Fortis Inc

NYSE:FTS

Earnings Call Transcript 2024-Q1

[Operator]

Good morning, everyone. Thank you for standing by. My name is Ludy, and I will be your conference operator today. Welcome to Fortis Q1 2024 Earnings 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.

[Stephanie Amaimo, executive]

Thank you, Ludy, and good morning, everyone. Welcome to Fortis' First Quarter 2024 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 2024 MD&A. Also unless otherwise specified, all financial information referenced is in Canadian dollars.

With that, I will turn the call over to David.

[David Hutchens, executive]

Thank you, and good morning, everyone. Before getting started, I'd like to introduce Stephanie Raymond to her first earnings call since being appointed President of Central Hudson in April. Stephanie will serve as President until Chris Capone's retirement in October, at which time you will assume full responsibilities as President and CEO. Welcome, Stephanie. We look forward to working with you on the Central Hudson team. For the first quarter, we delivered strong and consistent operational and financial results as our regulated utilities continue to effectively execute their business plans. And with $1.1 billion of capital investments made in the first quarter, our $4.8 billion capital plan for 2024 is on track. Our low-risk growth outlook remains intact and opportunities to expand and extend our plan continue to progress. On the regulatory front, ITC has been focused on the right of first refusal statute in Iowa.

While new ROFR legislation did not advance last month, we remain confident that ITC Midwest has the legal right and obligation to construct the Tranche 1 projects in Iowa assigned through the MISO's long-range transmission plan and associated tariffs. MISO also released its draft tranche two portfolio, including a preliminary project map while we expect further refinements, we view this as a promising step forward. With climate risks at the forefront of the utility sector, the recent release of our 2024 Climate Report was timely, highlighting how Fortis is preparing for and mitigating climate-related impacts across the group of companies.

We continue our long track record of executing our capital plan. These investments in our energy systems support the delivery of cleaner energy and the reliability our customers expect. Our 5-year capital plan of $25 billion remains on track comprising of virtually all regulated investments and a diverse mix of highly executable, low-risk projects. With $7 billion earmarked for cleaner energy investments, we expect to interconnect renewables to the grid, invest in renewable generation and energy storage in Arizona and deliver cleaner fuel solutions in British Columbia.

Rate base is expected to increase by $12 billion to over $49 billion in 2028, supporting average annual rate base growth of 6.3%. Beyond the plan, our utilities continue to advance additional growth opportunities with a couple of key developments during the quarter. As mentioned, MISO released a preliminary map of its LRTP tranche two projects with total transmission investments estimated in the range of USD 17 million to USD 23 billion. While it is too early to estimate the investment opportunities within ITC's footprint, MISO Board approval is anticipated in the second half of 2024.

The preliminary map of projects include 765 kV transmission lines. If approved, these investments would bolster MISO's ability to facilitate the ongoing generation fleet transition, accommodate load growth and address increasingly frequent and severe weather events. We believe this is exactly the forward-looking innovative planning required to deliver a reliable, resilient grid of the future.

In Arizona, the team is working to advance the 2023 integrated resource plans filed by Tucson Electric Power and UNS Electric which requires incremental investments estimated at $2.5 billion to $5 billion through 2038. In late 2023, TEP and UNS Electric released a joint all-source RFP calling for up to 1,500 megawatts of new resources aligned with their respective IRPs. Proposals were received in March and projects are expected to be announced later this year.

In March, the BCUC approved key elements of FortisBC's renewable natural gas or RNG application, requiring that natural gas deliveries to all customers include a portion of RNG. In addition, the BCUC accepted FortisBC's long-term gas resource plan, which outlines FortisBC's plan to serve customers' energy needs transition to a low carbon energy future and support meeting provincial greenhouse gas targets. Overall, we are pleased with this decision as it recognizes the key role that the gas system will play in meeting British Columbia's energy future.

