Good morning, everyone. Thank you for standing by. My name is Constantine, and I will be your conference operator today. Welcome to Fortis' Second Quarter 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.

Thanks, Constantine, and good morning, everyone. Welcome to Fortis' second 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 U.S. GAAP financial measures in our second 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. Today we are pleased to report our second quarter results. Operationally, our teams delivered reliable service to our customers despite a variety of severe weather conditions experienced during the quarter. Through the end of June, we invested capital of approximately $2.3 billion focused on system reliability and resiliency, customer growth and economic development, as well as cleaner energy investments. These capital investments supported rate base and EPS growth. On the regulatory front, we had a number of key proceedings advance. Notably at ITC, the Iowa Supreme Court granted a motion filed by ITC Midwest requesting a stay of the injunction issued by the Iowa District Court for Tranche 1 projects in Iowa. With this stay in place, ITC is now permitted to advance construction of all Iowa Tranche 1 projects originally awarded to the company in 2022. This is a positive development as ITC looks to invest in critical transmission infrastructure to support the clean energy transition and load growth in the region. And today we released our 2024 Sustainability Report. It includes new information on resiliency efforts, biodiversity programs and actions to support energy efficiency and lower emissions. The report also contains information regarding our progress on key sustainability targets. Our 2024 capital plan of $4.8 billion remains on track. During the quarter, construction of the 1,800 kilometer Wataynikaneyap Power Transmission Project was completed. We are proud to be a part of this project that is a majority owned by 24 First Nations, provides socioeconomic benefits and reduces greenhouse gas emissions associated with diesel fire generation previously used in these remote locations. We continue to execute our five-year capital plan of $25 billion that is comprised of virtually all regulated investments and a diverse mix of highly executable low risk projects. Rate base is expected to increase by approximately $12 billion to over $49 billion by 2028 supporting average annual rate base growth of 6.3%. Beyond the plan, regulated growth opportunities progressed during the quarter. At ITC, MISO released a near-final map of its LRTP Tranche 2.1 projects with transmission investments now estimated in the range of US$23 billion to US$27 billion, up from an earlier estimate of US$17 billion to US$23 billion. While it is still too early to estimate the investment opportunities within ITC's footprint, MISO board approval is anticipated in late 2024. In June, MISO also confirmed the transmission projects included in Tranche 2.1 would be insufficient to meet the demand and needs of the MISO Midwest sub-region under the Future 2A scenario. As a result, MISO expects additional transmission will be required likely through a Tranche 2.2 portfolio. While MISO has not provided any firm details regarding timing or scope of this new tranche, it certainly underscores both the need and opportunity associated with transmission investments in the Midwest considering decarbonization and load growth trends. In British Columbia, the Federal Environmental Assessment Certificate was issued in the quarter for the Tilbury Marine Jetty project. The construction of the jetty supports further expansion of Fortis, BC's Tilbury LNG facility. The site is scalable and can accommodate additional storage and liquefaction equipment and is close to international shipping lanes. Once constructed, the jetty will utilize Fortis BC's assets at the Tilbury site including the future Phase 1b expansion project to serve marine bunkering and reduce greenhouse gas and other emissions. In addition to the developments at ITC and Fortis BC, our utilities across North America are focused on expanding and extending growth opportunities in their jurisdictions especially in the areas of clean energy, continued electrification and load growth. 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 second quarter financial results.

