 lower than the second quarter of 2020. Foreign exchange was a significant impact in the quarter. The U.S. dollar to Canadian dollar exchange rate was $1.23 for the quarter compared to $1.39 for the second quarter of 2020. And this unfavorably impacted quarterly results by $0.5. So excluding foreign exchange impacts earnings per share was $0.04 higher, mainly driven by our rate base growth that are regulated utilities and higher earnings in Arizona and the Caribbean. For the six months ended June 2021, adjusted net earnings of $619 million or $1.32 per common share $0.09 higher than the same period in 2020. And this growth was despite the FX impact of $0.07 year-to-date. Excluding the FX impacts earnings per share increased $0.16 reflecting the same factors noted for the quarter, as well as some timing of earnings on retirement investments. new: In New York, Central Hudson increased EPS by a $0.01 driven by rate base growth and lower operating costs incurred related to the pandemic as compared to last year. And at ITC rate base growth mainly contributed to a $0.02 increase in EPS for the quarter. The $0.02 EPS increase in our other electric segment reflects higher sales in the Caribbean with the continued recovery of the tourism industry. At corporate EPS decreased $0.02 mainly due to a higher consolidated state tax rate associated with changes in regional sales mix. And higher weighted average shares outstanding issued through our dividend reinvestment program decreased EPS by $0.01. And as discussed the lower U.S. dollar to Canadian dollar exchange rate unfavorably impacted the quarterly results by $0.05. And although not depicted on the slide, earnings for our Western Canadian utilities were flat for the quarter rate base growth in both Alberta and British Columbia was tempered by the timing of operating expenses at Fortis BC associated with the multi-year rate plan decision last year. Overall strong quarter despite foreign exchange headwinds. Turning to Slide 14, this waterfall breaks down the EPS drivers for the first half of 2021. Our U.S. electric and gas utilities provides the most significant contributions growing EPS by $0.08. Our Arizona business contributed a $0.06 EPS increase. The increase was driven by similar items noted for the quarter again new rates at TEP, warmer weather partially offset by higher operating costs. The impact of losses on retirement investments recognized in 2020 also favorably impacted EPS by $0.02. Central Hudson contributed $0.02 of the increase driven again by rate based growth and lower operating costs combined our Western Canadian regulated utilities and ITC contributed a $0.06 EPS increase driven by rate base growth. At our other electric segment, higher sales in the Caribbean and rate base growth contributed to a $0.02 increase in EPS. And our energy infrastructure segment reported higher hydroelectric production in believes and higher volumes and margins associated with the A concrete natural gas storage facility together they increased EPS by $0.01. As expected with our dividend reinvestment program EPS decreased $0.01 due to higher weighted average shares outstanding. And lastly, a lower U.S. dollar to Canadian dollar exchange rate on favorably impact the results by $0.07 year-to-date. Turning to Slide 15. During the quarter, we were active in the debt capital markets with over $1 billion in long term debt raised at attractive rates that issued at Fortis Inc. mainly refinance maturing debt while our regulated utilities issued debt in support of their capital expenditure programs. More recently ITC price $150 million notes U.S. of which half are actually green notes. With our recent debt issuance, coupled with approximately $4 billion available on our credit facilities, we are in a strong liquidity position supporting our capital plan. And now for an update on our ongoing regulatory proceedings. In June 2021, ITC filed comments in conjunction with the supplemental notice of proposed rulemaking [indiscernible] on incentives. As you may recall, [Berk] is proposing to eliminate the 50 basis points regional transmission organization or RTO ROE adder for utilities like ITC that have been RTO members for more than three years. In its reply, comments, ITC maintain that [Berk’s] proposal is counter to current policy goals to encourage investment in transmission and transition to a cleaner energy future. ITC also highlighted that participation in an RTO provides customers with significant benefits that far outweigh the cost and the current proposal would discourage ongoing efforts to retain and grow RTOs. A timeframe has not been established for [indiscernible] to issue a final rule and any impacts would be prospective. In New York settlement discussions are ongoing and Central Hudson's general rate application and we do still expect a decision later this year. Earlier this year, the British Columbia Utilities Commission initiated a generic cost of capital proceeding for all regulated utilities in BC. Next steps include the BCU is issuing a report with a regulatory timetable including when Fortis BC will file evidence. And lastly, in conjunction with the exploration of Fortis Alberta's current performance base ratemaking or PBR term ending in 2022. The Alberta utilities commission or AUC confirmed that Fortis Alberta will return to a third PBR term beginning in 2024, following the completion of a cost of service rebasing in 2023. The AUC has initiated a new proceeding to consider the design of the third PBR term. That concludes my remarks. And I'll now turn the call back to David.

