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. During the call, all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation. At that time, those with questions should press star followed by the number one on their telephone. If at any time during the conference you need to reach an operator, please press star zero. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Miss Amaimo. 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 slideshow. 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 US 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. 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 she 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. 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 2 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 five-year capital plan of CAD 25 billion remains on track, comprising of virtually all regulated investments and a diverse mix of highly executable, low-risk projects. With CAD 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 CAD 12 billion to over CAD 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 2 projects, with total transmission investments estimated in the range of $17 billion-$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 includes 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-$5 billion through 2038. In late 2023, TEP and UNS Electric released a joint all-source RFP, calling for up to 1,500 MW 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 lanes. 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 MW and is expected to increase to 600 MW over time. In Michigan and Arizona, we are seeing increasing inquiries related to manufacturing facilities and data centers. Also, in Arizona, South32 continues construction of the zinc and manganese Hermosa Mine, which is expected to become one of UNS's 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's 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%-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. Thank you, David, and good morning, everyone. Reported and adjusted earnings per common share for the first quarter of 2024 were CAD 0.93. Adjusted EPS was CAD 0.02 higher than the first quarter of 2023, and key drivers of EPS growth related to rate based 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 CAD 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 a CAD 0.06 EPS increase, CAD 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-based- growth and a higher allowed ROE at FortisAlberta, effective January 1. At our largest utility, ITC, the CAD 0.02 EPS increase was mainly driven by rate-based growth. Lower stock-based compensation for ITC was offset by higher holding company finance costs. EPS was CAD 0.01 higher quarter-over-quarter for our U.S. electric and gas utilities, largely driven by rate-based 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-based growth and higher sales contributed a CAD 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 CAD 400 million of debt to repay short-term borrowings and fund our capital program. As shown on this slide, we have limited non-regulated debt maturing in 2024, and our CAD 600 million Series M preference shares are scheduled to reset at the end of this year. Overall, we remain in a strong liquidity position as we execute our five-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 five 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 Tranche 1 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 1 projects are upgrades to ITC's facilities along existing rights of way, which under MISO's tariff, grants ITC the option to construct the upgrades regardless of the outcome of the appeal. For any portion of the Tranche 1 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 1 projects located in Iowa. In New York, Central Hudson's one-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 multi-year 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. With that, I'll now turn the call back to David. 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. With load growth opportunities on the horizon, we are focused on investments that keep energy affordable for our customers. We remain confident in our five-year capital plan, which supports average annual rate-based growth of approximately 6% and our 4%-6% annual dividend growth guidance through 2028. That concludes my remarks. 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. Thank you. We will now conduct a question-and-answer period. If you would like to register a question, please press the star followed by the number one on your telephone. If your question has been answered and you would like to withdraw your registration, please press the star followed by the number two. If you're using a speakerphone, please keep your handset before entering your request. And we kindly request you speak loudly and slowly to ensure all participants can hear your questions. One moment, please, for your first question. And your first question comes from the line of Maurice Choy from RBC Capital Markets. Your line is open. Good morning, everyone. 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, the later part of this year with potential for higher wildfire risk, can you just compare and contrast the regulatory and legislative setup across your 10 utilities or even just areas where you feel there could be higher versus lower risk? 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, you know, engagements we're having with, you know, 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 CAD 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 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, you know, 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, where we. One of the benefits of Fortis is 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. Yeah, 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, on the Western North America side of the continent here. And that 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 US. In the U.S., our exposure is at Arizona, which 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 in the Tucson metro area or things that necessarily burn. It is a very different, I'll say, risk outlook. 