Thank you, David, and good morning, everyone. For the second quarter, reported and adjusted EPS was $0.67, $0.05 higher than adjusted EPS last year. Year-to-date June reported and adjusted EPS was $1.60 resulting in an increase in adjusted EPS of $0.07 year-over-year. EPS growth was mainly driven by rate based investments across our utilities, new customer rates and warmer weather in Arizona, as well as new cost of capital parameters in British Columbia, which were approved in late 2023 and retroactive to January 1, 2023. The chart on Slide 9 highlights the EPS drivers for the second quarter by segment. Our U.S. Electric and Gas Utilities contributed a $0.05 EPS increase quarter-over-quarter. In Arizona, EPS was up $0.07 due to the favorable impacts of new customer rates and higher retail revenues due to warmer weather. Weather impacts were $0.02 quarter-over-quarter. At Central Hudson, EPS decreased $0.02 quarter-over-quarter largely due to a one-time impact of a regulatory settlement associated with the CIS implementation, which I'll discuss later, as well as the recognition of a regulatory performance target in the second quarter of 2023. At ITC, the $0.02 EPS increase was mainly driven by rate based growth tempered by higher holding company finance costs. Our Western Canadian Utilities increased EPS by $0.02. The increase largely related due to the timing of the new cost of capital parameters in BC, the higher allowed return in Alberta for 2024 was tempered by the timing of operating costs and the recognition of income tax expenses. Our other electric segment EPS decreased $0.01 mainly due to higher costs and lower equity income. For the Corporate and Other segment, the decrease mainly reflects the disposition of Aitken Creek in 2023 and higher holding company finance costs. And lastly, higher weighted average shares reflect shares issued under the dividend reinvestment plan. We have not used the ATM program to date as participation under the DRIP remains strong. Turning to Slide 10, many of the factors discussed for the quarter are the same for the year-to-date period. There are a few items to note for the year-to-date results. For our Western Canadian Utilities, specifically at Fortis Alberta, higher demand charges and customer additions also favorably impacted the year to date results. In Arizona, in addition to the new customer rates at TEP and higher retail revenue driven by warmer weather, higher margins on wholesale sales tempered by higher operating costs also impacted EPS in the first half of the year. At our Corporate and Other segment, the disposition of Aitken Creek, unrealized losses on derivative contracts compared to the gains in the first half of 2023 and higher holding company finance costs were the main drivers of EPS. And while negative for the quarter and year-to-date periods, on an annual basis, the disposition of Aitken Creek will be neutral to EPS. And finally, higher weighted average shares outstanding reduced EPS $0.03 through year-to-date June. Through June, we have raised approximately $1.4 billion of debt to repay borrowings and to fund our capital program. We remain in a strong liquidity position as we execute our five year capital plan and maintain our investment grade credit ratings. As I mentioned last quarter, we expect to have further engagement with S&P in the Fall, particularly on Fortis' mitigation plans around physical and climate risks. Looking ahead, we are on track to achieve average cash flow to debt metrics of 12% over the five year period. As David noted, earlier this month, the Iowa Supreme Court granted a stay of the injunction issued by the Iowa District Court with respect to construction of the MISO long range transmission plan Tranche 1 projects in Iowa. With the stay of the injunction in place, ITC is permitted to advance construction on all Iowa Tranche 1 projects originally awarded to the company in 2022. Certain complainants have requested that the Judge's order be reviewed by a full quorum of the Iowa Supreme Court. Regardless of any quorum review by the Iowa Supreme Court, 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. Further, MISO is conducting a variance analysis for the Tranche 1 projects in Iowa and we believe the process should reaffirm the initial award of the projects in 2022. In Arizona, the generic regulatory lag docket continues to advance. The Arizona Corporation Commission will host workshops in the third quarter to further assess the possibility of using formulaic rates or forward-looking test years instead of the historical test year currently in use. While the timing and outcome remain unknown, we are encouraged by these efforts to evaluate regulatory constructs that may reduce regulatory lag. In June, the New York Public Service Commission issued an order concluding the investigation into the implementation of Central Hudson's billing system. As part of the order, the independent third-party monitor reported that the CIS system was deemed stable and critical issues were resolved. The order also stipulates certain costs are not to be recovered from customers, including US$4 million for contributions to a customer benefit fund, which was recognized in the second quarter. The vast majority of the remaining costs were previously recognized in prior periods. Future impacts are not expected to be material. And earlier this month, the New York Public Service Commission also issued an order on Central Hudson's 2024 general rate application. The decision retroactive to July 1 includes an allowed ROE of 9.5%, 50 basis points higher than the previous allowed return. Central Hudson expects to file its 2025 general rate application in the third quarter. And with that, I'll now turn the call back to David.

Thank you, Jocelyn. The first half of the year continued our long track record of executing our growth strategy. We continued to implement our $4.8 billion annual capital plan, made progress and opportunities beyond the plan, and advanced our regulatory proceedings. This is an exciting time to be a regulated transmission and distribution company and we continue to pursue additional growth opportunities that deliver a cleaner energy future while continuing to prioritize safety, reliability, and affordability for our growing customers' needs. 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 the question-and-answer period. Our first question comes from the line of Maurice Choy from RBC Capital Markets. Please proceed with your questions.

Thank you and good morning everyone. If I could start with your updated view of the electric and gas demand outlooks across your utilities, there is obviously a broad anticipation to higher load due to a number of reasons and that could also lead to higher gas-fired power, and potentially some changes in future IRPs. So can you speak to which utilities you're seeing a notable change in demand outlook versus a year ago and how utilities might respond to this?