Thank you, Jocelyn. To conclude our utilities are performing well positioned in us to deliver on our capital and rate based growth objectives for the remainder of the year. And with the progress we've made in 2020 to reduce our already low carbon footprint, we are excited to be part of the solution to transition North America to a cleaner energy future. With the combination of our high quality ESG profile, five-year growth outlook and 6% dividend growth guidance through 2025. We have a balanced low risk value proposition with opportunities to extend growth for the foreseeable future. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, I'd like to open the call to address questions from the investment community.

Thank you. [Operator Instructions] One moment please for the first question. Our first question comes from the line of Maurice Choy with RBC Capital Markets.

Thanks, Stales. And good morning, everyone. Just a quick first question on ITC and transmission investments. I know that back in the Q1 call you mentioned that visibility on initial projects could come as early as this year. And obviously during this past quarter, there have been a lot of announcements from the FERC in the progressing transmission development. And, David, you mentioned your prepared remarks there is obviously a encouraging recognition of the importance of these investments. So I wonder if you could provide us an update on your view of timing with regards to this visibility, as well as any changes to the size of these opportunities?

punch:

And maybe it's a follow up to that. And given you mentioned us, October/December and earlier in the call, you mentioned that the Lake Erie connector to ISO could go back to the government by the end of this year, as you approach your five-year update plan this fall, how do you see your visibility and being able to provide us with updated CapEx plans? Or do we need to wait for more announcements from these parties before we could get a more definitive list?

Yes, we're going to need some more information before we can start lay in these investments. And to be honest, we really want to make sure that we maintain credibility with you all, so that when we put capital in our budget that it's common, that it's real. So we will need to see some visibility like connector and through the MISO planning process before we're going to be able to put those dollars into a five-year capital plan. So we -- that's kind of our -- that's our thing, we want to be as transparent and as credible as we possibly can. So, we can throw out ranges, but those ranges can't make it into a capital plan. Because we really think that that has to show you all what we really honestly believe is going to be there. So it will probably take a little more time we are actually thinking about what exactly is the right timing for that capital plan or you read the release one and then maybe updated later, but that's something that we're still thinking through.

Great and just to finish-off on something that's very exciting. Proposed tax changes in Canada and the U.S. Specifically the interest deductibility limits in Canada and minimum tax in the U.S. any color or any update on either of those funds?

Yes, Maurice, I need the minimum tax in the U.S. seems to not be a concern for Fortis now, because we're going to fall under the thresholds for the size that it relates to, because it applies to the bigger companies. In Canada, yes, there's -- we don't have visibility just yet on the interest deductibility limit. And again, this is really a cash flow thing, because it will limit the amount of interest you can deduct in any one-year, but you can carry it forward. And I know that there's certainly considerable effort in Canada, which we are a part of, to have discussions with the government so that they fully understand that we're pretty capital intensive company where our capital structure is regulated, we have to spend a lot of investments to keep the grid reliable and safe, and certainly with the clean energy investments as well. So there's definitely discussions being had so that everyone fully understands the necessity for investments in this sector as well. So it's still early days, I do believe.

Great, thank you very much.

Our next question comes from the line of Ben Pham with BMO.

Hi, thanks, good morning, I had a couple of questions on your BC utility, we would love an update on where you are on the RNG side of things, any discussions with Woodfibre and on RNG and then also on the Tilbury LNG like I was held to record towards advancements going?

