Ladies and gentlemen, thank you for standing by. My name is Ruel, and I will be your conference operator today. Welcome to the Fortis first quarter 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 event and you need to reach an operator, please press star zero. At this time, I would like to turn the conference over to Miss Stephanie Amaimo. Please go ahead, Miss Amaimo. Thanks, Ruel, and good morning, everyone, and welcome to Fortis' first quarter 2022 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 first quarter 2022 MD&A. Also, unless otherwise specified, all financial information references in Canadian dollars. With that, I will turn the call over to David. Thank you and good morning, everyone. Our first quarter not only demonstrated the financial strength and stability of our business, but also our commitment to delivering a cleaner energy future for our stakeholders. During the first quarter, we successfully executed on our capital plan by investing nearly CAD 1 billion in our energy systems, supporting our adjusted EPS of CAD 0.78. There were also advancements made on the FortisBC Eagle Mountain-Woodfibre gas line project, as well as the MISO Long Range Transmission Plan and Lake Erie Connector project at ITC. Today, we are pleased to announce a 2050 net zero target that builds on our 2035 75% greenhouse gas reduction target. This announcement follows our inaugural TCFD Climate Assessment Report issued in March. Today, the importance of reliable, affordable, and secure energy service to our customers is more obvious than any time in recent memory. At Fortis, we are ensuring that these remain core principles as we take actions to both mitigate and respond to the impacts of climate change. While our reliability metrics continue to outperform industry averages, we must continue to make responsible investments in our energy systems to withstand the increasing frequency and severity of weather events. With the backdrop of inflation reaching 40-year highs, we are laser-focused on managing rising energy and material costs to limit customer bill impacts. As shown on slide 5, our utilities have historically managed annual increases in controllable operating costs per customer to 1%-2%. As operators of critical energy infrastructure, cybersecurity is a key component of our risk management program. With recent geopolitical tensions in Eastern Europe increasing cyber threats, our utilities continue to enhance security protection, including working with critical industry and government partners. As I mentioned, we made significant progress on our commitment as a TCFD supporter with the release of our first Climate Assessment Report. The report looked at four climate-related scenarios at our five largest utilities, identifying risks and opportunities. The report highlights our strong governance and oversight around climate matters and explains how risks are incorporated into existing risk management, long-term strategy, and financial planning processes. It is no surprise that policy and regulatory advancements, innovation, customer affordability, and reliability are imperative to facilitate the rapid transformation that is required to address climate change. Overall, Fortis is well-positioned to mitigate these risks and realize opportunities under various scenarios. Today, we are extending our commitment to a clean energy future with a 2050 net zero target. This next step in our ESG journey builds off our 2035 75% greenhouse gas emissions reduction target. Having reduced our direct greenhouse gas emissions 20% since 2019 and with plans to fully exit coal by 2032, we are committed to a net zero target by eliminating the last 25% of direct emissions by 2050. Through technology advancements, the appropriate use of low- or no-carbon fuels, and carbon offsets, we believe we can achieve our net zero target while preserving customer reliability and affordability. Turning now to slide 8. Last year, we announced our CAD 20 billion five-year capital plan through 2026. For 2022, we remain on track to invest CAD 4 billion in our systems, with nearly CAD 1 billion invested through March. We do not expect 2022 capital expenditures to be significantly impacted by supply chain constraints, as our teams have taken proactive steps to promptly identify and mitigate supply chain issues. Major capital projects, which represent 15% of the five-year plan, continue to progress. In April, Woodfibre LNG issued a notice to proceed to its prime contractor for the proposed liquefied natural gas site in Squamish, British Columbia. This announcement brings FortisBC's Eagle Mountain-Woodfibre Gas Pipeline one step closer to construction, though the project remains contingent on Woodfibre LNG making a final investment decision. Overall, our highly executable and low-risk capital plan is expected to increase rate base by over CAD 10 billion over the next five years, supporting average annual rate base growth of approximately 6%. Beyond our base capital plan, we have a long CapEx runway focused on climate adaptation, innovation, and a cleaner energy future in support of our stakeholders' expectations. This blueprint is expected to support sustainable growth for the foreseeable future. With respect to near-term growth opportunities, momentum at ITC continues to build. During the first quarter, MISO advanced its long-range transmission plan, announcing the first tranche of projects across the MISO Midwest sub-region, comprised of 18 projects with total associated costs of approximately $10 billion. These projects require MISO board approval, which is currently anticipated in late July. Six of the projects run through ITC's service territory, including Michigan and Iowa, where right of first refusal provisions exist for incumbent transmission owners. Other projects within this portfolio may be subject to competitive bidding, depending on the state they are located in. Based on this preliminary information, ITC estimates transmission investments of approximately $1 billion-$1.5 billion through 2030 associated with these projects. ITC is working on finalizing the timing and costs associated with these projects. In the coming months, we look forward to determining which will be included in our five-year capital