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. Got it. Thanks. Thanks for that, and this makes sense. Then moving quickly over to BC with our regulatory, I gather that there were a number of items that Fortis BC 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 three-year plan, not a five-year one, and there's more of a holding pattern request until you get clarity on how the province will roll out its CleanBC rules. Yeah. So, Maurice, there, there. The framework that they've 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 five-year plan, it's a three-year plan. But, Roger, anything to describe that sort of a little bit more out of the ordinary or slightly different from the last MRP? You know what? Thanks, David. Thanks, Maurice, for the question. I think David is characterized it correctly. It is a multi-rate plan, three years versus five. We've continued to pursue what we call a performance-based structure, where our delivery rate or controllable O&M increases by an inflation minus the productivity improvement factor, so that structure is the same. We've focused again on controllable O&M and have proposed all the flow-through items for the non-controllable O&M. I think one area of difference, whereas we had escalated base capital or sustaining capital by formula, we instead here for the utilities did a three-year sustaining capital forecast. However, we've maintained a similar structure on the growth capital that underpins FortisBC Energy Inc. customer additions. So overall, the last plan we had, the PBR 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. And then the other piece, Roger, too, is, you know, 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. Perfect. Makes sense. Thank you very much. Thanks, Maurice. Thank you. And your next question comes from the line of Rob Hope from Scotiabank. Your line is open. Good morning, everyone. Maybe first off on transmission. You know, it does seem like various levels of government are very supportive of incremental transmission investments. However, you know, we continue to see challenges on the permitting, as well as the legal side there. So, you know, when you take a look at Tranche 1 and Tranche 2, and the challenges that we've had there, you know, what is the path forward such that, you know, we could see an acceleration of transmission investment at ITC and some of the other kind of, Fortis, subsidiaries? Well, I think for sure we're seeing some good positive results from the Fiscal Responsibility Act, as you'll recall, that they did some NEPA reforms as part of that, which will simplify and expedite, I should say, the ability to permit transmission. I think some of the focus on timelines 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 timeline for permitting for on federal projects in half to two years. So those are good, positive signals. I should say that, you know, 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 can expedite those types of permits. But also there needs to be additional legislation, too, because the probably the biggest issue we get in delays is the fact that we get all these legal challenges, and the legal challenges can be brought up, you know, for very insignificant reasons. Those types of delays, and hopefully some level of legislative solution for that, will be what's gonna 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. Thanks for that. And then just maybe moving over, like, a number of your utility peers so far in Q1 have really been talking of kind of increasing load growth in their, you know, jurisdictions. You know, when you take a look at your asset base, where are you seeing the, you know, the greatest uptick in terms of load? Yeah. So it's mostly in the U.S., and mostly in ITC and UNS, UNS service territories. If you look at the hotspot map of where data centers are looking to locate, you'll see Arizona is one of those spots. You'll see a couple spots in the Midwest. I mentioned in the prepared remarks, the data centers that are going in in Iowa. If you've listened into other utilities calls, like DTE and CMS, and how they're getting a lot of data center interest, in Michigan, well, that's our transmission that needs to be built to serve that type of load. So all of those, you know, 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, you know, 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 siting. Again, good, good areas for that are at the Midwest, that ITC serves and Arizona. Both big, big, good, strong growth, economic development outlooks on a going-forward basis. Thank you. Your next question comes from the line of Ben Pham from BMO. Your line is open. Hi, thanks. Good morning. 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-based 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? Thank you. I'm gonna... I'll answer this in reverse. On the Canadian side, we're not really seeing that same kind of conversation, from a data center, you know, AI, perspective. We're not, 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, you know, we're not that we serve this load, but we're, we're seeing some of that economic development around electric vehicle plants and things like that. We just- 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, you know, additional drivers in the U.S. that are pushing this. 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, you know, different data centers, these hyperscalers who are going around looking for places to site their data centers, which, you know, they have siting requirements. They want to be by fiber. They, in fact, need power, right? So that's the, 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, you know, frankly, be a bit more time, you know, through the end of this year, even, to figure out where some of this stuff will land. So it'll 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. Okay, thank you for that. And then secondly, maybe on the tranche to the broader CapEx opportunity. Anything you can provide directionally in terms of magnitude of that pie? And when you think you can maybe put in the CapEx and potential service dates? Yeah, no, it's too early days. I mean, that we're still working with draft portfolios. You know, the portfolios have to be finalized, they have to be approved. There's still things moving around. There's still studies to be done. So it's far too early for us to be putting numbers out there yet. Okay, got it. Thank you. Thank you. And once again, if you would like to ask a question, please press star, followed by the number one on your telephone. Your next question comes from the line of Linda Ezergailis from TD Cowen. Your line is open. 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, 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. Yeah. 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 the lead to appeal. So I think that was a good result because it is important for us to make sure that we have that baseline capital set at the right level on a going-forward basis. You know, I'll kick it to Janine to add some conversation around, you know, inflationary impacts and some other things. But, you know, the team there, you know, understands, you know, what their current situation is, the capital plan that they have submitted. Obviously, that doesn't mean we don't look at, you know, additional opportunities and invest in additional infrastructure. It just means that, you know, they, they may have to trade off different capital within their plan. They might have to prioritize it a little bit different. And, you know, worst case, this is the world I lived in, in Arizona, was, you know, every once in a while you get a little regulatory lag because you don't get immediate recovery for it. But if they're—if they are investments that need to be done and need to be made on behalf of our customers to provide reliable, you know, power to, you know, do whatever we might need to do from a resiliency perspective, we make those investments, and then we'll, we'll, we'll get it, we'll get it on the next round. Janine, do you want to add a little color on the, you know, impact of interest and how you guys would be managing that? 