Sure Ben. Yes, it's always a lot of opportunities out there in Fortis BC, such it's such a great gas business and really looking across the full spectrum of things that they can do to be right in the heart of the conversation around reducing greenhouse gases. And so I'm going to actually kick this over to Roger Dall'Antonia, since we have him on the line, and he'll give you a much more detailed and better view of that than I can. Roger.

Thanks, Dave. Good morning, Ben. Can you hear me? Okay?

Okay, okay.

Yes we can.

Great. Yes, so on the first question, RNG, we're making good progress up to the end of Q2, we've got 22 contracts approved by the BCU for RNG, for a total of vote seven petajoules, when we have a couple more contracts, waiting approval, which will bring us over eight petajoules. So two years into our target by 2030, we're making good progress on the acquisition of renewable natural gas. So that's going well. Woodfibre, nothing new in the quarter, we're continuing to work with Woodfiber, and they're still planning to have a definitive view on timing of their project later this year. And then your last question on Tilbury, the environmental assessment process. Earlier this year, we filed the initial project description are preliminary. We are in the what's called the early engagement phase, doing the stakeholder consultation with various stakeholders. We'll take that feedback and hopefully be in a position to file a detailed project description with the environmental assessment office in Q3.

Great, thanks for a fulsome answer. And then maybe on the -- my second question on the energy infrastructure results, that bullish production and storage margins have improved? Would you characterize Q2 results as normal seasonality for the quarter now you're back to the hybrid long-term means and the storage is the seasonality you'd typically expect?

So Ben with respect to the results for B call for the quarter was clearly impacted by rain, right. So we had lower production in Q2 than what I would say is typical. Now that fluctuates, right? Because it fluctuates with the amount of rain and timing of rain. So but I would say that it was low relative to history. And so just a difficult one to predict, obviously.

. Hey, Ben, I want to add something because I think not on the B call, but on Rogers conversation, because I can't believe neither he nor I had mentioned the fact that while we mentioned that the greenhouse gas reduction regulations have allowed for an increased amount of RNG/hydrogen in the systems and for the utilities to actually contract for or produce it themselves. But we never threw out the number though what's out there is the possibility. So it sets the limit at 15%, which for BC is 30 PJ. So when you look at those numbers that Roger was talking about and having the contracts up to eight, we still have a lot of growth opportunity going forward to fill in that remaining 22 PJ's over time.

Okay, thanks for that. And Jocelyn more of our personal production below long-term means still, what about the storage for that are within the range of seasonality is typically seen in the past?

I'm not quite sure how to answer that, Ben, because we've seen it fluctuate, right? Because it -- I know in 2019, we have -- there were some drought conditions in 2019. I think the total year was less than 100 gigawatt hours. But yet in 2020, we went back over 200 gigawatt hours. So far this year, I think we're up somewhere around 79. So depending on the last half of the year, the rain I do believe come later days August, July, August. So that will sort of set us up for knowing how the full year is going to look.

Okay, I will [indiscernible]. Thank you.

Thanks Ben.

Your next question comes from the line of Rob Hope with Scotiabank.

Yes, good morning, everyone. Just want to follow up on the Lake Erie Connector. Can you just kind of outline kind of what discussions are happening now? Like it seems like it was a rather positive and enforceable message that the Minister directed the bureaucrats to start negotiations there, especially given that they're going to be the counterparty to that project. So can you just walk us through kind of next steps on like your project?

Yes, Rob, really, it is just about filling out the contract negotiations. I mean, you start with a term sheet, and you start passing that back and forth. And you get, obviously, the cost allocation, or the returns that we need to see on our investments, the contract the contract terms, the ongoing O&M, it's really just a full term sheet of things to bring in, obviously, how you look at and share risk, both on our pre-construction and construction basis and then operation basis. So it's, pretty much a tip to tail negotiation, it was a great positive signal from the government that they thought that this is a good project, and that they directed ISO to enter into those contract negotiations. But it's sort of that normalized -- I'll say kind of normal contract negotiation process. So be a lot of turns of documents, a lot of turns a term sheets, and then of course, then you get the lawyers involved in a lot of turns of documents. And before we get to a final deal.