plan. Next, the CAD 1.7 billion Lake Erie Connector project continues to advance. In March, the province of Ontario issued an order in council and ministerial directive to the IESO to negotiate with ITC on finalizing a transmission service agreement on or before August 15th, 2022. The proposed 1,000 MW direct current underwater transmission line will provide the first direct interconnection between the wholesale electricity markets operated by the IESO in Ontario and the PJM Interconnection in the United States. This project will be additive to our growth outlook. With a strong track record of increasing dividends for the past 48 consecutive years, coupled with our low-risk growth strategy, we remain confident in our 6% average annual dividend growth guidance through 2025. Now I will turn the call over to Jocelyn for an update on our first quarter financial results. Thank you, David, and good morning to everyone. Turning to slide 13 and looking at the first quarter results, adjusted net earnings of CAD 369 million or CAD 0.78 per common share was CAD 0.01 higher than the first quarter of 2021. We continued to see earnings growth driven by rate-based growth across the group and the recovery of the tourism industry in the Caribbean. Hydroelectric production was lower in Belize this quarter, and Central Hudson also experienced higher operating costs. The waterfall chart on slide 14 highlights the EPS drivers for the quarter by segment. As mentioned, we continued to see rate-based growth across our utilities, supported by investments of nearly CAD 1 billion during the quarter. Combined, our Western Canadian utilities and ITC contributed a CAD 0.03 EPS increase, driven mainly by rate-based growth. At our other electric segment, EPS increased $0.01, driven by sales growth in the Caribbean as a result of the tourism-related activities, with first quarter sales up 3% from pre-pandemic levels. At Central Hudson, earnings were favorably impacted by rate base growth and the conclusion of its rate case in 2021. However, they did experience higher operating costs associated with the implementation of a new customer information system and restoration costs associated with winter storms, decreasing EPS by $0.01 for the quarter. For our energy infrastructure segment, EPS decreased by $0.01 due to lower hydroelectric production in Belize. Production in the first quarter of 2022 was 17 GWh compared to 53 GWh in the first quarter of 2021, and this was due to lower rainfall. As expected, with our dividend reinvestment plan, EPS decreased by CAD 0.01 due to higher weighted average shares outstanding. Finally, while not depicted on the slide, earnings at UNS were broadly consistent with the first quarter of 2021 and in line with our expectations. UNS benefited from higher long-term wholesale sales, transmission revenues, customer growth, and lower planned maintenance costs. Earnings in the quarter were offset by the timing of earnings associated with the Oso Grande wind-generating facility. Turning to slide 15, we were once again active in the debt capital markets, with our regulated utilities raising over CAD 900 million in long-term debt, largely in support of their capital programs. With the backdrop of a rising interest rate environment, several of our utilities accelerated debt issuances in the first quarter, locking in attractive rates. ITC also entered into additional interest rate swaps to mitigate refinancing risks. Our recent debt issuances, coupled with over CAD 3 billion available on our credit facilities, places us in a strong liquidity position, supporting our CAD 20 billion five-year capital plan that David referred to earlier. We continue to maintain strong investment-grade credit ratings. In March, S&P confirmed our A- issuer credit rating and BBB+ secured debt rating and stable outlook. We are comfortably positioned within our existing investment-grade credit ratings, providing financial flexibility as we pursue incremental growth opportunities. Turning to recent regulatory updates. First, ITC continues to await a final rule from FERC in relation to the supplemental notice of proposed rulemaking or NOPR on transmission incentives, which proposes to eliminate the 50 basis points RTO return on equity incentive adder. Next, FERC issued a NOPR in late April addressing regional transmission planning and cost allocation stemming from the initial advanced NOPR released last year. The NOPR contains several constructive proposals, including a requirement that transmission planning regions conduct long-term plans, a formal role for states in developing the cost allocation for projects, and the reinstatement of federal right of first refusal under certain circumstances. Initial comments on the proposal are due 75 days from the date of publication. Earlier this week, TEP submitted a Notice of Intent with the Arizona Corporation Commission or ACC to file a general rate application in June 2022, requesting new rates to become effective no later than September 1st, 2023. The application will seek new rates using a 2021 test year that addresses infrastructure investments made since the last rate case, as well as changes in fuel and non-fuel operating expenses. The filing will also include proposals to eliminate certain adjuster mechanisms as well as modify an existing adjuster to provide more timely recovery of clean energy investments. In British Columbia, the generic cost of capital proceeding continues this year, and the effective date of any changes in the cost of capital parameters remain unknown. In March, the Alberta Utilities Commission issued a decision on the 2023 generic cost of capital proceedings. FortisAlberta's current cost of capital parameters were extended for 2023. The AUC also confirmed it will begin a separate process later this year for cost of capital for 2024 and beyond, including the consideration of a formula-based approach. That concludes my remarks. I'll now turn the call back to David. Thank you, Jocelyn. We are pleased with the progress our teams made in the first quarter to advance our sustainability and growth initiatives. With a 2050 net zero target, we are building on our commitment to deliver a clean energy future while ensuring the affordable and reliable