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Ladies and gentlemen, thank you for standing by. My name is Deborah, and I will be your conference operator today. Welcome to the Fortis Q1 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, Deborah, and good morning, everyone, and welcome to Fortis' First 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 first quarter 2021 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to David.
Thank you, and good morning, everyone. Today, we are pleased to report a strong first quarter. On the financial front, EPS growth was supported by our record capital investments made in 2020 and during the first quarter of this year. Higher earnings in Arizona also contributed to year-over-year earnings growth. On the operations front, our systems continued to perform well with our people focused on delivering safe and reliable service. As a good example of this, in Arizona, our gas and electric utilities maintained reliable service to our customers throughout winter storm Uri that affected so many other surrounding states. It serves as a reminder that planning for the long-term and preserving adequate capacity is critical to the provision of energy service to our customers under an increasingly wide range of circumstances. On the ESG front, we continue to advance key initiatives. As you may have read in our circular, we have 10 current directors and 2 nominees up for election. Assuming all nominees are elected at our annual meeting tomorrow, the Fortis Board will have reached gender parity for the first time in our history. This is a significant milestone in our diversity and inclusion journey. We are also strengthening our compensation metrics with the addition of new ESG-related measures. The metrics are focused on carbon reduction and climate change, building on our corporate-wide target to reduce carbon emissions 75% by 2035. Additionally, we are happy to report that our credit ratings were affirmed by S&P in April and our outlook was revised to stable from negative. And yesterday, DBRS Morningstar upgraded our credit rating from BBB high to A low. These positive developments underscore our financial strength. Lastly, in April, FERC issued a supplemental notice of proposed rule-making on incentives. Effectively, FERC is proposing to eliminate the 50 basis point regional transmission organization or RTO, ROE adder for utilities that have been RTO members for more than 3 years. Not only were we surprised in the reversal of FERC's direction on the RTO adder, but we are extremely disappointed given the important role RTOs play in facilitating a reliable, cost-effective and resilient grid, while enabling clean energy goals. Turning to Slide 5. Through the first quarter, $900 million of capital was invested in our utilities to support resiliency, modernization and cleaner energy projects. For 2021, our $3.8 billion capital plan remains on track. Higher forecasted capital expenditures are expected to offset a lower foreign exchange rate. Recently, we completed the Oso Grande Wind Project to Tucson Electric Power. The 250-megawatt project is the company's largest renewable energy resource with enough power to energize nearly 100,000 homes. The project complements TEP's integrated resource plan, which calls to exit coal and add 2,400 megawatts of new wind and solar power and 1,400 megawatts of energy storage by 2035. And in Ontario, the Wataynikaneyap Transmission Power Project continues to progress. The 1,800 kilometer transmission project is the largest first nation's majority-owned infrastructure project in Canada's history. With this ownership structure, the project is a model for indigenous communities across Canada. Fortis brings a 39% equity interest and its utility expertise as project manager to the partnership. At the end of the first quarter, 850 transmission towers have been installed with approximately 1,100 workers on site, including First Nations' members. The project is on track to be completed in 2023. By replacing diesel fuel generation with cleaner energy from the Ontario grid, the Wataynikaneyap project is estimated to reduce emissions by 6.6 million tons over a 40-year time frame. Additionally, the project is expected to generate significant benefits for First Nations communities, including access to reliable energy supply and economic benefits from construction. We are very thankful for the partnership with First Nations Communities as we work together to realize their vision while advancing the project during the pandemic. As Slide 6 highlights, we expect to invest $19.6 billion in our systems through 2025, with nearly all of our capital supporting energy delivery and the transition to a cleaner energy future, we have a balanced, low-risk plan. Investments, including renewable generation, such as wind, solar and battery storage, interconnections of renewables, liquefied natural gas and renewable natural gas continue to support our sustainability strategy. 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. Beyond the base capital plan, we are focused on incremental opportunities that expand and extend growth. First, at ITC, the: Midcontinent Independent System Operator, or MISO, has initiated a long-range transmission planning process. In March, MISO outlined conceptual maps identifying potential new transmission required to enable more renewable generation in the region. Specific details regarding the size and location of MISO long-range transmission projects remain unknown until the studies are completed. But as Slide 7 highlights, ITC's assets are strategically located to interconnect the Midwest to cleaner energy resources. Also at ITC, the proposed Lake Erie Connector transmission project continues to progress. In April, the Canada Infrastructure Bank announced that it will fund up to 40% of the project cost. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance. The project is expected to bring an estimated $100 million in annual savings to Ontario customers by connecting their grid to the PJM interconnection, the largest electricity market in North America. Additionally, the project is expected to reduce greenhouse gases by up to 3 million tons per year. While the project is fully permitted and shovel-ready, it is not included in the current 5-year plan as we continue to negotiate transmission service agreements. Once finalized, construction of the projects would take 4 years to complete. In Arizona, the team is working to advance its clean energy goals, which requires investments in the range of $4 billion to $6 billion to execute Tucson Electric Power's integrated resource plan. And in British Columbia, we continue to pursue further development of the Tilbury site, long-term contracted LNG opportunities and additional investments required to attain FortisBC's target to reduce customer greenhouse gas emissions thereby 2030. Lastly, the Biden's administration recently released its proposed infrastructure plan calling for carbon-free power from the electricity sector by 2035. This could accelerate capital investments in our U.S. utilities through transmission interconnections at ITC, clean generation and energy storage in Arizona and electric vehicle infrastructure in the 9 U.S. states that we serve today. With a strong track record of increasing dividends for the past 47 consecutive years, 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 first quarter financial results.