Also in March, the province of British Columbia issued an environmental assessment certificate for the Tilbury Marine jetty project. The construction of the jetty supports the expansion of the Tilbury LNG facility, which is uniquely positioned to meet customer demand for natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment and is close to international shipping lines. Once constructed, the Jetty would make use of FortisBC's assets at the Tilbury site to service Marine Bunkering.

In the U.S., we are seeing momentum build around load growth opportunities. In ITC Midwest footprint Google recently announced plans for a data center to be built in Cedar Rapids, Iowa with a goal of coming online in 2026. The data center will support initial load growth of 300 megawatts and is expected to increase to 600 megawatts over time.

In Michigan and Arizona, we are seeing increasing inquiries related to manufacturing facilities and data centers. Also in Arizona, South 32 continues construction of the zinc and manganese Hermosa mine, which is expected to become one of UNS' largest customers. These developments can provide strong economic growth for our communities and favorably impact customer rates.

During the quarter, we released the 2024 climate report which assesses the impact of climate on our priority assets over multiple scenarios. The report identifies key risks related to climate change, fortis' mitigation activities to address those risks and future opportunities to advance the resilience of our utilities. With a strong track record of increasing dividends for the past 50 consecutive years, coupled with our low-risk growth strategy, we remain confident in our 4% to 6% annual dividend growth guidance through 2028.

Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

[Jocelyn Perry, executive]

Thank you, David, and good morning, everyone. Reported and adjusted earnings per common share for the first quarter of 2024 were $0.93. Adjusted EPS was $0.02 higher than the first quarter of 2023, and key drivers of EPS growth related to rate base growth across our group of companies and the timing of earnings associated with the new cost of capital parameters at FortisBC. Regulated utility growth was tempered by higher corporate costs and weighted average shares outstanding. The disposition of Aitken Creek, which occurred in November 2023 also impacted EPS in the quarter by $0.03. While negative for the quarter, on an annual basis, the disposition of Aitken Creek will be neutral to EPS.

The chart on Slide 10 highlights the EPS drivers for the quarter by segment. Our Western Canadian utilities contributed $0.06 EPS increase; $0.04 related to the timing of the new cost of capital parameters at FortisBC, approved by the BCUC in September 2023 and retroactive to January 2023. Growth also reflected rate base growth and a higher allowed ROE at Fortis Alberta effective January 1.

At our largest utility, ITC, the $0.02 EPS increase was mainly driven by rate base growth. Lower stock-based compensation for ITC was offset by higher holding company finance costs. EPS was $0.01 higher quarter-over-quarter for our U.S. electric and gas utilities, largely driven by rate base growth and the timing of operating costs at Central Hudson.

In Arizona, earnings were largely consistent with the first quarter of 2023. The favorable impacts of new customer rates and higher margins on wholesale sales were offset by higher depreciation and operating costs, and lower retail revenue associated with milder weather. Due to the seasonality of sales, the favorable impact of new customer rates at TEP is expected to be higher in the second and third quarters.

At our Other Electric segment, rate base growth and higher sales contributed a $0.01 increase in EPS. And for our Corporate and Other Segment, the decrease mainly reflects the disposition of Aitken Creek, which I mentioned earlier. The remaining decrease reflects higher holding company finance costs and unrealized losses on derivative contracts. And lastly, higher weighted average shares reflect shares issued under our dividend reinvestment plan. To date, we have not used the ATM program as participation under the DRIP remains strong.

Through April, we have raised approximately $400 million of debt to repay short-term borrowings and fund our capital program. As shown on this slide, we have limited nonregulated debt maturing in 2024 and our $600 million series and preference shares are scheduled to reset at the end of this year.

Overall, we remain in a strong liquidity position as we execute our 5-year capital plan. Our investment-grade credit ratings with Moody's, S&P and DBRS Morningstar remain unchanged. We are on track to achieve an average cash flow to debt metrics of 12% over the next 5 years, and we continue to engage with S&P on our physical risk around climate change.