Alright, appreciate that. And then, this is a bit of a broader kind of -- and longer term question, just regarding some of the challenges the U.S. electric systems had over the past, we'll call it year/ We continue to see increasing demand for transmission regarding new connection and new renewables, but also kind of reinforcing the grid as well, and connecting the various geographies there. When you take a look at your system, where do you see as kind of the greatest opportunity? Is that the renewable side? Or is it kind of the reliability and ensuring we don't see regions going dark?

Yes, that's a that's a great question. And one that we talk about quite a bit, because, we do tend to focus maybe a bit too much on the flashy stuff, right? Because the flashy stuff nowadays is all about creating a cleaner energy economy in future here in the U.S. and in Canada. But that's, just part of the story. The rest of it has to be how else are we addressing the impacts of climate change, and we're doing a lot of work internally, with our operations folks to evaluate the impact of climate change, obviously, much more severe weather on a going forward basis. As you electrify things that changes everything's from generation down into the distribution, grid, investment thesis all along that entire value chain, you got to strengthen local grids for things like electric vehicles. So there's a lot of store-in and then I forgot, you got to throw in aging infrastructure to these assets aren't getting any younger. So when you look at that full bank of investment opportunities that we have, and you go from interconnecting renewables, the transmission to get them to load, the distribution needs, the resiliency, the reliability, the security investments that you need around, cybersecurity to make sure that all of that system is, now more resilient, charging infrastructure, all of that good stuff, I can't tell you, which is going to win the race, but it's going to be a pretty big feast. Now the trick will be is managing all those investments so that we have affordable rates at the tail end. And that's where the things like electrification, electric vehicles, industry, et cetera, will help out because the more that we electrify the economies, the bigger -- basically, the bigger the pie is to spread out those costs. And when you look at it all together like that, I can't -- I would have to say that the renewables and the transmission to interconnect them will be a big piece. And I mean, the renewables like in Arizona and the transmission, interconnect them at ITC will be the two largest pieces. But the rest of that will fall across every one of our utilities in varying degrees.

Thank you.

You bet Rob.

Your next question comes from the line of Michael Sullivan with Wolfe Research.

Hey, Ron, good morning.

Good morning Michael.

First question was just on -- just first question was, I think last quarter, you guys alluded to maybe some higher CapEx in 2021 is helping to offset the FX headwinds you're seeing. Can you just give a little more color on how that's shaping up?

Yes, it's a bit of cats and dogs to be honest, it's some that are up across a little here and there. So it's not anything big. It's nothing that we could really point to a little here and there. So it's not anything big, it's nothing that we could really point to and say it's a $500 million project that just dropped in, some of its timing shifting around and other others is some slightly, some smaller new project. But yes, I'll miss in that.

Okay, great. And also wanted to get a sense of conviction and where this for FERC NOPR on RTO adders, ultimately ends up just given the latest meeting and some of the commentary, there seemed like you guys thought you had a pretty good case. But just curious if your thinking has changed at all?

Well, I still think we have a really good case and a really good argument. The arguments are absolutely strong that doesn't necessarily maybe [suede] so someone who's got a very specific opinion on the issue. But the arguments are clear. The first one is, RTO is we need them bigger, and we need more of them. And in order -- and the costs associated with the small amount of RTO adders that get passed through to the customers are dwarfed in comparison to the savings and the benefits that the -- that those same customers get by having that RTO they're having the coordination of transmission, planning, development, et cetera as well as the access to the market. So the RTOs has to be bigger, and there has to be more of them and then you got to interconnect them. This is a bit contrary to that. I have to say that probably the other bigger issue, I wouldn't say that there is a big issue. The big issue here is the fact that the Federal Power Act of 2005 actually requires an incentive to be in an RTO. So I think this legal issue will have to run its course. Because it does seem from a philosophical standpoint that several of the commissioners just don't like that adder and wants to look at other ways of incentivizing transmission which there remember, this is just one of a whole laundry list of additional adders that are part of the original NOPR. So this is just addressing a change in the treatment of that RTO adder, which in the additional NOPR as you all know was actually recommending that it goes from 50 basis points to 100 basis points. So now go into zero is obviously a big change. But the thing is 100 basis points around reliability and another 100 basis points around new technology, 50 basis points around efficiency investments and from the transmission perspective, those are all still part of the bigger order as well. But it will be interesting to see how the legal aspects of someone saying well -- we're all saying it, which is, hey, this doesn't comport with the legislation that's supposed to require or that does require an RTO adder for being other participant.