Thank you, David, and good morning, everyone. For the quarter, adjusted net earnings was $360 million or $0.77 per common share, $0.09 higher than the first quarter of 2020. As David mentioned, increased rate base at our regulated utilities and higher earnings in Arizona were the main growth drivers for the quarter. Slide 12 highlights EPS drivers for the quarter by segment. Our U.S. electric and gas utilities provided the most significant contribution, growing EPS by $0.05 for the quarter compared to the same period last year. Our Arizona business contributed a $0.04 EPS increase, this was driven by new rates at Tucson Electric Power effective January 1, offset by higher operating costs associated with planned generation maintenance. Additionally, the $0.02 impact of losses on retirement investments recognized in March of 2020, favorably impacted the quarter-over-quarter change. In New York, Central Hudson increased EPS by $0.01, driven mainly by rate base growth and timing of operating costs and the $0.02 EPS increase for both ITC and our Western Canadian utilities was mainly due to rate-base growth. Our energy infrastructure segment contributed a $0.01 EPS increase driven by production at the bleed hydroelectric generating facilities. And in our corporate and other segment, the $0.01 EPS increase mainly reflects losses on foreign exchange contracts that were recognized in the first quarter of last year. This increase was tempered by higher weighted average shares outstanding issued through our dividend reinvestment program. And lastly, a lower U.S. dollar to Canadian dollar exchange rate unfavorably impacted quarterly results by $0.02. All in all, a very strong quarter with minimal financial impacts from the pandemic. Turning now to an update on our credit ratings and liquidity. Earlier this year, we highlighted the significant improvements in our cash flow to debt and holding company debt ratios over the past couple of years. Throughout the pandemic, we have maintained a strong credit profile as our utilities have managed cost and regulatory mechanisms that serve to stabilize cash flows and earnings have operated as expected. As David mentioned, in April, S&P affirmed our A minus issuer credit rating and our BBB+ unsecured debt rating and also revised our outlook to stable from negative. And just yesterday, DBRS Morningstar upgraded our corporate and unsecured debt credit ratings from BBB high to A low. Both rating agencies highlighted our improved credit profile and operational and financial stability throughout the pandemic. Overall, our credit metrics, coupled with Fortis' low business risk profile positions us well within our existing investment-grade credit ratings. And finally, we continue to maintain strong liquidity with over $4 billion available on our credit facilities. Now turning to Slide 14 for an update on our ongoing regulatory proceedings, at ITC, FERC issued a supplemental notice of proposed rule-making related only to the incentive adder for participation in the RTO. Notably, the commission modified the initial note from March 2020, which proposed to increase the RTO adder to 100 basis points. However, the supplemental NOPR now seeks to eliminate the 50 basis point RTO adder for transmission owners that have been a part of the RTO for more than 3 years, including ITC. As David highlighted, we were disappointed with FERC's proposal given the current public policy goals to encourage investment in transmission to enhance grid reliability and transition to a cleaner energy future. We believe utility participation in an RTO provides customers with benefits that far outweigh the cost. ITC is reviewing the supplemental NOPR and will be providing comments, which are due to FERC later this month. There's no stipulated time frame or FERC to issue a final rule and any impacts would be prospective. As a reminder, every 10 basis points change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01. In New York, settlement discussions are ongoing in Central Hudson's general rate application, and we do expect the 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, including our gas and electric businesses. The proceeding is expected to set cost of capital parameters effective January 1, 2022. In March, FortisAlberta received a decision on the 2022 generic cost of capital proceeding, current cost of capital parameters remain in place for 2022. And lastly, in conjunction with the expiration of FortisAlberta's current performance-based rate-making, or PBR term, ending in 2022, and the AUC has initiated a process to gather stakeholder feedback on how a cost of service rebasing can be completed to establish base rates after 2022. Concurrently, the AUC is evaluating the effectiveness of past and current PBR plans to determine whether a third PBR term should be established. Reports on the findings are expected in mid-2021. Before wrapping up my remarks, I would like to discuss the potential implications of the recently proposed tax changes in infrastructure spending. From a U.S. tax perspective, the proposed increase in the corporate tax rate from 21% to 28% if passed, is expected to increase earnings and cash flow as it will have some of the reverse effects of the 2017 U.S. tax reform. The Made in America tax plan also includes proposals to introduce transmission investment tax credits. This is expected to encourage large regional projects, while the newly proposed department of Energy Grid Development Authority should streamline permitting and planning of regional and interregional transmission investment. While not depicted on the slide, the Made in America tax plan also introduces a minimum tax on book income, which could impact timing of cash flows as well as changes to international taxation. The Federal -- the Canadian Federal Government also released its budget last month, including proposed changes to interest deductibility, which could also impact timing of cash flows and changes in international taxation. Draft legislation in both countries has not yet been released. We will continue to assess and we'll provide further information as more details become available. With respect to infrastructure spending, while we recognize the America job plan requires final approval, we are pleased to see a strong focus on the critical role transmission plays in facilitating new renewable generation and grid resiliency. This emphasis on investments in clean energy aligns with Fortis' focus on improving our low carbon footprint and our goal to deliver a cleaner energy future. That concludes my remarks, and I'll now turn the call back to David.