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, you know, 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. Certainly, full 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. Thanks, Janine. Thank you. Your next question comes from the line of Mike- Michael Sullivan from Wolfe Research. Your line is open. Hey, good morning. Hey, Michael. Yeah. Hey, hey, Dave. I'll just try another one on the MISO Tranche 2 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 1, does this feel like, you know, better opportunity set or worse? Oh, yeah, yeah, I can, I can provide some directional color there. There's a lot more lines on the map, and they're different color lines, right? So the 765 kV is exciting. Those are obviously big projects. You know, the size of the overall portfolio, the estimates are, in essence, twice the size of Tranche 1. 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, you know, that'll come out in the wash as we go through the process the rest of this year. Okay, I appreciate that. That's really helpful. And any chance you could also just give a little color on, 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 this another shot next year? Yeah, just more color around that would be helpful. ... Yeah, I think the short answer is, you know, it's politics are always a little hard to call exactly how the process is gonna 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, you know, 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, we'll give it a go next time." And I think that's, you know, one of our. Oh, there's, you know, obviously, as Jocelyn mentioned in her prepared comments, that's what we think about our existing Tranche 1 and, you know, why those are and should still be allocated to us, and the 70% that's in our rights of way. And, I mean, we've still got, you know, layers and layers of arguments and an appeal to boot on those Tranche 1 projects. So, it's really, so what do we do next? I think the conversation around, you know, looking again next year from an Iowa perspective, recalling also, as we talk about Tranche 2, we still have our ROFRs in Minnesota and Michigan. Also, you know, you never know where those lines will land in relation to our existing rights of way. And as we sit here today, we're, you know, just around the corner from FERC putting out their planning and cost allocation rule that will, you know, 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, you know, that whatever. I listed about seven different things that that team's working on, related to this, and we'll just, you know, stack them up and go through them. Okay, thanks. 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? Yeah, 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. This is, it's you know, either one of those is better than a regulatory lag basis that we're working on now. You know, 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 at TEP, we'll file for one as well. That's a great sort of second place for something like a Formula Rate. But so, again, we've got a couple 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. Thanks so much. Appreciate it. Thank you. Your next question comes from the line of Mark Jarvi from CIBC Capital Markets. Your line is open. Yeah, thanks. Morning, everyone. Just with not full clarity on the ROFR issue, legislative process, the court process haven't played out in your favor yet, what does that mean in terms of keeping certain projects in the five-year plan? What would you need to see, or what would happen for you to withdraw that? And then, you know, once the lines are drawn and, and you see the allocation on the Tranche 2 projects in light of the ROFR issues not being settled, do you hold back in adding those to the five-year plan? I, I appreciate a lot of that comes maybe beyond the five-year plan, but anything that is within the five-year plan, does that preclude you from adding in the near term? Yeah. So, as far as timing on Tranche 1, you might recall that we only have about $1.2 billion out of the $1.4-$1.8 billion, and this is US dollars, of the total capital expenditure in the current five-year plan. So, most of these are probably finishing up on the tail end of that five-year capital plan already and then into the next two years. So really, what's happened so far is just kind of delaying or, you know, moving some of those in-service dates around a little bit. I don't think that's gonna be substantial. It's not gonna be... You know, 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 2 conversation, like you mentioned, yeah, those are probably at best in the, you know, year five of the next five-year capital plan, and then we'll go on from there. That's more of a conversation about looking at the length and that we have in our capital runway. And so it's not necessarily even something that will make it into the next, this next five-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'd like to update our capital plan in the fall. So, it's... Well, we'd love to have, you know, quicker and sooner clarity on that. It's gonna take some time. You know us, we don't put it in the capital plan until we really know it's coming. So we are, you know, 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 gonna go out and do. So we'll make sure that we still live by those principles. Any updated views and just in terms of the mix, again, the right-of-way assets, in terms of the, the amounts that you've carved out, the $1.2 that's in the budget now, just any refined numbers around how, how you think that would shake out if the ROFR was not reinstated? So in the, in the CAD 1.2 or the, you know, or the CAD 1.4-1.8 total package there, you know, we talk about that 70%. I think, I think that would be... You know, if, if, if everything went against us, I think that's the, that's the, the minimum that we would have. That would be the floor. So I, I, that, that's, that's what we would be thinking right now. But as, as it stands, we don't think that will be the case. We think we'll have all those projects. Got it. Okay, thanks for the time this morning. You bet. Thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo. 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. Thank you, presenters and ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.