In March, the Iowa District Court issued an order denying all motions for reconsideration of its decision in relation to the Iowa ROFR. This includes ITC's request for reconsideration with respect to the scope of the injunction for trance one projects in Iowa that were previously awarded to ITC Midwest by MISO. ITC has appealed the District Court's decision to the Iowa Supreme Court.

As discussed last quarter, under the MISO tariff, approximately 70% of the Iowa tranche one projects are upgrades to ITC's facilities along existing rights of way, which under MISO's tariff brands ITC the option to construct the upgrades regardless of the outcome of the appeal.

For any portion of the tranche one projects in Iowa to be competitively bid, we believe a federal decision that significantly departs from existing rules under the MISO tariff is required. Until there is more certainty around the resolution of this matter, we cannot predict the impact on the timing of the capital expenditures related to tranche one projects located in Iowa.

In New York, Central Hudson's 1-year general rate application is progressing. Hearings concluded in the first quarter, and we anticipate a decision from the New York Public Service Commission in July. Last month, FortisBC filed its 2025 through 2027 Rate Framework Proposal with the BCUC. The rate framework builds upon the current multiyear rate plan and includes a prescribed approach for operating expenses and capital, an innovation fund for cleaner energy and continued earnings sharing mechanisms. The regulatory process will continue throughout 2024.

And with that, I'll now turn the call back to David.

[David Hutchens, executive]

To conclude, Fortis is off to a solid start in 2024. We continue to advance our low-risk sustainable growth strategy, underpinned by our diverse regulated energy delivery businesses across North America. Initiatives like our 2024 Climate Report as well as our integrated resource plans in Arizona show our proactive approach on behalf of our customers in identifying and mitigating climate risks and pursuing opportunities to ensure reliable and resilient service.

With preliminary visibility on tranche 2 of the MISO long-range transmission plan, ITC is well positioned to advance investments in its footprint. And with load growth opportunities on the horizon, we are focused on investments that keep energy affordable for our customers. We remain confident in our 5-year capital plan, which supports average annual rate base growth of approximately 6% and our 4% to 6% annual dividend growth guidance through 2028.

That concludes my remarks. I will now turn the call back over to Stephanie.

[Stephanie Amaimo, executive]

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]

[Operator Instructions] And your first question comes from the line of Maurice Choy from RBC Capital Markets.

[Maurice Choy, analyst]

Maybe I'll just kick off with a comment you made earlier, Jocelyn, about how you've engaged the S&P credit rating agency on physical asset risk. As we head into, I guess, for the part this year with potential for higher wildfire risk, can you just compare and contrast the regulatory and legislative set up across your 10 utilities or even just areas where you feel that could be higher versus lower risk?

[Jocelyn Perry, executive]

So Maurice, I'll start off. So yes, we have engaged with S&P, and we continue to do so. And I would characterize up to this stage, we've been sharing information around that in terms of what we're doing from a mitigation point of view, engagements we're having with regulators, how we're working with EEI. So right now, we're just continuing to information share with S&P. As you can appreciate, a lot of our jurisdictions are different with respect to how things are treated from a regulatory perspective. We don't have specific regulatory mechanisms that specifically address wildfires. But we've had wildfires in the past, like in Alberta last year, we had around $10 million of cost in one particular fire and that will be accommodated through the current rate structure that they have.

I will say that given, I'd say, the attention on wildfires, that our subsidiaries are having more conversations and more interactions with regulators so that they fully understand our plans, and that we're just having more engagement generally with the regulators.

So I don't know if I see any one particular area as having more risk than the others. One the benefits of Fortis that we're substantially regulated, we are in good regulatory jurisdictions. We've historically done well in front of the regulator, with respect to how we've managed our utilities and recovered our costs. So I'm not expecting any issue there, but it is evolving as time progressed. David?

[David Hutchens, executive]

Yes. Just to add a little color there, Maurice. Obviously, the fire risk does vary by jurisdiction. And the focus areas have historically been well, I'll say, currently even have been on the Western North America side of the continent here. And that's primarily puts our focus on Alberta, BC and Arizona in that order. But I think one of the things that folks have to understand, too, is the very different legal and liability and regulatory structures between say, BC and Alberta and their structures, which are much more favorable, much more regulated, much more defined on how things are handled from a liability perspective, different legal construct.