Great, thanks. Thanks for the color there. And my last one, I just wanted to check in on New York and the COVID recovery there is it's still too late to kind of squeeze that into the some of the settlement negotiations. And should we think of that as on a separate track. Yes, just an update on the process there?

Yes, we're still in those settlement negotiations. And, we're hopefully getting towards the tail end of those. But yes, there's it's -- there's no real clear path on how those costs will get recovered. And from the COVID perspective obviously, we immediately -- we wrote those down, so we don't have that new thing on the books related to those COVID costs now. And if -- in some future proceeding, those come back that's great. And we think we have a good argument on why they should come back. And we also have good historical precedents on why some of that should come back, but we don't have any visibility as to how much of that or when.

Great, thanks. Thanks so much.

Thanks, Michael.

Your next question comes from the line the Mark Jarvi with CIBC.

Good morning Mark.

First question is just on the proposed clean energy standard, whether or not that kind of goes for but just wondering what the implications might be for, I guess, probably TEP most importantly, obviously, it seems like to be positive to help decarbonize that utility even faster, but just wondering how that impacts rate base sort of limitations or challenges or anything sort of to come about with that proposal?

Yes, so the clean energy standard, if it gets passed from a Federal Regulation standpoint, Is that while you're talking about the Federal Law?

Yes.

So I think it's actually about in within a couple years of the Arizona Corporation Commission's proposed rules right now on their renewable portfolio standard. So it's 50 in 2030, versus 50 in 2032, which is the Arizona standard, and frankly, we -- in our in our current path that we have laid out in our integrated resource plan will meet both of those. So it will -- we're really looking for -- from an acceleration standpoint, at TEP to have the possibility of maybe accelerating some of those renewable investments that we see later that are closer to a coal plant closure to maybe bring those forward and use a little less coal, keep the capacity, don't get me wrong, we're going to need that capacity, till that shuts -- till we have those shutdown dates. But we might be able to reduce the energy by further more renewables over time. But, we're -- it will all be -- it will be a cost conversation. And that's really what we're waiting for is to see what are in some of the rest of these infrastructure bills, et cetera, that might reduce the cost of renewables, obviously, some other things are going the other way on inflation's and materials may increase the cost of renewables. So we have a lot of that to see before we can accelerate it. And we definitely are really cognizant of the overall rate impact, we got this great story on our timeline of how we're trading those -- the OpEx and fuel costs of fuel the coal plants for investment and return on infrastructure for solar, wind and storage. And we want to make sure that we're keeping those lined up, so that we have a nice, smooth, low cost trajectory, like we see in our integrated resource plan.

So if I just listened to your comments, more on the margin, then you're having really a material impact given the fact that there are some similar alignment between the federal target and the state targets?

Yes, it's -- yes, those -- the difference on from a clean energy standard isn't going to be much, it's really about whether or not we can accelerate it. Because we've talked about this and I got to drop this number, again, because there's a lot of renewables, we just brought on a 250 megawatt wind facility, we just brought in 100 megawatt PPA with 30 megawatts of storage from a solar perspective down there in Arizona, but we still got 2,000 megawatts of renewables and 1,400 megawatts of storage to go before we can get to that 2035 goal. So lots of investment opportunity. And the vast majority is past that five-year plan that we are talking about, as we see here today. So we're trying to figure out how -- where that comes in, is it in that year six will be in our next five year plan? Or is there also the opportunity accelerated just as a reminder the first big coal plant that we have shutting down is in 2027. So we got to make investments to be able to support that shutdown.