energy service our customers demand. With our regulated transmission and distribution business, highly executable capital plan, and CapEx runway, we are in a strong position to support our dividend growth guidance through 2025. I will now turn the call back over to Stephanie. Thank you, David. This concludes the presentation. At this time, I'd like to open the call to address questions from the investment community. Thank you. Ladies and gentlemen, we will now conduct a question-and-answer session. If you would like to register a question, please press star followed by the number one on your telephone keypad. If your question has been answered and you would like to withdraw your registration, please press the pound sign. If you are using a speakerphone, please lift your handset before entering your request. We kindly request you speak loudly and slowly to ensure all participants can hear your questions. One moment, please, for the first question. Your first question comes from the line of Maurice Choy from RBC Capital Markets. Your line is now open. Thank you, and good morning. My first question is to follow up on the MISO LRTP. You quoted the $1 billion-$1.5 billion of investment in Tranche One, one which represent around 10%-15% share of the overall cost. Was this in line with your expectations? As a follow-up, besides the MISO board approval, what are some of the variables that remain unknown right now that if you had better visibility, you'd be able to finalize assessment higher or lower, and the timing of the capital spend? Yeah. Thanks, Maurice, and thanks for that question. I should start off by letting everybody know that we actually are in person for the first time with this entire team for an investor call in three years. It'll be great to be able to send some of the details of these questions to our team that's actually sitting right here in the same room in St. John's. I wanted to start out and let people know that. On the MISO Long-Range Transmission Plan, the $1 billion-$1.5 billion US that we put out there is our current best estimate based on the projects and based obviously on the initial cost projection that MISO has put out there. As you noted, it's Tranche One of Future One. What's going to happen, you know, further in the future related to the remaining tranches and whether or not we go into the you know Future Two and Three scenarios as well remains to be seen. Obviously timing around the MISO board approval of the projects, getting those details, figuring out the timing of construction and of course doing our own project cost estimates will all be things that will go into the mix as we go forward. We expect to get more visibility on that with you know each step that MISO takes going forward. I think you asked about expectations. We're pleased. This is a billion dollars, so we forget how much money a billion dollars is. The $1 billion-$1.5 billion US of additional projects that aren't currently in our forecast is a pretty big chunk. Of course, these things are going to come in, you know, varying. As you do these tranches will come in, I'll say kind of in varying areas. We're not sure how to really project what the next tranches might be. Will this maybe lighten our footprint? Will the next one, you know, if you have a different weighting in our footprint, that stuff is really hard to get clear visibility on. Sorry, a quick follow-up. Suppose this spending occurs within the next five years. How do you see yourself managing the funding for the spend? Yeah, Maurice, I think it's early to talk about specific funding for this. I think we need to get visibility of the timing because we do expect some of it, I would think, to extend beyond the five years. When we firm up the timing, we'll firm up the funding. I've said a number of times that, you know, we've been pleased with where we've moved the balance sheet, so not looking to move that backwards too materially or forward too materially. I don't expect there to be a complicated funding plan, but stay tuned, and we'll firm that up as we firm the timing of these capital expenditures. Thanks. Maybe my final question is on the net-zero 2050 target, and congrats on that. I assume, you know, if I look at slide 7, many of the initiatives you've shown in there relate to initiatives that get you to your 2035 midterm target. I assume much of what gets you to net-zero by 2050 relates to Arizona. If so, what are some of the post-2035 initiatives there and your thoughts on navigating through the affordability theme that ties into your regulator's agenda in Arizona? Yeah. The majority of that last 25% is related to gas generation in Arizona, and that's the part that we're gonna have time to figure out exactly how we address that. Remember, this is a net zero target. We've got a really solid and defined plan of how we get from the 2019 emissions to that 75% reduction that's laid out in that slide. Most of that's activities related to the generation in Arizona. That last 25% will need new technology. We do have gas generation down there. We'll need cleaner fuels, things, possibilities like hydrogen, renewable natural gas, carbon capture and storage. It's hard to say where, which technology will win, but we wanna make sure that we've got, you know, we've got a view on all of those. The path after 2035 is obviously less clear at this point because it's so far out and so much to be done from a technology perspective. We will make sure, I mean, that. You mentioned our guardrails, and it might sound like we talk about these words, you know, so often that we forget how meaningful they are. The affordability and reliability of our service to our customers is gonna be most important and is right in the visibility of our regulators and customers as we sit here today, more so than probably any time in the past, well, at least in recent memory. We will make sure that the things that we do are in line with that. We'll keep an eye on it. Obviously our industry is keeping an eye on this, looking for those technologies that can help us accelerate what we're doing and continue what we're doing down to the efforts of net zero. I should say that, you know, when you get out there too, offsets are an option as well. We don't need offsets to