All of those things are a very different risk profile than, say, in the U.S. And in the U.S., our exposure's at Arizona, which is has very limited exposure just because of the nature of the assets that we own. We own the majority of our assets are in the Tucson Metro area, which don't have a huge wildfire risk because of -- well, frankly, there are not a lot of trees into the Tucson Metro area or things that necessarily burn.

So it is a very different, I'll say, risk outlook. And we have been spending a lot of time with our teams across all of our subsidiaries, not just those three to make sure we're taking the best practices that we see, not just across our own utilities but across the entire industry and finding ways of mitigating that risk and then getting out there and explaining the great job that we're already doing. But also making sure that we're explaining that to folks like our rating agencies.

[Maurice Choy, analyst]

Got it, And obviously makes sense. And moving quickly over to D.C. with our [indiscernible]. I gather that there were a number of items that -- FortisBC proposed to keep and continue as part of the rate framework. And I wonder if you could share if there's anything in there that's materially different from the current framework. It's clearly a 3-year plan, not a 5-year one. And if there's more of a holding pattern request until we get clarity on how the province will roll out its EPC rules?

[David Hutchens, executive]

Yes. So Maurice, the framework that they filed as I understand, and I'll kick it over here to Roger, but it seemed like almost the exact same mechanisms that we had in the prior, maybe with just a little fine-tuning other than as you mentioned, it's not a 5-year plan. It's a 3-year plan. But Roger, anything to describe this sort of a little bit more out of the ordinary or slightly different from the last MRP?

[Roger Dall’Antonia, executive]

Thanks, David. Thanks, Maurice, for the question. I think David has characterized it correctly. It is a multiyear rate plan, 3 years versus 5. We continue to pursue what we call performance-based structure where our delivery rate or controllable O&M increases by inflation minus the productivity improvement factors. So that structurally same. We've focused again on control O&M and have proposed all the flow-through items for the noncontrollable O&M. I think one area of difference whereas we had escalated base capital or sustaining capital by formula instead here for the utilities, did a 3-year sustaining capital forecast.

However, we've maintained a similar structure on the growth capital that underpins for FortisBC Energy, Inc.'s customer additions. So Overall, the last plan we had, the PVR plan, the MRP plan was quite successful. No reason to vary significantly. I think the one area that we are putting a bit more focus is on things like energy transition, how do we undertake innovative investments, things like that. But more in relation to the policy drivers, not really much different on the underlying rate setting for the basic rates.

[David Hutchens, executive]

And then the other piece, Roger, too, is the fact that we can still file for CPCNs for large projects, which is obviously important for us to do things above and beyond what the underlying MRP structure would allow for.

[Operator]

And your next question comes from the line of Rob Hope from Scotiabank.

[Robert Hope, analyst]

Maybe first off on transmission. It does seem like various levels of the government are very supportive of incremental transmission investments. However, we continue to see challenges on the permitting as well as the legal side there. So when you take a look at tranche one and tranche two and the challenges that we've had there, what is the path forward such that we could see an acceleration of transmission investment at ITC and some of the other kind of Fortis subsidiaries?

[David Hutchens, executive]

Well, I think for sure, we're seeing some good positive results from -- one from the Fiscal Responsibility Act, as you'll recall, that they did some NEPA reforms as part of that, which will simplify and expediate the -- our expedite, I should say, the ability to permit transmission. I think some of the focus on time lines and coordination were really brought home last week when the Department of Energy announced its CITAP Program, which stands for Coordinated Interagency Transmission Authorization and Permitting. And the whole focus there is to cut the time line for permitting on federal projects in half to 2 years.

So those are good positive signals. I should say that in ITC's footprint, it's not typically a lot of federal land that they have to get permits on. So it won't necessarily have a huge impact, at least, as we look backwards on a forward-going basis. It's a good signal and hopefully, you can expedite those types of permits.