Got it. And then just coming back to Lake -- and I don't want to get ahead of ourselves too much. But when you think about that project, like probably you talk about risk management and whatnot. And just current perspective. How do you think about how much has to be contracted, sort of on day one is it the contract the portion has to hit a certain IRR return objective, and then you leave yourself a bit open for some outsiders maybe how you're thinking about that in terms of returns and risk and exposure to any sort of merchant small exposure?

Yes, this is all one big deal. No merchant exposure, one customer signed, sealed and delivered with the [indiscernible] and ISO, they'll be our sole contractor, and it'll take all of it. That's the current contract negotiation that we're in right now.

Got it. Thanks for clarifying.

You’re welcome.

Your next question comes from the line of Andrew Kuske with Credit Suisse.

Thanks, good morning. I guess the first question is for Jocelyn. And it really revolves around the various green financing initiatives received, whether they be bonds or credit facilities with a bunch of sort of adders in the doctrines depending on how long wants to look at it. How do you think about just green financing initiatives with effectively a regulated asset base regulated doctrines and just the capital structure? Like what's the interplay about these initiatives that you could export a greater degree or not?

So if I think if I hear you correctly, Andrew, just asking us about the perspective on our green financings going forward in our regulated utilities. I think you're going to see a lot of it. I mean, we've already started to see the uptake ITC recently was our most recent and that's around interconnecting the renewable resources to the transmission grid. And we're also seeing I think the phase now is called a green [indiscernible] right, we're actually seeing some pricing with this. I do suspect, we're having conversations right across all of our utilities about segregating their capital, to identify where and how they're investing to make the grid greener and stronger even from a reliability perspective, it's all the same. So we're just going to see more of it, and you're going to see it into our credit facilities. And I do think they will evolve a little more with respect to pricing. But so far, we are seeing some positive pricing and investors are wanting us to do this. So yes, it's definitely a trend for more going forward.

That's great, and then maybe just as a follow up to that comment, given the fact that there's investor appetite, and green premium, where effectively ratepayers are going to benefit. Do you see this starting to build into regulatory doctrines and regulatory apps in the future where this is basically going to be required across the board and expected?

I don't think it'd be required, Andrew. But I mean, ultimately, anything we do for -- to reduce costs will ultimately be for the benefit of our customers in ratemaking overtime. And that's the way that regulated ratemaking works. I think, if we have utilities that are not doing this, yes, they could get asked by the regulator as to why they're not doing it. Because this is a market where we could potentially get [indiscernible] for the benefit of customers. So yes, no, I see it as no -- I don't see the regulator's demanding that we do it, but we better have some good reasons as to why we're not doing it. If we're not in this space, which I don't see, I do see we'll be in this space.

Okay, that's very helpful. And then one final one, if I may, and it just comes back to the RNG. Obviously, you've gone a long way on the RNG, that you've got under contract and signed-off by the BCUC still way to go. How do you think those efforts really unfold over the next several years is the commitment and the requirement is a big number? And how does that match up with reallydoctrines?

Yes, that's exactly the plan that the folks over in BC are working on is trying to figure out, the cost curve of these investments and there is -- as we've mentioned, I think, hopefully, like three or four times already, it's balancing the costs with the transition to renewable resources. And that's something that they've got right in the center of their playbook. And they're looking for the opportunities for additional whether it's RNG or hydrogen and making sure that the blend of what we do and how we put it in and at what pace is suitable to the regulators and of course, eventually our customers so that is part of the calculus for sure.

Okay, that's great. Thank you very much.

Your next question comes from the line of David Quezada with Raymond James.

Thanks. Good morning, everyone. My first question here, just on ITC, I'm interested any comments you have on how you prepare for I guess potentially, I guess, increased scale of opportunities going forward with the reforms to electric transmission planning that FREC is rolling out and I guess, Lake Erie going forward, potentially multiple larger projects? Do you need to step up in advance of that opportunity? Or is it still a little premature at this point?

Yes, let me -- well, first-off, good morning, David. Good to hear from you. I'm going to kick that one right over to the Linda who as you know the CEO of ITC. And, she will give you a good view on that.