get to that 75% greenhouse gas reduction goal that we currently have in 2035, but that's got to come into play in the future. Great. Thank you very much. Your next question is from the line of Linda Ezergailis from TD Securities. Your line is now open. Thank you. I'm wondering if you could give us some more thoughts on the Lake Erie Connector. Specifically, how confident are you in your CAD 1.7 billion cost estimate? Maybe you can give us a sense of how much contingency is in there, or is that estimated future cost or how much that might go up? Then, what would be the key gating factors beyond this August fifteenth deadline to get to an FID and have this proceed? I guess my final question related to Lake Erie Connector is around the Ontario provincial election and how that might affect the timing or potentially the outcome of this project. Yeah. You mentioned the OIC, the order in council that we received, and you know, they gave the IESO a deadline of August 15th to get a transmission service agreement signed up. That is the next big gating item. Now, as far as costs go, that's the things that we're working on is to finalize that. We don't have anything that we can you know, disclose publicly as we you know, try to finalize all of the details within that negotiation process. Obviously, cost is a big one. You know, we're gonna need EPC contracts out there, et cetera. All of those pieces will be filled in over the next few months and obviously have to be known before we get to that TSA. That's the big gating item. Obviously, besides, you know, our own internal approvals as well as IESO's approval, which you referenced there from an election perspective. The plan that we have here and the TSA timeline here, we don't see that would be affected by, you know, the timing of the elections in Ontario. To be frank, this is a great project, so it'll stand on its own merits. We think no matter who's looking at it, and that's always been the goal for a project like this, is to show those benefits, the cost-benefit ratio that we have, and that it's a good project. We're not concerned about, you know, from an election perspective. Thank you. Maybe just a bigger picture conceptual question around bill pressure for your customers and just this, you know, inflationary environment that we're seeing. How are you thinking across your jurisdictions around mitigating that impact on customer bills? Might you see regulators potentially try to dial back capital expenditures to mitigate the operating expense pressures? Might you see more deferral accounts or potentially changes in depreciation rate to the extent that certain assets could have a longer life than initially anticipated? Or, you know, might there be also some friction around are we going up even as interest rates and inflation marches up? Can you talk about how you're thinking about approaching that and what you're hearing from other stakeholders? Yeah, you hit on, I think, every single category that I would list. It is obviously right in the center of every conversation that we have with our regulators and with our customers is making sure that we're particularly in this inflationary environment, as well as, you know, high natural gas and purchased power costs across North America, well, across the world for the most part. Those are things that we have to really be paying attention to because, you know, not only does it matter to our customers and our regulators, it matters to us that our customers are having to pay that much. We're looking at ways of helping them mitigate their bills. We do the standard stuff only in much more rigor, things around promoting energy efficiency, conservation, bill management, you know, levelized billing, things like that. We do know and recognize that when, you know, there are big spikes in pass-through costs because these are costs that we don't make any money on in our regulated utilities, that we look at ways of helping our customers. Some of those, as you mentioned, the deferrals that we have at a couple of our utilities now that are spreading out the cost recovery so that the current impact isn't so severe. We have to make sure that we're paying attention to that and watching not just the bill impact on the customers, but of course that affects our cash flow. Which means we really have to be focused on other ways of reducing costs across our organization, O&M, operations and maintenance, et cetera. Those are some of the big ones. Bill assistance is, I think, another one that we've been steering our customers to because there are federal, you know, billing programs that can help, at least down in The U.S., that can help people pay their bills. Those are most of the items. As far as the regulators and how are they seeing this, nobody likes increasing costs and rates no matter how justifiable they are. I don't see or don't hear any conversations related to, you know, slowing down CapEx because this CapEx is needed for a variety of very strong policy requirements. You know, obviously reliability for one, as I mentioned earlier, making sure we're making the investments in our systems that can manage, you know, the increasing severity of storms, et cetera, but also shifting to clean energy. You know, some of the ways that we do that, like in Arizona, even save our customers money, so that's good. That's a no-brainer capital expenditure. Some of the other ones on, you know, resiliency, adaptation, things like that, we have to make sure that we're doing those in the most responsible manner that we can and in the timing that we can to, you know, manage those the overall bill impact. Thank you. I'll jump back in the queue. Thanks, Linda. Our next question is from the line of Rob Hope from Scotiabank. Please proceed with your question. Good morning, everyone. Just wanna touch on the Tucson Electric rate filing that we should be expecting next month. You know, what are the key things that you're looking for in the new rates, whether it be kind of a higher ROE, clean energy tracker? Can you just kind of add a little bit of color there? Yeah. We've got a batch of normal stuff in what I'll call normal stuff in a rate case. You look at things like rate design and cost allocation. Obviously we have a chunk of rate