But also, there needs to be additional legislation, too, because probably the biggest issue we get in, in delays is the fact that we get all these legal challenges. And the legal challenges can be brought up for very insignificant reasons. And those types of delays and hopefully, some level of legislative solution for that will be what's going to be key for us, for us and everybody else who's developing transmission in the U.S. to be able to get that done faster.

[Robert Hope, analyst]

And then just maybe moving over like a number of your utility peers so far in Q1 have really been talking about kind of increasing load growth in their jurisdictions. When you take a look at your asset base, where are you seeing the greatest uptick in terms of loan?

[David Hutchens, executive]

Yes. So it's mostly in the U.S. and mostly in ITC and UNS' service territories. If you look at the hot spot map of where data centers are looking to locate, you'll see Arizona is one of those spots. You'll see a couple of spots in the Midwest. I mentioned in the prepared remarks, the data centers that are going in, in Iowa. If you listened into other utilities calls like DT and CMS and how they're getting a lot of data center interest in Michigan, while that's our transmission that needs to be built to serve that type of load.

So all of those -- that data center load has different -- I mean we respond to it differently. Like in Arizona, we would be looking to supply any data center that came in one of our utilities there. Since we're vertically integrated utilities, we'd be looking at generation, transmission and distribution, all three functions to serve them. In ITC, it's obviously only transmission. But there's still a lot of growth opportunity out there, not just in data centers, but I think we're starting to see a lot of conversations around manufacturing and siding.

Again, good areas for that are at the Midwest that ITC serves in Arizona, both big, good, strong growth economic development outlooks on a going-forward basis.

[Operator]

And your next question comes from the line of Ben Pham from BMO.

[Benjamin Pham, analyst]

Maybe to continue on the last question around load growth increasing on AI and data centers. Do you expect that to have a meaningful impact on rate base growth going forward, when you think about that setup? And then can you also comment -- I know you mentioned it's more U.S. but any comment on the Canadian opportunity for AI as well?

[David Hutchens, executive]

I'll answer this in reverse. On the Canadian side, we're not really seeing that same kind of conversation from a data center AI perspective. We're not hearing a lot of additional load growth or announcements in our service territories, at least, in Canada. Also probably much less chatter around manufacturing, although there are in some areas quite a bit. In Ontario, that's where we serve this load, but we're seeing some of that economic development around electric vehicle plants and things like that.

We -- there's just a lot more incentives to do it in the U.S. because of the Inflation Reduction Act and the incentives it has for local content. So there's some additional drivers in the U.S. that are pushing us. So what the impact will be is still -- this is still early days. There's obviously a lot of conversation. There's a lot of different data centers, these hyperscalers who are going around looking for places to cite their data centers, which they have siding requirements. They want to be by fiber. They need power, right? So that's, I think, the biggest conversation right now is finding the power or the areas that have power to be able to supply them. It is early days.

I think that they look at multiple sites before they decide on it. So it's too early for us to really have a good feel for that load growth opportunities and the capital that will come with it. And actually, it might, frankly, be a bit more time through the end of this year, you've been to figure out where some of this stuff will land. So it will be a while before we see that making its way through our resource planning process within our utilities and through other processes like LRTPs, et cetera, that MISO goes through.

[Benjamin Pham, analyst]

Okay. And secondly, maybe on the tranche two, the product CapEx opportunity. Anything you can provide directionally in terms of making two of that pie? And when do you think you can be put in the CapEx and potential service dates?

[David Hutchens, executive]

Yes. No. It's too early days. I mean we're still working with draft portfolios. The portfolios have to be finalized, they have to be approved. There are still things moving around. There are still studies to be done. So it's far too early for us to putting numbers out there yet.

[Operator]

Your next question comes from the line of Linda Ezergailis from TD Cowen.

[Linda Ezergailis, analyst]

Sure. Just wondering about your PBR3 appeal in Alberta. Can you comment on any sort of ability to defer capital expenditures until there's more certainty of whether a more prospective approach to capital programs can be taken or how to kind of mitigate some of the uncertainty there? And maybe just talk more generally about some of the inflationary pressures in your capital program and whether they're dissipating.