Yes, good morning, David. Good question. Yes, look, I think is -- we've already taken some steps, what I would say, some sort of realignment, if you will within our planning group to I would say create, if you will, a new subset department, if you will of planning to look at some of the broader regional inter regional opportunities. So, certainly there's some internal realignment to put more priority more focus on these anticipated outcomes. But by and large, we were not at a point yet where we're staffing up. We at this point, we've been working, I would say hand-in-hand or as I've said before, transmission has arrived in terms of its attention and focus, much of what is being discussed and talked about today is sort of in line and consistent with where ITCs priorities and focus have been all along. So a lot of this isn't sort of new or new revelations, much of this is, many of the studies that have been performed are consistent, I think in directionally with where we're going. So not at this point, and certainly to the extent that, when specific projects materialize, we -- our engineering folks or line design or engineering folks, we work hand-in-hand with some major outside outfits consultants, engineering firms to assist. And so we feel as though we're in pretty good stead with some of the internal realignments as well as kind of all along where our focus has been. So I think we are obviously I think feeling pretty comfortable with where we're at and how we're going to get there, certainly on the Lake Erie project, when Lake Erie I think sort of becomes closer to reality. Certainly, there will be further realignment and potentially additional staffing and resources that are necessary to assist with the design, certainly the construction, but most importantly, the ongoing operation and maintenance of that project. But that's certainly those plans have been identified. But certainly, we haven't gotten to the point where we have executed on that.

That's great color. Thank you, Linda. Appreciate that. And maybe just one other follow up for me just on the topic of class inflation on renewables. As it relates to the roll-out in Arizona, I understand that anecdotally, some people in the market are suggesting a 10% to 15% increase in the cost of solar and wind turbine suppliers have also suggested price hikes are coming. Would you say that that's broadly consistent with what you're seeing? Are you actively procuring equipment today, that is the where you're seeing a little bit of cost is there.

There's no doubt that to be honest, David, we're not because we don't have anything that we're basically developing right now, the, projects that I mentioned, also ground and then this [indiscernible] Energy Center was the latter was a PPA. So we had -- we weren't involved or engaged in that. And also ground has been on the books and has been, obviously planned out for years and was being constructed and finished construction before any of these costs increases hit. So as we go forward, though, we -- and we don't have anything really in the immediate queue. So when we go forward and start looking at the timeline and start putting out, RFPs maybe next year or whenever, to start looking out for projects over the next several years. We might see it, but we're -- it's the anecdotal stories that you're hearing as well, and that we're seeing and others in some of the other supply situations that we have.

That's great. Thanks, David. I'll get back in queue.

Okay, thanks.

The next question comes from the line of Matthew Weekes with IA Capital Markets.

Good morning. Thank you for taking my questions. Just focusing on the earnings from the Caribbean. And it looks like it was really quite strong quarter quite a strong rebound there in the Md&A comments, you talked about sort of the recovery in tourism that's happening and then rate based growth as well, were there's sort of any other impacts that you saw there in the quarter for one and then for two, I was wondering if you'd be able to comment as we go through Q3 here now, on the general outlook that you're seeing and the recovery in the Caribbean?

Yes, Matthew, clearly, we are seeing improvement over Q2 of last year, but that was, COVID was pretty intense during Q2, 2020. But even throughout 2020, tourism was obviously impacted with the borders closed. But here we have it now Turks in particular, the borders are wide open. And but we're also even though the borders are not open pursue you see, they are seeing an uptick in the construction market. So there's a lot of new hotels being built. So there's a lot of probably build-off, right for the tourism activity. So we're seeing it in Turks. We're seeing that construction activity in the Caribbean, there's expectation This is going to continue. Clearly we keep watching what everyone else is watching with respect to vaccination roll-outs and the variance in the light but right now we are seeing some positive uptick in those two utilities. And to go forward, I suspect that trend is expected to continue but we're hoping it's going to continue, right, but we're watching it.

Okay, thank you. That's it for me. I'll turn the call back.

Thanks, Matthew.

Our next question comes from the line of Dariusz Lozny with Bank of America.

