Fortis Inc
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Fortis Inc
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Ladies and gentlemen, thank you for standing by. My name is Phyllis, and I will be your conference operator today. Welcome to the Fortis Q2 2021 Conference Call and Webcast. [Operator Instructions]At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.
Thanks, Phyllis, and good morning, everyone, and welcome to Fortis' Second Quarter 2021 Results Conference Call. I'm 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 remains 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 managed 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 impact 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 Task Force on 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 1 year. This marks measurable progress towards our target to reduce carbon emissions of 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 the 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 are 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 5-year capital plan supports energy delivery and cleaner Energy Infrastructure. Through the first half of 2021, we made capital investments of $1.7 billion 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 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 at 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 and made the Ontario government authorize the Independent Electric System Operator, or IESO, to enter into contract negotiations. We are in the early stages of negotiation, and the IESO is expected to report back to the government by the end of the year.Earlier this month, FERC issued an Advance 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 FortisBC, 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 $0.05. So excluding foreign exchange impacts, earnings per share was $0.04 higher mainly driven by our rate base growth at our regulated utilities and higher earnings in Arizona and the Caribbean.For the 6 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 impact, earnings per share increased $0.16, reflecting the same factors noted for the quarter as well as some timing of earnings on retirement investments.Slide 13 highlights EPS drivers for the quarter by segment. Our U.S. electric and gas utilities increased EPS by $0.03 for the quarter. Our Arizona business contributed $0.02 driven by new rates at Tucson Electric Power effective January 2021 and warmer weather. June was actually, in fact, one of the hottest June months on record in Arizona. Earnings in Arizona were tempered by higher planned maintenance costs primarily at Springerville.In New York, Central Hudson increased EPS by $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, a lower U.S. dollar to Canadian dollar exchange rate unfavorably impacted the quarterly results by $0.05.And although not depicted on this 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 FortisBC associated with the multiyear rate plan decision last year. Overall, a 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 provided 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 on 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 base 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 Belize and higher volumes and margins associated with the Aitken Creek 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 unfavorably impacted 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. Debt issued at Fortis Inc. mainly refinanced maturing debt, while our regulated utilities issued debt in support of their capital expenditure programs. More recently, ITC priced USD 150 million notes, of which half were 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, or NOPR, on incentives. As you may recall, FERC 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 3 years.In its reply comments, ITC maintained that FERC'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 time frame has not been established for FERC to issue a final rule and any impact would be prospective.In New York, settlement discussions are ongoing in 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 general cost of capital proceeding for all regulated utilities in BC. Next steps include the BCUC issuing a report with a regulatory timetable, including when FortisBC will file evidence.And lastly, in conjunction with the expiration of FortisAlberta's current performance-based ratemaking, or PBR, term ending in 2022, the Alberta Utilities Commission, or AUC, confirmed that FortisAlberta 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. I'll now turn the call back to David.
Thank you, Jocelyn. To conclude, our utilities are performing well, positioning us to deliver on our capital and rate base 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, 5-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, we'd like to open the call to address questions from the investment community.
[Operator Instructions] Our first question comes from the line of Maurice Choy with RBC Capital Markets.
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 in your prepared remarks, there's obviously 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.
Yes. Maurice, thanks for that question. It's obviously the question that we're all trying to answer as quickly as possible. We're seeing a lot -- I mean a lot of positive indications from FERC related to trying to remove some of the obstacles to the rapid development of transmission that's going to be needed to interconnect the renewables for the goals that the administration down here in the U.S. has.Now that being said, it still has -- the process still has to be gone through. And particularly from a MISO perspective and their long-range transmission plan, there's been no update to those kind of later this year, sort of October time frame for that initial list of projects to come out and then even potentially an approval of those by the MISO Board in December. But those time frames are obviously a bit up in the air. I can't think that they can accelerate them too fast. Even with all the positive momentum around FERC, it's still going to take some time to, in essence, punch through all the details and all the planning that's required to put those projects together.
And maybe just a follow-up to that and given you mentioned October/December, and earlier in the call, you mentioned that the Lake Erie Connector, the IESO could go back to the government by end of this year. As you approach your 5-year update plan this fall, how do you see your visibility in 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 laying 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, you know that it's coming, that it's real. So we will need to see some visibility like Erie Connector and through the MISO planning process before we're going to be able to put those dollars into a 5-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 release one and then maybe update it 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 fronts?
Yes. Maurice, I think the minimum tax in the U.S. seems to not be a concern for Fortis now because we're going to fall under the threshold 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 1 year, but you can carry it forward. And I know that there's certainly a considerable effort in Canada, which we are a part of, to have discussions with the government so that they fully understand that we're a pretty capital-intensive company. We're -- 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.
Our next question comes from the line of Ben Pham with BMO.
I had a couple of questions on your BC utility. Would love an update on where you are in the RNG side of things. Any discussions with Woodfibre on LNG? And then also on your Tilbury LNG, like how's the regulatory advances going?