[David Hutchens, executive]

Yes. So it was a bit disappointing in that latest PBR that we were using that historical look back of the prior year's capital to set the forward rate, which is what we're appealing and what we got to leave to appeal. So I think that was a good result because it is important for us to make sure that we have that, that baseline capital is set at the right level on a going-forward basis. I'll kick it to Janine to have some conversation around inflationary impacts and some other things. But the team there understands what their current situation is, the capital plan that they have submitted.

Obviously, that doesn't mean we don't look at additional opportunities and invest in additional infrastructure. It just means that they may have to trade off different capital within their plan. They might have to prioritize it a little bit different. And worst case, this is the world I lived in, in Arizona was every once in a while, you get a little regulatory lag because you don't get immediate recovery for it.

But if there are investments that need to be done and need to be made on behalf of our customers to provide reliable power to do whatever we might need to do from a resiliency perspective, we make those investments, and then we'll get it on the next round. But Janine, do you want to add a little color on the impact of interest and how you guys would be managing that?

[Janine Sullivan, executive]

Actually, thanks Dave. You've covered it quite nicely. We are planning to execute our 2024 capital plan as we come to understand the various components of the PBR3 plan as they were determined last year. So there's a lot to digest with respect to where we have levers. Where we can manage costs in certain areas to address the shortfall potentially in capital funding. We do plan on bringing or utilizing some elements of the plan with respect to Type 1 capital where we go forward with very specific requests to the AUC while this reconsideration of the methodology that they use to establish capital funding is also ongoing. So certainly, all steam ahead, just continuing to deploy capital as we can and managing our costs as we do so until we see some of these other mechanisms start to apply.

[Operator]

And your next question comes from the line of Michael Sullivan from Wolfe Research.

[Michael Sullivan, analyst]

I'll just try another one on the MISO tranche two map. I know it's a little early, but maybe just relative to how you were feeling when you saw the draft map for tranche one. Does this feel like a better opportunity set or worse?

[David Hutchens, executive]

Yes, I can provide some directional color there. It's there's a lot more lines on the map, and there are different color lines, right? So the 765 kV is exciting. Those are obviously big projects. The size of the overall portfolio, the estimates are, in essence, twice the size of tranche one. So directionally, it's looking pretty good. Obviously, we don't know where those lines will fall down exactly. We're not sure what the final package will look like, but I think we're all very comfortable and confident in saying it's a lot bigger. How that allocates to ITC, that will come out in the wash as we go through the process the rest of this year.

[Michael Sullivan, analyst]

Okay. I appreciate that. That's really helpful. And any chance you could also just give a little more color on just how the legislative session in Iowa ended up playing out? And was it just a matter of time or not enough support? Can you give us another shot next year? Yes, just more color on that would be helpful.

[David Hutchens, executive]

Yes. I think the short answer is it's politics are always a little hard to call exactly how the process is going to work. I think the team did a fantastic job getting up there in front of the legislators, getting the support that's needed. But at some -- periodically, you just can't get the things to be brought up and debated. And when that happens, you just say, "Okay, well, we'll give it a go next time." And I think that's one of our others, there's -- obviously, as Jocelyn mentioned in her prepared comments that what we think about our existing tranche one and why those are and should still be allocated to us and the 70% is in our rights of way.

And I mean we've still got layers and layers of arguments and appeal to boot on those tranche one projects. So it's really so what do we do next? And I think the conversation around looking again next year from an Iowa perspective. Recalling also as we talk about tranche two, we still have our ROFRs in Minnesota and Michigan. Also, you never know where those lines will land, in relation to our existing rights of way.

And as we sit here today, we're just around the corner from FERC putting out their planning and cost allocation rule that will -- which could address some, at least, on a limited basis, some of the federal ROFRs that they, at least, tossed out there in the NOPR. So we'll see where that goes and we'll take that whatever -- I think I've listed about seven different things that, that team is working on related to this, and we'll just stack them up and go through them.