base that has increased that we'll be asking for. We will look for higher ROE. We think we got a pretty low one in that last rate case. It was at the end of 2019, so it was end of 2019, is that right? Yeah. End of 2020. That was obviously right in the middle of COVID. We think that we have a good argument for getting a bit of a stronger ROE in that jurisdiction, particularly with the backdrop of where we see interest rates right now. As far as the clean energy tracker, Susan and her team are doing a great job of looking at how we can, you know, reduce some of the trackers and transition away from them, things related to things like DSM, demand side management, energy efficiency, et cetera, and replace those. Even the renewable energy tracker and replace those with a new clean energy tracker. I know I've talked about that with you all in the past, and that's a real important part of our rate filing because that will allow us to invest and accelerate our investments in clean energy and be able to get a more prompt recovery of those investments through a tracker mechanism. All right. That's helpful. Appreciate the color. Just as a follow-up, just on the Lake Erie Connector project, you know, let's assume that we get a contract, you know, in Q3, Q4 for that. You know, when do you expect to mobilize on that project, and kind of when would capital start to be put out the door there? Yeah. I'm gonna kick that one over to Linda Apsey, CEO of ITC, and she's got those details. Yeah. Great. Thanks, Dave, and thanks, Rob, for the question. With respect to, I would say, presuming everything goes as we would anticipate if we were to have all the agreements in place yet this year, you know, we would anticipate that we would be sort of preparing and readying for construction start in the first half of next year. I think as we have mentioned before, it is a four-year anticipated construction. That would put us into the first half of 2027, assuming all goes as anticipated between now and getting the agreements in place. All right. Thank you for the color. Thanks, Rob. Your next question is from the line of Ben Pham from BMO. Please proceed with your question. Hi. Thanks. Good morning. May I start off with the recent rising interest rates, and maybe could you remind us what percentage of your utility you can seamlessly pass through higher interest expense, and maybe comment on your debt position. Then you also mentioned the low ROE at TEP. Is there any other utilities where you have automatic adjustments to the ROE? You see the base ROE moving up, there's a good chance to maybe move more aggressively on that area. I'll talk a little bit about the inflationary impacts from a rate perspective at the subs and kick it over to Jocelyn to talk about the impact, debt, timing, et cetera. But I suppose I should first say we don't really have, like, a good thumb rule for what, you know, the percentage of our cost that would be able to be passed through on a sort of Fortis-wide basis because we have different regulatory constructs in our jurisdictions. Everything from ITC's, which is basically just a matter of timing, but it can pass through all their costs with their forward formula transmission rates to PBR methods that vary in the level of interest and how that's treated on the annual true-ups. It's a little bit different in BC than Alberta and Ontario, but they all generally have mechanisms for capturing at least a good portion of that of the higher costs from inflation, et cetera. Of course, in Arizona, it's a historical test year. So those are risks that we would bear and then recover in the next case. It's just one of those things that kind of go up and down based on the rate case timing. I'll turn it over to Jocelyn to answer the interest rate question. Yeah. Ben, with respect to your question on the rising interest rates, not that we're not doing all the right things to manage rising interest rates for customer affordability because we're doing that, but we do have a number of various regulatory mechanisms in each of our utilities that actually does provide for a rising interest rate environment. ITC would have an annual true-up, and we have other various mechanisms in each of our other utilities. With the exception, as David talked about with UNS, because they're on an historical test year. Obviously they play catch up with interest rates, rising interest rates when they go to set rates, which they'll do with this particular test year that they are about to file. I would say, the most exposure outside of UNS would clearly be in the holding company and, within our disclosures this quarter, as we've identified that, we have entered into, further interest rate swaps to actually mitigate some of that refinancing risk. We are doing the right things. Even at the regulated utilities, I would say we were pretty active this quarter in terms of advancing some of the debt issuances, regardless of the regulatory mechanisms that we have. We're doing the right things in terms of getting in front of the curve so that we can actually try to combat some of the impact on our customers. On the ROE, is there any obvious outliers there where it's well below North American utility averages or relative to what the CAPM is telling when you feed in the 30-year? Yeah. We don't have any tracking ROEs to track currently. There is a generic cost of capital going on in BC. Obviously, the case in Arizona will go through its own calculations to determine the right ROE when we do that rate filing. Alberta has pushed their existing capital structure and ROE out another year, and then we'll start a generic cost of capital later this year that will be in effect in 2024. Other than that, there's not any adjustment mechanisms that would be changing it on an interim basis. Thanks for that. Then maybe switching to Woodfibre, there's a recent article around a second pipeline being proposed through a tunnel, and there's some references to the cost going up by, I think, CAD 300 million +. I'm just wondering if you can comment on that and on that cost, if that's correct, and if you can recover that in rate base. I'll give you to Roger here for the details. It is good to see the progress that's being made on that project in general. Woodfibre