Thank you, Jocelyn. In summary, we remain steadfast in providing safe and reliable service with the safety of our employees and customers top of mind. We have a strong 5-year growth outlook supporting our 6% average annual dividend growth guidance through 2025. And as we look forward, we are optimistic about the growth prospects in our business including the heightened focus on the clean energy transition across North America. 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] Your first question comes from the line of Maurice Choy with RBC Capital Markets.
My first question relates to the FERC NOPR. Recognizing that the RTO adder was obviously the main topic of the supplemental NOPR, but can you discuss the potential upside to ROE from other matters in the March 2020 NOPR, such as the cost-benefit, reliability? And also, how do you see this decision in April impacting the Transco Independent better?
Yes. As you know, the March 2020 incentive NOPR that came out had several different categories, it actually, as you mentioned, on the RTO adder side of things, it actually was increasing that 50 basis point current adder to 100, that was part of that original proposal, which is why we are so surprised with that switch of going from 50 to 100 and then to 0. But it also included another 100 basis points for reliability projects. 100 basis points for new technology and then another 50 basis point for projects that improved efficiency or reduced costs. So overall, there was 350 basis points of additional incentive opportunities there on a project-by-project basis. Although within that NOPR, it did cap the total of any 1 project at 250 basis points. So we obviously are very strong proponents of looking at ways to incentivize new transmission on a going-forward basis. Again, surprised that, that it's the RTO reduction, but frankly, it's early days. It is just a NOPR. Basically, we have the original NOPR and the supplemental NOPR sitting here at basically a bid-ask spread of 0 and 100. So we don't know where that will end up, and we will obviously make comments accordingly on the importance of the RTO adder for trends for basically for getting people inside those RTOs. It is extremely important to recognize that the bigger the markets are, the lower the costs are, the higher the reliability and the more renewable energy that we can integrate into the system. So we really think that, that was wrong direction to send. On the independence adder, we've been fighting those for a while, and I don't think this provides us any additional insight on where that might go.
Great. And maybe related to that, on my second question. Your outlook comments noted that there were obviously further expansion in terms of electric transmission grid in the U.S. and that visibility on initial projects could be as early as this year. Can you elaborate a little bit more about this visibility? Where do you see this growth coming from? And also timing in terms of how potential projects could fall within -- or just a little bit outside of your 5-year plan?
Yes. So I'll turn this over to Linda Apsey, the CEO of ITC here in a second. Just real high level. MISO is in that planning process, and they put out -- there's a ton of great information on their website related to the -- basically, these 3 different futures that they are analyzing that will have different percentages of renewable integration as well as different growth scenarios. I would point out, though, that when you look at those futures, even the most aggressive, one might seem a little bit stale these days as we have cranked up our level of greenhouse gas reductions in the United States, at least the targets that we're putting out there from the Biden administration. So even that might be, I would say -- I wouldn't say conservative, but might not be as aggressive as what we might see over the next 20 years because it is that 20-year outlook. I would suggest there might be the need for a future for to see if we actually followed the Biden energy plan and had those -- that 50%, 50% to 52% greenhouse gas reductions by 2030 and what that would look like. But I'll turn it over to Linda so that she can tell us about the time frame and expectations there.