[Michael Sullivan, analyst]

Okay. And last one for me, if you could just update us on the Arizona process and the workshops there that I think have kicked off on trying to improve regulatory lag. How you see that going so far?

[David Hutchens, executive]

Yes, positive. I mean very positive. It's got two different options that they're looking at there. Whether it's a formula rate or a forward test year, each comes with a different sort of batch of questions and issues within the Arizona regulatory and legislative construct. But at the end of the day, it's all positive. It's either one of those is better than a regulatory lag basis that we're working on now. Obviously, we got the SRB, the system reliability benefit mechanism, that allows us basically a capital tracker that we got at UNS Electric. We expect that next time we file a rate case, that TEP will file for one as well. That's a great sort of second place for something like a formula rate.

But -- so with that again, we've got a couple of different options there and we're just glad to see that it was getting traction that after the first workshops that they are looking at continuing them. So that's all positive.

[Operator]

Your next question comes from the line of Mark Jarvi from CIBC Capital Markets.

[Mark Jarvi, analyst]

Just with not full clarity on the ROFR issue, legislative process, the court process, having played out in your favor yet. What does that mean in terms of keeping certain projects in the 5-year plan? What would you need to see or what would happen for you to withdraw that? And then once the lines are drawing and you see the allocation on the tranche two projects in light of the ROFRs not being settled, can you hold back in adding those to 5-year plan? I appreciate that a lot of that comes maybe beyond the 5-year plan. But anything that is within the 5-year plan, is that [indiscernible] you from adding in the near term?

[David Hutchens, executive]

Yes. So as far as timing on tranche one. You might recall that we only have about $1.2 billion out of the $1.4 billion to $1.8 billion, and this is U.S. dollars of the total capital expenditure in the current 5-year plan. So most of these are probably finishing up on the tail end of that 5-year capital plan already and then into the next 2 years. So really, what's happened so far is just kind of delaying or moving some of those in-service dates around a little bit. I don't think that's going to be substantial. It's not going to be -- right now, we're not changing our capital plan based on it because we still fully expect that those will be our projects to build and then when we get into the tranche two conversation, like you mentioned, yes, those are probably at best in the year 5 of the next 5-year capital plan, and then we'll go on from there.

That's more of a conversation about looking at the length that we have in our capital runway. And so it's not necessarily even something that we'll bake it into the next at this next 5-year capital plan because we don't expect those projects to be approved and assigned or allocated until late this year. And of course, we like to update our capital plan in the fall. So it's -- well, we'd love to have quicker and sooner clarity on that. It's going to take some time. And you know us. We don't put it in the capital plan until we really know it's coming. And so we are a bit conservative from that standpoint.

But if we can give any color around the expectations when we put out our capital plan and as we get towards the end of this year, we'll do that. But as always, we want to make sure that we maintain the strong credibility that we have with you all that what we put out in those capital plans, we're going to go out and do. So we'll make sure that we still live by those principles.

[Mark Jarvi, analyst]

And any updated news on just in terms of the mix, again, the rate away assets in terms of the amounts that you've carved there, the $1.2 billion that's in the budget now. Just any refined numbers around how you think that would shake out, if the ROFR was not reinstated?

[David Hutchens, executive]

So in the $1.2 billion or the $141.8 billion total package there, we talk about that 70%. I think that would be -- if everything went against us, I think that's the minimum that we would have. That would be the floor. So I -- that's what we would be thinking right now. But as it stands, we don't think that will be the case. We think we'll have all those projects.

[Operator]

As there are no further questions, I would like to turn the call back to Ms. Amaimo.

[Stephanie Amaimo, executive]

Thank you, Ludy. We have nothing further at this time. Thank you, everyone, for participating in our First Quarter 2024 Results Conference Call. Please contact Investor Relations should you need anything further. Thank you for your time, and have a great day.

[Operator]

Thank you, presenters. And ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.