Yes. Thanks, Maurice. I'll start with kind of a broad overview and if you want to dig down into any of the individual utilities, actually we have everybody in the same room for once this call. So, I can ping it over to them if need be. But, I think probably the especially from a gas generation perspective, really the only big utility that we have that we're considering additional gas generation right now is that at UNS. We have, as you know, the two different utilities are TEP and UNS Electric. And as part of the integrated resource plans that they filed last year, we're adding a total of 600 megawatts, 400 at TEP and 200 megawatts at UNS Electric of combustion turbines to help fill in the variability associated with adding quite a bit more renewable energy into the portfolio. So that was what we filed last year obviously that was based on prior information on load growth et cetera. So we are seeing a lot of potential for additional load growth related to manufacturing and data centers in that footprint. But at this point, we haven't changed our integrated resource plan or changed any timing or additions to it. Although we do, as every resource plan is good the day you file it, and then you look at the additional assumptions, the load growth and retirement schedules et cetera and adjust them accordingly. But right now we don't have a lot of that built into the current plan, but we are working very hard behind the scenes to see where that might come. ITC also has, as we mentioned on the last call, some data centers looking to come into its footprint in both Iowa and I'm sure you're aware in Michigan as well there's a lot of efforts to attract data centers into those utilities' footprints of course that we serve from a transmission perspective. So they are there, but there's still a lot of TBD to be determined on how that lands. Those are primarily our two jurisdictions that we'll see the biggest impact from those types of load. Now of course, I should mention Alberta as well because Fortis Alberta, while the distribution company up there, I think we'll see some knock-on impacts from data center growth there. And just due to the comments of the government up there, they are receptive to citing data centers up there, but they have what I'm calling a BYOP bring your own power sort of philosophy to make sure that folks who come up there are going to come and either build generation or contract with it to make sure that they're not pulling it all out of the market. So that's if you want to go into any more details, just let me know.

Maybe just a quick follow-up on that, and obviously there's a lot of discussion about sharing of transmission costs and any other costs related to this new load. How are you seeing or which part of your portfolio are you seeing, the greatest progression and policy making and are you anticipating all the other jurisdictions to follow suit?

Yes. So, I think we're testing out a lot of stuff. And I think the big test, but I suppose is in Arizona because we have a vertically integrated utility and we can offer different kinds of options for customers that come in there from special contracts to special rates et cetera. There's one principle that I think everyone, every utility, this isn't just unique to us, will be following and that is this load has to pay for itself. And in fact, we think that it should have and will have a positive impact on customer affordability, because of the additional high level of utilization that these high load factor customers bring. So, overall we think it's a good story both from a growth perspective and a customer affordability perspective.

That's great. If I could finish up on ITC to just better understand, the district court, the Supreme Court judge's order here. Can the stay of the injunction continue endlessly for so long as the full quorum of the supreme court does not review this judge's order?

Yes. Good morning. Thank you, Maurice. I suppose, yes, it could. There's no requirement that the Supreme Court act in any certain timeline. They do act at their discretion. So to the extent that there was never any ruling or further decision or determination, then yes, the stay of the injunction would remain in place.

And I guess to just follow-up on that, if we have a position on Tranche 2.1 and I suppose ITC is going to proceed with investments in Tranche 1 and 2.1. How should we think about these investments if one day, let's say months, years, or a decade from now, the original position is referred back, is there any risk of stranded asset risk?

Yes, Maurice. No, we have no concern of any stranded asset risk. Obviously, we are continuing to pursue and invest in these projects according to the MISO tariff. And so the associated expenses related to that would all be under the premise that these projects were awarded to us, and that we have continued to pursue and develop under all of the provisions of the MISO tariff.

Good morning, everyone. I just wanted to get maybe some additional commentary on the regulatory outlook for Central Hudson. So the billing issues seem to be behind you and stabilized. New rates are in service, July 1. Do you think the new rates are going to be sufficient to largely close the gap between the achieved and allowed ROE or is this something that probably is more of the next rate filing?

Yes. So that should help definitely close that gap, and obviously the difference between allowed and earned over the past couple of years has been related to the CIS implementation costs, the additional cost that we were seeing associated with that which of course was part of that settlement that we agreed we won't recover. So that's all behind us. So on a going forward basis, we expect to see a much closer correlation between earned and authorized ROE, and as Jocelyn mentioned too we are filing the next rate case, because it is important to note that that rate case was just a one year rate case. So it's only good for a year and so we're required to file another one, and we're doing that tomorrow.

Thanks for that. More broadly, the Vancouver Council recently reversed the gas ban, which is quite surprising. When considering the ongoing need for natural gas, how do you view its role in helping gas buyers with cooking and potentially lowering home ownership costs? Additionally, with the increasing electrical demand, could this signify a shift in perspective towards natural gas?