Great. Thanks, Dave. Yes, as Dave mentioned, I would characterize MISO as perhaps the most advanced in their long-range planning efforts. And as Dave I think outlined in terms of the different features, the different scenarios, we are expecting MISO to announce kind of their, what I would call their basket or portfolio of first-mover projects later this year, probably in the October time frame. And the hope is that there would be a sort of a set of projects, these first-mover projects that would be included in MISO's, their MTEP plan that's their annual transmission expansion plan that goes to their Board of Directors for approval. So if all goes as planned and as indicated, we could anticipate seeing a portfolio of projects in the latter part of this year. I would say, consistent with that, there is a group of MISO transmission owners that is also advancing principles around cost allocation that would be coincident with the projects that are put forth. I think as we have talked about previously, the biggest sort of hurdles, if you will, to realizing these regional transmission projects, obviously, the planning, collaboration coordination, but certainly also having a cost allocation methodology that can realize the projects that are put forth. So we are very optimistic, given, I would say, a lot of the activity, the conversation, the collaboration, the engagement across MISO. And so certainly, I think as Dave suggested, I think as we move forward, we'll continue to see MISO refine their future studies based on assumptions around penetration of renewable levels. But overall, very optimistic on the MISO planning process. And meanwhile, SPP, they too are actively engaged and involved in a long-term transmission planning effort, not quite the same visibility at this point in time in terms of timing, but again, I would say all of this is in a very constructive positive direction.
And your next question comes from the line of Linda Ezergailis with TD Securities.
Looking at some of the recent positive actions from some of the debt rating agencies, I'm wondering when you expect to next get an update from Moody's and what sort of changes, if any, might come on that front? And I guess as a follow-up question. I'm just wondering how the debt rating agencies reflect some of the uncertainties around the FERC NOPR, the -- recently, the Biden infrastructure plan, some of the proposed tax changes in Canada and U.S., there's a few moving parts. And I'm just wondering how that's reflected in their base outlook and scenarios?
Linda, it's Jocelyn. Yes. With respect to Moody's next update, I would suspect it will be over the next couple of months. We have recently met with all 3 rating agencies, DBRS, S&P and Moody's, just to give them an update on our annual 2020 results. So a lot of those discussions went very well and as you can see in this quarter, we did receive an upgrade from DBRS and the negative outlook was removed from S&P, which we were pleased about. Our conversations with Moody's were good, and I can't predict the outcome of that, but I'm not anticipating much change there. Like I said, I think all rating agencies were pleased with the improvements that we've moved in our balance sheet over the last couple of years. So we had good discussions. With respect to how they reflect the NOPR, you've probably seen, I think it was S&P came out with some commentary around the NOPR that suggested that they would expect the NOPR, if approved, would temper cash flow metrics for Fortis, down to the lower end of the range but not drive us down below the range, which is a fair point, if that is the only thing that's approved in isolation of everything else. So they recognize that. They're all aware of the NOPR. They're all aware of the Biden infrastructure plan. They're all aware of the tax. But as you say, they're moving pieces, and it's hard to nail down exactly what any of them potentially mean. And Fortis has worked through this in the past, and I envision we're going to work through all of this going forward. So no real red flags here with the credit rating agencies, and we'll continue to communicate with them and keep them apprised of any developments.
And as a follow-up with respect to some of these additional potential opportunities, Tilbury, like Erie Connector, et cetera, if they were to reach a positive FID this year, what are the thoughts on how they might be optimally financed?
For the Tilbury?
Well just generally adding like additive to your already pretty robust rate base growth outlook. Just wondering where the incremental capital might come from?
Yes. No, sorry, Linda. Yes. No, you're right. We've also stated that when we looked at our $19.6 billion capital plan, we were expecting that the DRIP would be a little bit of a lower participation. But as you know, participation is back up to, I'm going to say, pre-1990 -- 2019 levels. So back up to that 35% participation. So we'll have some extra capacity under our DRIP. And I've always said that if we're in a position where we're growing even faster than that then I say this to David all the time, everything goes back on the table from a funding perspective. But right now, we do have some current flexibility with our DRIP program, giving us extra, above than what we thought when we set that $19.6 billion plans.
And just a question around your cash flows from operations. Notice that your accounts receivable is creeping up a little bit, recognizing that there's been some relief provided to customers during the pandemic what's the outlook and the trend for whether that might continue to grow through the year, whether that might be recovered through regulatory mechanisms over time or potentially stay flat for a while? How might we think of that trending?
Linda, that's a great question. And last year, certainly, with the start of the pandemic, it was an area that a lot of companies focused on, no doubt, including Fortis. We did see an increase in receivables last year. I do feel like we've -- it's hard to predict entirely, but I do feel that we're in a good place right now. We adjusted our reserves to reflect the fact that our receivables were increasing feel that we've hit a plateau and that we're in a good spot. And we're not seeing it worsen, which I think is a very good point. Clearly, we're all looking for this pandemic to be over and to get back to more normal operations, and we're not going to take our eye off of this, but I would say that, yes, you are correct. We did see it increase, but we're starting to see it levelized, and we're in a good position from how we provided for that in the previous year.