did put out a notice to proceed in April to its main contractor. That's obviously the LNG facility contractor. We're building the pipeline, which that tunnel is part of, and I'll let Roger give you the details on that. Good morning, Ben. Thanks for the question. The two-tunnel issue is a bit of, I think, confusion from the reporter. Sorry, one tunnel, two pipes relates to the design under the Squamish Estuary. There's about a 9-kilometer tunnel we're building under the estuary. We're gonna be backfilling that tunnel, so it'll be very difficult to access the pipe. We're putting in a second pipe for redundancy and reliability so that Woodfibre will not be disruptive to service. That was just an evolution of design. I think it was reported there was two pipes serving Woodfibre. It's one overall pipeline system that we're expanding to serve Woodfibre, but a second pipe for redundancy in the tunnel portion. As far as costs, a number of the costs are being finalized. We are seeing a little bit of pressure, but not significant at this stage. Okay. You would say that the reported cost reference may not be reliable at this point in time? For the pipeline or for the Woodfibre's LNG facility? It's for the pipeline. Yeah, we are seeing some cost increases on pipe, but as far as the overall cost, we're still finalizing our cost estimates. Okay. All right, thank you. Our next question is from the line of Mark Jarvi from CIBC Capital Markets. Please proceed with your question. Thanks. Good morning, everyone. I'm going to come back to the topic of affordability. Is there any discussions, have you heard anything in terms of either at a federal level or state level in terms of either it's, like, a subsidy or some other way to help alleviate customer bill pressure while still allowing utilities to make the needed investments around decarbonization? Obviously, at the federal level, there was talk of the CEPP, which wasn't gaining traction. Is there anything else in the state level or anything else at the federal level you think can be done to help manage affordability while still doing the right on decarbonization? None that we know of other than, you know, the pieces of the Build Back Better plan. If those come back and those tax credits start flowing, that can really help. But nothing from a state level that I'm aware of, you know, across our jurisdictions anyway. Okay. Just obviously on the NOPR that went through at FERC a couple of weeks ago, just any sort of initial thoughts on that, the federal ROFR, cost allocation in terms of bringing in the state. Is there any chance that the involvement of state utility commission slows the processes at all? Just sort of what your sort of initial thoughts are on that as you've digested it. Yeah. We're still digesting all the details. Obviously, it's out there for comments. Overall, it's constructive. To get better, more defined planning process to get more transparency in the planning process, to have these cost allocation discussions and bringing the states in. That I think is probably where you get most of the rub is if you can get states involved early, it should help out the process. I wouldn't think it would slow it down. Then, of course, the federal ROFR rights for certain projects and situations, that's a positive for us as well with ROFR rights in three states in the Midwest. Okay. Last question. Just, I think there's a refund that has to go for Tucson Electric Power in terms of some of the peak prices that happened in the summer of 2020. Can you just comment on how much that is and whether or not that's gonna flow through adjusted earnings? Wait. Say that again. I believe there was, like, an order saying that there has to be a refund from a handful of utilities, including, I believe, TEP, back to some high commodity charges in the summer of 2020. I'm just curious if that's right and how much it is and whether or not there's an earnings impact. That's the first I heard of it, and we're looking quizzical here, so I don't. Okay. We don't know anything about that one. Sorry about that. Yeah, no problem. Our next question is from the line of Richard Sunderland from JPM organ. Please proceed with your question. Hi. Good morning. Thank you for the time today. Maybe just circling back to the TEP rate case and thinking about the, you know, the Arizona regulatory backdrop more broadly. You obviously have some activity in the state and then a big one coming with TEP here. Any sense on kind of reading the tea leaves on sentiment and how things stand from a regulatory backdrop, maybe with you versus other peers in the state, given some of the noise we've seen in the state over the past few years? Yeah. I've said repeatedly that, you know, we've got a good relationship with our regulators in Arizona, even though it might be a bit more of a tangly relationship for others in that jurisdiction. As I mentioned earlier, the 2020 rate case, we got a good outcome. I told you I wasn't a fan of the ROE. Other than that, a very constructive outcome on post-test year plant, getting two new trackers. All of those things really were positive and constructive from our view. We're taking that long history of working with trust and transparency with our regulators, you know, every time we go up there, and that will give us a You know, the ability to get good outcomes. You know, good, reasonable outcomes. We know it's. You know, that's the way we have to manage these relationships, and it's how we continue to do it. Fair enough. It's very helpful. Apologies if I missed this earlier, but just thinking about the net zero outlook and your long-term environmental goals, just in light of today's update, can you speak to how RNG fits into the larger picture here? Yeah, our RNG can fit into the larger picture. Now, specifically in this goal, we're talking about scope one emissions, and that can fit into a piece of, say, the gas generation in Arizona, which will be that 25% that's left after 2035. It does play a role there. It's hard to say how much of a role as we sit here today versus hydrogen, et cetera. It also plays a role in our focusing on, say, scope three emissions that we do up in British Columbia. We do have a strong goal of getting 15% of our supply from renewable