So, Maurice, I believe that the shift in sentiment has been evident in nearly all of our regions, with the exception of British Columbia, which is now starting to recognize that the impact on affordability must be a primary focus. As we explore different channels for energy services, whether electric or gas, we think it's essential for both to play a role in providing energy sustainably and cost-effectively. We observe that some of the local distribution company adjustments in BC indicate a slightly different role for us moving forward, primarily focused on capacity. The need for this capacity is becoming increasingly clear in every region. I think people are starting to acknowledge this, and it's important to remember that we are still progressing toward a clean energy future. We are also helping people appreciate that as local distribution companies and gas providers, we can deliver clean energy solutions. This is something significant that we should emphasize. As you might be aware, we received approval from the BCUC for renewable natural gas to be included in the offerings for all our customers. This was a considerable achievement for Roger and his team in BC. Coupled with the decision to permit natural gas in new buildings once again, we are beginning to see how this blend can work effectively and affordably while still meeting clean energy objectives. Did I call you Maurice, Rob? Rob, if I called you Maurice, I'm sorry, but I know who you are Rob very clearly.

Good morning everyone. Maybe just going back to the Iowa situation and the relief on the injunction albeit there's I guess still uncertainty on how this all plays out. How does that impact your thinking and activity around procurement and moving out of projects that might come through in 2025, 2026? Are you being a bit more cautious pushing things out a little bit? And then those projects that maybe wouldn't fit under the right-of-way that 30%. How are you managing those projects in terms of permitting or trying to advance them quietly before you have to put CapEx to work?

Thanks, Mark. I'll have Linda ask that. It was a question related to both how do we manage the risk in this from a supply chain perspective?

We are still in the early stages of developing all the LRTP 1 projects. There is a considerable amount of work required for citing, permitting, and regulatory applications. Specifically for the Iowa 21 projects, we are in the initial stages and have not yet received the necessary regulatory approval. Additionally, we have not begun the franchise process mandated by state law. Consequently, there is no immediate effect on our approach to the supply chain. We maintain strategic relationships with our major vendors, ensuring we have sufficient capacity for all critical components of our infrastructure. Our capacity for the LRTP Tranche 1 projects, along with other projects, is secure, and we do not foresee any supply constraints impacting these projects or others. Our primary focus at this stage remains on the legal aspects, the regulatory process, and landowner issues related to the LRTP projects.

Can you remind us again what the planned spending would have been for next year and whether or not that could be impacted here as you sort through these issues?

Planned spending for next year, yes, we're continuing. Obviously, there's no change at this point in time in terms of our planned spend. We obviously will continue to reassess that as we release our next vintage of our five-year plan. But obviously, we're continuing to move forward and pursue the projects as identified and we certainly will update if there's any delay or slide specific to the LRTP 1 projects. But at this time there's no change in our overall capital plan.

Okay. And then on the regulatory lag docket in Arizona, what would you be advocating for as you work through these workshops in the fall and kind of push that forward?

Yes. I'll turn that over to Susan Gray, CEO of UNS.

All right. Good morning, Mark. Thanks for the question. The commission is considering basically either a forward test year or formulaic rate. And so we're having another workshop coming up in the fall to discuss that. And I think either format can work for us as long as we get the design of it correct. I think it's a good sign that we're talking about changing our longstanding rate making policy here. And I think, either way, we'll end up reducing lag. In the workshop, we did emphasize the formulaic rate. But I think in either case, we can design it to benefit our company.

It sounds like you're pretty confident.

Yes, Mark, she's doing stuff down there at TEP. I only dreamed of that was something that we've always been looking for is it was trying to figure out how to get out some of that regulatory lag and we've been doing things with other tracker mechanisms et cetera. But this is quite a bit better and cleaner solution and probably a little bit more simpler too.

It sounds like there is momentum behind it. So safe to say you think something will come to fruition and you won't change roadblocks where this falls out?

We're optimistic. No, I think we've always seen that as a bit of an entry point into the Ontario market. I mean it gives us a good anchor for looking at additional projects and additional transmission development. We obviously created a tremendous relationship with the First Nations up there. So yes, we'd always love to build more transmission in Ontario. Frankly anywhere within our footprint. So, we would look at, we don't have any plans on a going forward basis other than owning that asset.

Okay. Thanks, everyone.

Thanks, Mark.

Thank you, Constantine. We have nothing further at this time. Thank you everyone for participating in our second quarter 2024 results conference call. Please contact Investor Relations should you need anything further and thank you for your time and have a great day.

Thank you for participating. This concludes today's conference call. You may now disconnect.