I would just add to that probably the 2 utilities that are most exposed to that, that don't have the regulatory mechanisms defined as clearly as others would be UNS and CH. And I'd add that as we're coming out of the pandemic here, those are 2 of the states that are probably coming out pretty quick here. So we would expect that positive recovery to obviously impact us in a positive manner from a customer payment perspective.
And your next question will come from the line of Rob Hope with Scotiabank.
First question just on the Lake Erie Connector. So it looks like the Feds are on board with the project. However, we still need to offtake, which we expect will be driven by the provincial government. Are the Feds talking to the provincial government is the Canadian infrastructure bank's kind of actions a precursor to contracts there? Or maybe more broadly, where are we in that project right now?
Yes. So we can't really tell exactly what's going on behind the scenes, but we're obviously having a lot of conversations with the provincial government in Ontario there related to this project. But having the federal government involved in having the Canada infrastructure bank come out in support of this project, I think, is all very positive for us to progress that project. It's a great project. I mean, just laid out there. It's got a great savings story. It's got a great greenhouse gas reduction story. It's got a great reliability story. It is a really, really good project. This is kind of the things that when you think about big transmission projects in interconnect markets that we should be focused on longer term. In fact, this is one of them that's called out specifically and in 1 of the most recent studies that show all these basically shovel-ready projects that are raring to go. Lake Erie Connector was on that list. So yes, we think that the positive momentum, the positive conversations among government, whether it's at the state or provincial level, are going to do nothing other than help us get this project move and get TSAs finalized and get -- I was going to say wires in the air, but it's actually wire underwater. So we're looking forward to starting this project.
All right. And then I just want to go back to the NOPR. Glic was out yesterday saying I was battled by the criticism of the changes of the NOPR and that you didn't need an incentive to be part of an RTO. However, you also mentioned that if you need to incent transmission, there would be kind of other ways to do it, including a higher base ROE. So could this NOPR change then kind of once again lead to another fulsome review of the ROE for ITC?
Yes, Rob, I don't think -- I wouldn't go that far on the tail end of your question there. This basically brings up the base ROE conversation again. But I'll point out a couple of things. First, reading the sense from Danielle and Chatterjee, Commissioners Danielle and Commissioner Chatterjee, related to this RTO adder removal is very insightful. There's a couple of points. One, they obviously argue the reason for having this RTO adder from a market perspective to -- we need bigger markets, as I mentioned before, that is the solution to integrating renewables. We need bigger markets. We need more participants, the bigger the market, the better cost allocation is, the better reliability is, the more renewable energy we can integrate. That should be the key focus, which is -- that leads me to the second point, which is both Commissioners Danielle and Chatterjee bring up is legally, the Federal Power Act requires that there is an incentive to participate in the RTO. And there is 14 years of precedent that is related to exactly doing that. So it's odd that this would be a focus of a supplemental NOPR and we obviously will make comments that I think will sound a lot like the decence from those 2 -- the 2 minority commissioners there. So we -- while it is -- I understand commissioners, commissioner Glic's opinion that this is a different mechanism than the project incentives. I think our answer is, yes, but you need both. One is for projects, the other is for RTO participation. Those are 2 very different incentives. And you got to make sure you have both, especially given the accelerated renewable energy transition that we're trying to push across the United States under the current Biden administration.
And your next question comes from the line of Mark Jarvi with CIBC Capital Markets.
Just wanted to go to the transmission tax credits. I'm wondering that have you gone through them, your understanding of how broadly applicable there might be things like they come into fold in terms of Lake Erie project? And then any idea in terms of loosely quantifying what could impact you said, it could be positive to EPS and cash flow?
Yes. So the question there is around the investment tax credits for transmission projects on a going-forward basis because there is a lot of incentives and a lot of the tension being paid on transmission. Obviously, the -- when you look at the infrastructure plan and the $100 billion of set aside basically for grid upgrades to improve both regional and interregional transmission. There's loan guarantees. There's obviously structural changes that they're making to try to get things permitted more quickly partnerships between DOE and DOT down here in the U.S., a lot of that stuff. And obviously, tax credits are going to be part of that overall push towards new transmission projects as well. I'm going to kick that to Linda to talk a little bit about. But generally, what we see from a tax credit perspective from a transmission perspective is this will hopefully bring some of those projects that might be around the edges into fruition. It might be the thing that puts some of these projects over the edge from an economic standpoint. Do you have any additional color on that, Linda?
Yes, Dave, not a whole lot of additional color. I mean, certainly, we're still awaiting sort of further clarity or insight in terms of specifically how would those projects that may be eligible for the investment tax credit, how would they come to fruition? There's talk about sort of you can sort of make some options around kind of taking advantage of the tax benefit. I think the positive news is that we see all of these things, not only a positive from a tax perspective. But certainly, we do not view them as eroding any -- the rate base of the project. But more to come. The details, I think, are still pretty great at this point in time. But I think overall, and most importantly, I think it's just all of the positive momentum around incentivizing transmission. Obviously, from our perspective, whether that be through sort of the FERC avenue in perspective or whether it be through tax incentives. So I think more to come as the sort of the legislative proposals gets more substantives, we'll be able to, I think, share more information on that on that.