Hey, good morning. Thank you for taking my question. Just wanted to ask quickly about how you're thinking about resource adequacy in Arizona, I know California is taking some steps of late to potentially limit exports. And just curious how that's informing your long-term planning as you think about Arizona.

Yes, that's -- it's definitely informing our long-term plan and the timing of our coal plant shutdowns. As I mentioned earlier on the call that we're not shutting down anything that provides dispatchable capacity before we have a system in place that we know can replace it. And we've lived through a summer with it. So that's kind of I think, our general principle. And we did take additional actions, even before this summer to make sure that we were able to get additional capacity that we can use to serve our customers. And in the event that we have higher than normal or higher than our historical peak load. Like we actually did set a new peak in June and made it through that because of the -- because of all the preps that the team did in Arizona to make sure that we had those additional resources. So that's something obviously on the front of mind. There's been some, regulatory filings and from California, that in essence are precluding energy that flows through Arizona that continue on or flows through California to continue to Arizona, which we were obviously very distressed about and are actually asking for a rehearing from FERC on that. But it's a regional situation, and we have to look at it like that from a regional perspective. And we have to -- we just have to make sure that our state and in particular, our utility is doing everything we can to protect our customers. But also looking broader and I think this summer was a good indication of that, where California brought on a lot more resources, ones that were shut down, some that were going to shut down, there has been a lot of battery installations out there as well. So I think this is on front of mind and every utilities CEO across the world in essence across North America, because we've seen weather extremes, particularly from the heat perspective, in almost, every area of North America over the past two years. And if you haven't had one, it's coming for you next. So everyone's got to make sure that they're doing what they can to beef up the capacity and the ability to serve that load. And frankly, one of the best ways of doing that, because it doesn't all happen at once is building out those RTOs and then interconnecting them with transmission. And so that's another key conversation that has to fall into that bigger, broader picture around transmission.

Okay, great. Thank you for that detailed answer. One more if I can. And this is just on the quarter, the $0.02 drag that you guys reported at the [indiscernible]? I think I heard at the opening remarks with some of that was like state tax considerations. Is that something that you expect to carry forward in Q3 and Q4? Or is it perhaps more of a timing item between quarters? Just curious how you think about that for the balance of the year?

Yes, no, that's more of a 2021 issue. So following the consolidated state tax, which we elected to do back in 2018, it's a benefit. It's just a lower benefit in 2021. And that's because we had a change up in our regional sales mix. And some of that is obviously driven by COVID. So while it's still a benefit is just a lower benefit in 2021. And $0.02 is all we expect year-over-year. But yes, so it's a 2021 thing, not expecting it for go forward.

Great, thank you very much. I'll turn it back.

Your next question comes from the line of Patrick Kenny with National Bank Financial.

Yes, good morning. I just wanted to check in on the BC wildfire situation and I guess confirmed that you guys haven't experienced any significant damage to your electric infrastructure that might require some near-term capital to repair or I guess worst case scenario, any liabilities that that you might be concerned about?

Yes, actually, thanks for that question, Patrick, that we obviously had some severe weather events across our footprint, whether it's heat fires, droughts, I mean, flooding. We've had it all just in the first couple months of the summer. But I'm going to turn that over to Roger Dall'Antonia, because he gives us daily updates on that and he'll be able to fill you in.

Thanks, Patrick. So, the BC situation still under a state of emergency, I think there's more than 250 active wildfires. Just quickly on the on the gas side of the business. Nothing really directly impacting though we are on alert on the electric side of the business. The area of concern right now for us is in the [indiscernible] area, we have two lines that have been impacted. We have lost transmission structures just recently, because of wildfire fighting service, we haven't gone in and be able to do a full assessment, we do expect there will be quite a few repairs to those structures. No real impact on customers at this point we're able to back feed through other means, but the situation is fluid. The repair will take some time to assess. We don't see any liability issues. We do have Z factor, treatment or exogamous factor treatment for things like this in our rate structure to the extent that we do have significant repairs to meet.

Okay, that's great. I appreciate the update.

Thanks, Patrick.

And thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo for any closing remarks.

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