gases in British Columbia. That's a big chunk of natural gas. RNG is playing a big part of that. The team up there has done a great job in pulling together contracts for a good portion of that already and has the eye on being able to figure out the last percentage, a few percentages there that they need by the 2030 deadline that they have for that 15%. Got it. Thank you for the time today. You bet, Richard. Our next question is from the line of Andrew Kuske from Credit Suisse. Please proceed with your question. Thanks. Good morning. I mean, you're in an interesting position because you've got transmission opportunities in both Canada and The U.S. And maybe the question is directed to Linda, but how do you think about the benefits associated with either of those jurisdictions? In one case, obviously it's intertwined, given you're connecting the two countries. Yeah. Yeah, go ahead, Linda. Great. Thanks. Yeah. Maybe just from a little bit of history. Certainly, we do think our geography is strategic. If you know, think back to actually what ITC stands for is International Transmission Company. It was, you know, originally developed on the premise to take advantage of our unique geography and our close geography to Ontario. Certainly, as we continue to develop the Lake Erie Connector, I think it sort of brings us back to our roots in terms of sort of how we envision the business and that strategic geography. I think we are well-positioned, certainly as markets evolve both in the U.S., particularly the Midwest ISO, as well as how the Ontario market evolves. They did evolve in different directions. Certainly, you know, we are I think very pleased from a strategic perspective that we are able to leverage the geography. I think it does give us some further, you know, I don't want to call them opportunities. That would be premature. I think just in terms of thinking about taking advantage of sort of the border, and certainly a project like the Lake Erie Connector sort of certainly gives us a, you know, a foothold with experience in terms of undersea cable technology. Certainly, we certainly view this project as something that we hope that we could leverage into the future. Okay, that's helpful. You know, cyber was mentioned earlier on in the call, and obviously that's critical. You know, the normal course of business operations and the cyber capabilities that you've got, especially at an entity like ITC, they're immensely capable. Do you see this as a competitive advantage at this point in time to maybe roll up other utilities into the future that don't have that kind of capability? Or is it really just a competitive necessity at this stage? Yeah, I think it's just a flat-out necessity at this stage. I don't think we would look at, you know, put that as a, maybe a competitive advantage, from an acquisition standpoint. The competitive advantage is the fact that we have great teams across our entire footprint. ITC, given their huge transmission footprint and how big their systems are, they had really strong depth in their IT world. That's why our CIO, from a Fortis Inc. perspective, we stole him from ITC and brought him up to Fortis Inc to help coordinate that across the entire organization. That's that type of double layer of skills that we have across our organization and are able to share that skill. It's a competitive advantage for us because we're able to take, you know, best practices and push them across the entire organization. Obviously, that's just one of many ways that we work our business model. Okay. Thank you. That's very helpful. Thanks, Andrew. Our next question is from the line of David Quezada from Raymond James. Please proceed with your question. Thanks. Morning, everyone. Just one for me, and it just relates to your I guess near-term planning horizon for renewables at TEP. Just curious, you know, if you can provide any color on what you're looking to procure over that period and if the Department of Commerce investigation into solar panels from Southeast Asia and any related tariffs there could cause you to juggle any kind of type of projects between wind and solar in that area. Yeah, we don't really have much of an impact yet on the tariff issue. Both TEP and our smaller subsidiary, UNS Electric in Arizona, put out RFPs last month. We're looking for good chunks of renewables that can be PPAs, build on transfer, et cetera, both for renewables and for firm capacity, which can be in the form of, you know, batteries or other generation alternatives. We'll have better answers for that when we get, you know, midyear, when we start seeing the results of those, of that RFP, and then later in the year when we actually analyze them and assign or enter into contracts related to that process. Excellent. Thanks for that. Our next question is from the line of Matthew Weekes from iA Capital Markets. Please proceed with your question. Good morning. Thanks for taking my question. I think I was just gonna ask about the quarter and some of those costs related to Central Hudson. Just wondering if those are really transitory kinda one-time costs to implement those systems or if you're expecting any more going forward. Then on the other side, looking at I think some commentary in FortisBC about some lower expenses there. Were there any sort of timing related impacts there? Was that just due to effective cost management and productivity savings on the O&M and the A side there? Yeah. First on the CH, I'll answer these pretty quick. First on the CH, they are transitory. They're related to that, to a system implementation. So we're not expecting, you know, repeated cost impacts on a going forward basis. Of course, Charlie and his team are working hard to figure out how to offset some of those cost impacts as we go throughout the remaining part of this year. On the BC one, I think that is just good old strong O&M management by the team up there and not timing. Okay, thanks. I appreciate the color on that. That's it for me. I'll turn it back. Our next question is from the line of Michael Sullivan from Wolfe Research. Your line's now open. Hey, everyone. Good morning. Morning, Michael. Wanted to circle back to this upcoming rate case filing you have in Arizona. Can you just remind us how