But just based on those comments, it seems like it's based on what ITC is contemplating what's in your outlook. It wouldn't be a lot to be more on the fringe as opposed to a lot of your core investments?
Yes, that's correct. I mean we would envision that the typical, what I would call regional transmission projects would continue to go through the RTO planning process be included in a rate base, I suppose if there are some projects that meet certain criteria that perhaps legislation specifies than perhaps those could be -- they could take advantage of the tax credit. But as we sit here right now, our belief is that most of the sort of what I would call traditional regulated transmission projects will continue to go through the RTO planning process and that perhaps there will be sort of other definition or categories of transmission projects that meet certain criteria that may be eligible for certain tax benefits. But like I said, all of those details have not been developed yet, so we're going to have to continue to work with congressional folks, the administration to help kind of flush those details out.
Okay. Got it. And then Jocelyn, the question is for you. I know you still are looking for a lot more details around some of the proposed tax changes here in Canada and the U.S. But if you had to say one versus the other is being potentially more impactful, is it the U.S. changes on minimum taxes, international tax treatment? Or any kind of comments in terms of the relative impact of what you've seen so far from those proposals?
So Mark, that's a tough question because we have limited information, both in the U.S. and in Canada. But when you look at the impacts for Fortis, the increase in taxes is a pretty -- is a simpler one because we're going to likely see partial reversal of what we had seen with U.S. tax reform. So we will see an increase in taxes, increase in cash flow. When it comes to the, like interest deductibility limits in Canada and the 15% minimum tax in the U.S., both of those are going to be driven by how they define tax EBITDA or the minimum book income. So -- and we don't really have clarity on that, just cash flow on that particular one, but still important, it will be timing of cash flow. But it's hard for us to say which one is really going to be more impactful because it's going to depend on the definitions, I think.
Okay. And then just one last question around the NOPR. If it was passed as it's been proposed today, would there be any retroactive adjustments or you just be solely on a go-forward basis in terms of impact on your rates and revenues?
Yes. It's solely on a going-forward basis.
And your next question comes from the line of Michael Sullivan with Wolfe Research.
I first wanted to just ask on the CapEx plan. You guys noted for the year that higher CapEx could potentially offset FX headwinds. Where would that be coming from? And how material could that be?
It's coming from a couple of different places this year. Some has to do with the timing of Oso Grande investments that we have made, basically some that leaked over from 2020 into 2021 and getting that project completed. There's a little bit additional at the Wataynikaneyap project as well and also a Scotia of it at FortisAlberta. So right now, those 3 pieces are basically covering the FX delta between what we had in the -- what we used for the $19.6 billion capital budget and this year's capital budget and what the current rate is.
Got you. Okay. And then kind of similarly, if the NOPR does -- and sorry to be a dead horse on this, but if the NOPR were to -- the supplemental NOPR were to go forward as proposed, are there any potential offsets that you guys would have there to the, I guess, $0.05 or so of downside?
Yes. I mean it's the offset and the growth that we're always looking for. This is really about not just focusing on the ROE, the adders, the incentives, all of that stuff. That obviously is extremely important. And definitely, the topic de jure, that's for sure. But what we have to look at, too, is longer term. How we're going to be growing that transmission business. I mean, as I mentioned previously, just all of the effort around building up the transmission system. Everybody is in alignment on the need for additional transmission infrastructure for us to even -- even to have a prayer of becoming -- getting close to meeting the clean energy transition targets that we are putting out in the United States. So it's really -- there's 2 different topics. That's the return side of things, but the other is what we call the pie side of things. And this pie is going to be growing enormously. So we have to see basically how those 2 are going to balance out. And as we talked about from a transmission planning process, MISO is in the middle of SPPs, getting after it. Obviously, a lot of independent transmission investments are going on throughout the United States. We have to take a look at that bigger, broader picture, see how that applies to things that we can invest in. And then put that whole story together. Unfortunately, you're probably chomping at a bit like we are trying to figure out how much of this is out there, but it will take some time for us to figure this out. And then we'll have a better balance of that growth and return picture on a going-forward basis.
Okay. Appreciate the color there. And then my last question was back to the Lake Erie project. Any better sense or clarity on how long the TSAs could take? Like what is within the balance of the year reasonable? And would you guys get AFUDC on that once it starts construction?
Yes. I would have pined on that, but I don't want to get in trouble with Linda and putting out a date that she doesn't agree with. So I'm going to shoot straight to her to answer that one.