Sure, Ben. Yes, it's always a lot of opportunities out there in FortisBC, 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. Ben, can you hear me okay?
Yes. We can hear you.
Yes.
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 BCUC for RNG for a total of about 7 petajoules, and we have a couple of more contracts waiting approval which will bring us over 8 petajoules. So 2 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 Woodfibre and they're still planning to have a definitive view on timing of the project later this year.And then your last question on Tilbury, the environmental assessment process. Earlier this year, we filed the initial project description or 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.
All right. Great. And then maybe on the -- my second question on the Energy Infrastructure results. You know that Belize production and storage margins, they can -- have improved. Would you characterize Q2 results as normal seasonality for the quarter now you're back to the hydro long-term means and the storage is the [ not ] you typically expect?
So Ben, let me speak to the results for BECOL for the quarter, it 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.
Ben, I want to add something because I think -- not on the BECOL, but on Roger's 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 it or produce it themselves, but we never threw out the number, though, what's out there as 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 8, we still have a lot of growth opportunity going forward to fill in that remaining 22 PJs over time.
Okay. And just more follow-up. So production's below long-term means still. What about the storage spreads that are within the range of seasonality that you've seen in the past?
I'm not quite sure how to answer that, Ben, because we've seen it fluctuate, right? Because I know in 2019, we had -- there were some drought conditions in 2019. And I think the total year was less than 100 gigawatt hours. But yet in 2020, we went back over 200 gigawatt hours. So, 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, comes later, say, August -- July, August, so that will sort of set us up for knowing how the full year is going to look.
Your next question comes from the line of Rob Hope with Scotiabank.
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 rather positive and forceful message that the minister directed to [ bureaucrat ] to start negotiations there, especially given that they're going to be the counterparty to that approach. So can you just walk us through kind of next steps on Lake Erie project?
Yes, Rob. Really, it is just about filling out the contract negotiations. I mean you start with the 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 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 a preconstruction and a construction basis, on an 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 IESO to enter into those contract negotiations. But it's sort of that normal -- I'll say, kind of normal contract negotiation process. So there'll be a lot of turns of documents, a lot of term sheets. And then, of course, then you get the lawyers involved and a lot of turns of documents and -- before we get to a final deal.
All right. 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 of new renewables, but also kind of reinforcement of 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 it the renewable side? Or is it kind of the reliability in ensuring we don't see regions going dark?
Yes. 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 the 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 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.And then -- and I forgot, you got to throw in aging infrastructure, too. 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 piece. 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 interconnection at ITC will be the 2 largest pieces. But the rest of that will fall across every one of our utilities in varying degrees.
Your next question comes from the line of Michael Sullivan with Wolfe Research.
First question was just on -- just -- first question was, I think, last quarter, you guys alluded to maybe some higher CapEx, and 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, some that are up across the -- 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 it's timing shifting around and others is some slightly some smaller new projects. But yes, all this and that.
Okay. Great. And I also wanted to get a sense of conviction and where this FERC NOPR on RTO adders ultimately ends up. Just given the latest meeting and some of the commentary there, it seemed like you guys thought you had a pretty good case. But just curious if your thinking there 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 sway someone who's got a very specific opinion on the issue. But the arguments are clear. The first one is the RTOs, 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 customers are dwarfed in comparison to the savings and the benefits that those same customers get by having that RTO there, having the coordination of transmission planning, development, et cetera, as well as the access to the market. So RTOs have 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 they're -- 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 well know, was actually recommending that it goes from 50 basis points to 100 basis points.So now going to 0 is obviously a big change. But the thing -- the 100 basis points around reliability and another 100 basis around new technology, 50 basis points around efficiency investments from a 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 a participant."
Great. And my last one, I just wanted to check in on New York and the COVID recovery there. Is it 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, 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 anything 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.
Your next question comes from the line of Mark Jarvi with CIBC.
First question is just on the proposed clean energy standard, whether or not that it kind of goes forward. But just wondering what the implications might be for, I guess, probably TEP, most importantly. Obviously, it seems like it would be positive to help decarbonize that utility even faster. But just wondering how that impacts rate base and 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 why you're talking about, the federal one, Mark?
Yes. Yes, yes.
So I think it's actually about in -- within a couple of years of the Arizona Corporation Commission's proposed rules right now on their renewable portfolio standards. So it's 50 in 2030 versus 50 in 2032, which is the Arizona standard. And frankly, we -- in our current path that we have laid out in our integrated resource plan, we'll meet both of those.So what 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 until we have those shutdown dates. But we might be able to reduce the energy by feathering in more renewables over time. But we're -- 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 of the things are going the other way on inflations in materials that 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 time line of how we're trading those, the OpEx and fuel -- cost of fuel or 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 listen to your comments, more on the margin than having really a material impact given the fact that there's some similar alignment between the federal target and 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 a 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 5-year plan that we are talking about as we sit here today. So we're trying to figure out how -- where that comes in. Is it in that year 6? Will it be in our next 5-year plan? Or is there also the opportunity to accelerate it? 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 Erie again. I mean I don't want to get ahead of ourselves too much, but when you think about that project like from -- you talked about risk management and whatnot and just return perspective. How do you think about how much has to be contracted sort of on day 1? Is it that -- the contracted portion has to hit a certain IRR return objective and then you leave yourself maybe a bit open for some upside? Just 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 a bow. So it's us and IESO. 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.