much you've added to rate base in that jurisdiction since the last case? Then on the fuel and power side, just how we should be thinking about that impact on the overall bill and how that fits into the case filing. Yeah. We don't wanna front run the filing. We're putting all those numbers together because there's a lot of stuff that goes into that, not just the test year that we've obviously already closed, but also post-test year adjustments and other things that we may need to be looking at. The number one thing about you know your regulators is don't surprise them by saying stuff before they know it. I can't. We'll save that for the June filing. Okay. Maybe on the fuel and purchased power that you just got an order on, what sort of bill impact there was there? Then how to factor that into the future. It was only I think around 3% was the overall bill impact of the purchased power and fuel adjustment clause that we just got approved. That's that 3% was for historical costs that will be then collected over the next 18 months. Got it. Okay. Shifting over to the MISO transmission, can you clarify the $1 billion-$1.5 billion, is that just in the ROFR states that you're in or that's across your footprint and the ROFR states is a piece of that? Yeah. I'll turn that over to Linda to answer. The projects that comprise the $1 billion-1.5 billion, those projects, are either in Michigan or Iowa, and we have state ROFRs in both of those states. I think in answer to your question, the projects that have been identified that are ITC's would be in ROFR states. There are no other projects identified that would be outside of those states for ITC. Okay. Could you maybe just give a high-level view of your thoughts on how things may go in the non-ROFR states? Is it still going to be the incumbents largely winning as I think we've seen historically? Or are you sensing maybe there's more openness to competition now? Yeah. I would really hesitate, I think, to speculate on kinda what's gonna happen in those other states with respect to competitive bidding. As you may know, FERC's recent NOPR on transmission planning included some provisions that suggest that they may be open to reinstating federal rights of first refusal if projects are jointly owned. While we don't specifically truly know or understand what FERC might be thinking or certainly where they might make a decision, but certainly if that proceeding were to proceed and there was a decision, and I'm using a lot of ifs. If there was a decision, perhaps whatever may come out of that NOPR in a final order perhaps could apply back to these projects in non-ROFR states. You know, I'm talking pretty high level off the cuff, because I think really the best answer is we don't know yet what might happen in those other states and how incumbent utilities may position themselves or how developers or people who are participating potentially in that competitive solicitation process. You know, we don't know where they might bid or how they would bid, who they would partner with. I think there's a lot of unknowns at this point in time to truly understand what that means. What I would say, just as it relates back to ITC, you know, I just to maybe perhaps toot a little bit of our own horn, I think sort of anticipation of this tranche one portfolio. Process. I think that's why we were so focused on securing the right to first refusal in the states where we have predominantly most of our assets. The timing, we just completed getting our state ROFR in Michigan late last year. Certainly from our perspective, the timing was critical, so that we could secure the rights to these projects that have been identified. Appreciate the thoughts. Thank you. Your next question is from the line of Dariusz Lozny from Bank of America. Please proceed with your question. Hi. Good morning, and thank you for the time. Just wanted to touch on the Arizona rate case filing briefly. Can you maybe just talk a little bit about what your, I guess, what the strategy is, number one, behind the timing of filing, midyear? I think one of the other utilities in the state also is looking to file probably around the same time. Then secondarily, in terms of the goal of reducing the number of riders out there, anything strategic that you're trying to accomplish as part of that, or is it just trying to align with the commission's stated goals of having fewer riders out there? Thank you. Yeah. I think in the last part first, it's aligning with goals of both the commission and, you know, other stakeholders looking to simplify the number of riders. It helps us as well, so that we don't have so many different proceedings going on all the time. Getting, you know, the fewer good straightforward riders is better than having a bunch of small ones. As far as the rate case timing, we make the decisions based on what we need to do, not what, you know, other utilities may or may not do. We're used in the last test year or the last year, full- year that we have as a test year, and this is the time that we could get all our numbers together and the time that we need to go in and address the rate shortfall we have in rate base. Okay. Thank you. One more quick one if I can. Just on the quarter, it looked like sales at Central Hudson ticked down about 3%. Was that a weather-driven number, or was there anything else attributable to that? Charlie, do you have the details on that? Yeah. I would say it's probably more weather-driven than anything else. I mean, certainly pricing resulted in customers cutting back as well. We have revenue decoupling, so you know, I think ultimately that works through the course of the year, particularly as we work through sales, unbilled sales as well. Thanks, Charlie. Okay. Thank you for the time this morning. Thank you, Dariusz. Thank you. As there is no further question, I would like to turn the call back over to Stephanie Amaimo. Thank you, Ruel. We have nothing further at this time. Thank you for participating in our first quarter 2022 results conference call. Please contact investor relations should you need anything further. Thank you for your time, and have a great day. Thank you for participating, ladies and gentlemen. This concludes today's conference call. You may disconnect.