Yes. Thanks, Dave. Certainly, we're hopeful that we can continue to see progress and that we can reach an agreement within the coming months by the end of the year. But certainly, as you can imagine, with any type of negotiation in 2 party negotiation, it takes 2 of us, obviously, to come to term. So are we hopeful, is it possible? Absolutely. And I'm sorry, I cannot specifically answer the AFUDC question. I don't know, maybe perhaps Jocelyn can.
Yes. No, Mike, that's all part of one same negotiations of the whole project cost and how we finance that. But it's a nonregulated business, as you know, Michael.
Your next question comes from the line of Andrew Kuske with Crédit Suisse.
Maybe if we could just focus a little bit on Arizona. And obviously, there's some pretty big capital plans there from Intel, TSMC, among others, this just naturally happens in the state, but with those 2 semi-manufacturers, it's very big capital. It looks like it falls outside of your service territory. But could you maybe give us a little bit of color and context on opportunities you think will happen just from the capital flows into the state?
Yes, Andrew, that's a great question. And a lot of times, when you look at some of the economic data in Arizona. It's obviously driven mostly around the Phoenix area, Maricopa County, which is obviously one of the fastest growing, if not the fastest-growing county in all of the U.S. Some of that does leak out to areas around the Phoenix area down into Arizona. We have seen an increase in economic development inquiries in Southern Arizona. We have an economic development organization that both me and Susan Gray the new President and CEO of UNS Energy are both part of. So we are seeing some visibility into that. And we do see that we're going to -- and it is Arizona. I mean, this is a strong growth state. And will continue to be a strong growth state on a going-forward basis. And we obviously are looking to attract as much business as we can. Economic development is the best of all things from a utility standpoint that's what brings in customer growth that actually brings in KWH with it so that when you're investing to add these customers, you're adding the usage to the to the formula as well. And some of these larger customers like the Rosemont mine that's still sitting out there, waiting to get through its legal hurdles and get started. Those big customers like that are beneficial for our overall customer base and our rates because we can spread those costs out among more customers and more kilowatt hours.
That's helpful context. And maybe just still staying within the state, do you foresee any opportunities to do renewable generation outside of your existing rate base activities? To maybe support corporate customers that are seeking to have cleaner power?
Yes. We actually just announced this week when we brought when we brought the big solar project at NextEra built for us a 100-megawatt project with a 30-megawatt battery and of course, the Oso Grande project as well. We actually earmarked some of those some of those kilowatt hours for -- not -- for our University of Arizona, we entered into a long-term contract with them to provide them with 100% renewable energy, which is one of the biggest -- it's the biggest deal like that with a public university in the United States. So we're really proud of that deal. We're always looking at ways to meet our customers' needs. And if there's additional renewable energy that they're looking for and that we can invest in and that we can get a long-term contract that points back to those resources, we're always looking at things like that, always have been and always will be there's also other utilities within our footprint in our control area, smaller municipalities, co-ops, et cetera, that are always opportunities for that as well. But those are things we look at, not something we have a laser focus on, but always looking to help out our customers and look for investments around the edges, even if they are unregulated or we like to call contracted energy infrastructure deals.
And your next question comes from the line of Elias Foscolos with IA Capital.
Just want to focus on the capital plan and potential inflationary pressure that you might see on it. So I was wondering if you could provide some color on that. And just also comment on the ability to absorb any sort of increases in the rate base?
Well, that's a great question because there's a combination of impacts when we look at our capital plan. Well, every year, we lock down a capital plan, show it to our investors, and then, of course, they're already working on the next one. So there will be, as we go forward, and we look at this next capital plan that we'll roll out in the fall for the next 5-year period, it will be a combination of things that go in there related to inflationary. We redo budgets on these all the time. Obviously, the shorter-term contracts are much more known. Some of that exposure might be hedged with on tracks or commodity, et cetera. But on a going-forward basis, that goes all back into the pot with the additional fine-tuning of project definitions and of course, the addition of new projects as we go. So we -- I probably don't have a clear view on where that might go from an inflationary pressure perspective, whether that drives the capital up of course, there's FX impacts as well. And then when you look at it from a funding perspective, as Jocelyn noted, we have the DRIP program that we're getting really strong participation. And so all of those pieces will go back in to tell that story when we roll it out later this fall.
Okay. I know it wasn't an easy question, but it was one that I wanted to ask. And you kind of alluded to this, so I'll just make this the last follow-up. You probably have some internal tolerances on the capital plan. Should we really expect one about 6 months from now? Or if you think you're moving outside those boundaries, is there a possibility that we might get an update earlier? And I'll leave it at that.