Your next question comes from the line of Andrew Kuske with Credit Suisse.
I guess the first question is for Jocelyn, and it really revolves around the various green financing initiatives [ achieved ], whether they be bonds or credit facilities with a bunch of sort of adders in them, or deducters, depending on how one 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 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 uptick. 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 phrase now is called the greenium, 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 a green premium, where effectively rate payers 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 will be required, Andrew. But I mean, ultimately, anything we do to reduce costs will ultimately be for the benefit of our customers and ratemaking over time. And that's the way that the regulated ratemaking works. I think if we have utilities that are not doing this, yes, they could get asked by their regulator as to why they're not doing it because this is a market where we could potentially get a greenium for the benefit of customers.So yes -- no, I see there's no -- I don't see the regulators 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 a way to go. How do you think that will unfold over the next several years? The commitment and the requirement is a big number, and how does that match up with really prudency doctrines?
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 3 or 4 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.
Your next question comes from the line of David Quezada with Raymond James.
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 FERC is rolling out. And I guess Lake Erie going forward, potentially multiple larger projects. Do you need to staff up in advance of that opportunity? Or is it still a little premature at this point?
Yes. Let me -- well, first off, David, good to hear from you. I'm going to kick that one right over to Linda, who's, as you know, our -- the CEO of ITC, and she'll give you a good view on that.
Yes. David, good question. Yes, look, I think it's -- we've already taken some steps, 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, I mean, we're not at a point yet where we're staffing up. We -- at this point, we've been working, I would say, hand in hand. 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 ITC's 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, and 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 -- our line design, our 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're 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, Linda. Appreciate that. And maybe just one other follow-up from me just on the topic of cost inflation on renewables as it relates to the rollout in Arizona. I understand that, anecdotally, some people in the [ market ] are suggesting a 10% to 15% increase in the cost of solar. And some wind turbine suppliers have also suggested price hikes are coming. Would you say that that's broadly consistent with what you're seeing? And are you actively procuring equipment today that is -- where you're seeing a little bit of cost creep there?
No. 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, Oso Grande and then this Wilmot Energy Center, the latter was a PPA so we had -- we weren't involved or engaged in that. And Oso Grande has been on the books and has been obviously planned out for years and was being constructed and finished construction before any of these cost increases hit.So as we go forward though -- and we don't have anything really in the immediate Q. So when we go forward and start looking at the time line 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 in others -- in some of the other supply situations that we have.
Our next question comes from the line of Matthew Weekes with IA Capital Markets.
Just focusing on the earnings from the Caribbean, and it looked like it was really quite a 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 base growth as well. Were there 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, I think clearly, we are seeing improvements over Q2 of last year. But that was -- COVID was pretty intense during Q2 of 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 for CUC, 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 buildup, right, for the tourism activity.So we're seeing it in Turks. We're seeing the 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 rollouts and the variants and the like. But right now, we are seeing some positive uptick in those 2 utilities. And to go forward, I suspect that, that trend is expected to continue. And we're hoping it's going to continue, right? But we're watching it.
Our next question comes from the line of Dariusz Lozny with Bank of America.
Just wanted to ask quickly about how you're thinking about resource adequacy in Arizona. I know California has taken 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. 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 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 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 flow through Arizona to continue -- 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, 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 -- of every utility CEO across the -- well, in essence, across North America because we've seen weather extremes, particularly from a heat perspective, in almost every area of North America over the past 2 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. One more, if I can, and this is just on the quarter. The $0.02 drag that you guys reported at the parent, I think I heard in the opening remarks that some of that was like state tax considerations. Is that something that you expect to carry forward in Q3 and 4? Or is it perhaps more of a timing item between quarters? 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, it's 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.
Your next question comes from the line of Patrick Kenny with National Bank Financial.
Just wanted to check in on the BC wildfire situation and, I guess, confirm 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 you might be concerned about?
Yes. Actually, thanks for that question, Patrick. We obviously have had some severe weather events across our footprint, whether it's heat, fires, drought, I mean, flooding, we've had it all just in the first couple of 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. Yes, so the BC situation still under a state of emergency. I think there's more than 250 active wildfires. Just quickly on the gas side of the business, nothing really directly impacting, though we are on alert the electric side of the business. The area of concern right now for us is in the South Okanagan, around the Osoyoos Oliver area. We have 2 lines that have been impacted. We have lost transmission structures just recently. Because of the 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 were 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 exogenous factor treatment for things like this in our rate structure to the extent that we do have significant repairs to make.
As there are no further questions, I would like to turn the call back to Ms. Amaimo for any closing remarks.
Thank you, Phyllis. We have nothing further at this time. Thank you for participating in our second quarter 2021 results call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.