Yes, there's always the option to give an update early if something big happens, right? I mean we wouldn't completely redo a 5-year forecast. But if -- let's just say, if Lake Erie Connector, which is not in our 5-year capital plan, drops in and we can get that thing moving. We're going to tell you, we're not going to wait until September, October, whenever we're going to do our Investor Day to let that cat out of the bag. It's just more of the pieces behind it. The inflationary changes, the commodity price changes. Remember, a lot of the stuff that we do is infrastructure, right? So it's copper, it's steel, it's all of those things, and we're going to have to take a hard look at what those -- how those have changed and what that does to our capital budget on a going-forward basis. But anything big, we'll let you know the stuff that's kind of the details behind the scenes of rolling up a capital plan, you probably don't want us to be giving you too often updates on that.
And you next question comes from the line of Patrick Kenny with National Bank.
Just looking at the long-term decarbonizing plan for FortisBC, wondering if you could provide just an update on your progress to integrate RNG, hydrogen, even some of the carbon capture initiatives that are starting to come with the surface here? I know we still got a ways to go to 2030, but would you say things are tracking on pace with your original targets or has there been any variance either way?
Yes. I'll kick that to Roger for some of the details. I was just actually on a House of Commons Natural Resource subcommittee on this topic. Last week about -- from a Canadian perspective, the opportunities for looking at clean fuels. And of course, our topic was around the use of both hydrogen and renewable natural gas in our gas systems. And FortisBC, which is a leader in this area has really been doing some great work that we probably don't tout loud enough on what we're doing from, one, from an RNG perspective and the projects that we have in the queue there. And then also the R&D and the behind the scenes things that we're looking at from a hydrogen perspective. So I'll turn that over to Roger to add a little bit of color there.
Thanks, David. Appreciate the question. So on the RNG front, we've got a good line of sight to the 15% RNG target by 2030, we now have about 6 petajoules of agreements that are signed and approved by the BCUC. Those have to be built or the off-taker on those agreements. But they are signed and approved, and we have another 3 pending VCC approval. So we have about 8 petajoules ready to go with a number of projects that we have identified and are in negotiations to sign. So we feel that we've got a very good start on the 2030 target for RNG. And continue to make good progress there. Hydrogen is a little bit -- we're more in now, what I would say is the development phase. We've got a number of projects underway. We have a joint initiative with other utilities on technical feasibility study for hydrogen blending in BC. We have a pilot project with a large industrial site to use renewable hydrogen production to blend into the gas site, the gas supply for that industrial site. And we are looking at some northern BC blue hydrogen carbon capture opportunities to decarbonize the gas system. So quite a bit of activity in this area, the BC government is helping to find with the industry a hydrogen study. We're also working federally with our industry peers on advancing hydrogen standards and development as well. So quite a bit of progress on that front.
Okay. Great. That and then maybe just sticking with Western Canada, given the headlines here in Alberta and the challenges in controlling the case numbers. And I guess your peers implementing a rate freeze over the next couple of years. Not sure if you guys are considering the same or perhaps looking at other opportunities more on the social side to help out your Alberta customers?
Yes. I'll turn that over and actually introduce Janine Sullivan, who's the new President and CEO of Fortis Alberta. But yes, we obviously recognize with our folks on the ground there in Alberta, just the tough time that the province is having on several fronts. And obviously, I was just hearing yesterday on another call that Alberta has, I think, if this is right, that they currently have the highest per capita number of cases in North America. And so that's obviously a concern of ours. There's nothing more important to making sure that our employees and customers and communities are safe and that we're doing everything we possibly can to protect them and to taking all the precautions that we need to as a company to not just keep providing our service, but making sure that our employees and customers are safe and are taking those right precautions. Obviously, economic impacts from COVID from the shutdowns. There's a lot of every one of our jurisdictions has gone through it in different time periods and to different extents. And Fortis Alberta seems to be the tip of the spear on where that's focused now. So I'll turn that over to Janine and have her explain what we may be looking at doing there for our Albertan customers.
Thanks, Dave. And yes, we're certainly very cognizant of the challenges that are going on in Alberta right now, particularly as COVID continues to ramp up and really post some issues for our customers. We're really cognizant of the heightened focus on the cost of delivered electricity in the province and the conversation that our customers are having with the regulator and with government. And we've been a part of those conversations, and we're staying close to them. There have been some proposals as to how it can be addressed. And of course, we're watching how those play out and assessing those in light of our own specific circumstances and working on proposals as to how we might approach it in the coming months, particularly as we work through this approach to resetting rates for 2023 at the end of this PBR term. So there's some opportunities coming where we will continue to work through options available to us and seeing how those have been put out already play out and how they're received and how they might work to address the issues at hand.
As there are no further questions in the queue, I would now like to turn the conference over to Ms. Amaimo for closing remarks.
Thank you, Deborah. We have nothing further at this time. Thank you, everyone, for participating in our first quarter 2021 results call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.
Thank you for participating, ladies and gentlemen. This concludes today's conference. You may disconnect your lines.