Ladies and gentlemen, thank you for standing by. My name is Phyllis, and I will be your conference operator today. Welcome to the Fortis Q3 2021 Results and new five-year Capital Outlook 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 one on your 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. Thanks, Phyllis, and good morning, everyone, and welcome to Fortis' third quarter 2021 results, a new 5-year capital outlook 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 third quarter of 2021 MD&A. Also, unless otherwise specified, all financial information is referenced 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 third quarter results as we continue to deliver safe and reliable service while navigating through the pandemic. Financially, our third quarter results reflect strong core operations, moderated by a lower foreign exchange rate and cooler than normal weather in Arizona. On a year-to-date basis, we have delivered strong earnings growth absent foreign exchange. We are on track to deliver our CAD 3.8 billion capital plan for 2021, with CAD 2.6 billion invested through September. Additionally, we recently announced a dividend increase of approximately 6%, marking 48 consecutive years of dividend increases, a record we are very proud of. Before getting into our new five-year plan, I'd like to discuss the recent executive leadership developments here at Fortis. Last month, we announced that Jim Laurito will retire at the end of the year from his role as Executive Vice President of Business Development and Chief Technology Officer. Many of you know Jim as he has been working in our industry for many years. Jim, we appreciate your immense contributions to Fortis and wish you and Vanita all the best in retirement. On a personal note, Jim, I'd like to express my sincere gratitude for the guidance, advice, and friendship that you have given me over these last seven years. We announced the appointment of Stuart Lochray, Senior Vice President of Capital Markets and Business Development. We welcome Stuart to the Fortis family in the third quarter and look forward to his support in building on the momentum across our businesses to execute on our growth strategy. Turning now to slide five, our new 5-year plan calls for the investment of approximately CAD 20 billion from 2022 through 2026, showing our ability once again to extend our strong underlying organic growth. This balanced low-risk plan is expected to translate into average annual rate-based growth of approximately 6%. Our plan shows we've come a long way since October of 2016 when Fortis acquired ITC and was first listed on the New York Stock Exchange. After that transaction closed, we rolled out a 5-year capital plan of CAD 13 billion for 2017 through 2021. While that seemed ambitious at the time, we're now on track to invest approximately CAD 18 billion, an additional CAD 5 billion over that same period, translating into rate-based growth of CAD 8 billion or 6% on an average annually. The new capital plan invests in our energy infrastructure and supports a cleaner energy future and includes CAD 1 billion of incremental investments in our regulated utilities. Drivers of the increase include customer growth, enhancements to transmission reliability and capacity, and investments in cleaner energy. This growth in capital is reduced by a lower assumed exchange rate, which decreases the plan by approximately CAD 600 million. The new plan is highly executable, with approximately 85% consisting of relatively small projects. The remainder consists of what we define as major capital projects, those exceeding CAD 200 million or just 1% of the five-year capital plan. Our plan includes 11 such projects, including the CAD 200 million-dollar Okanagan capacity upgrade project at FortisBC that will address customer growth in the region through expansion of the existing natural gas transmission system. As the pie chart on the left-hand side of slide eight highlights, nearly all of our new capital plan supports energy delivery and the transition to a cleaner energy future. Our utilities are planning for cleaner energy investments of CAD 3.8 billion through 2026, a CAD 500 million increase compared to our prior plan. This increase is driven mainly by additional renewables and energy storage in Arizona and renewable interconnections at ITC. In Arizona, Tucson Electric Power expects to invest in 275 MW of energy storage and another 90 MW of solar projects to support its Integrated Resource Plan and exit coal by 2032. ITC plans to invest in transmission to interconnect renewables, including 2,800 MW of generator interconnections in the U.S. Midwest and in Multi-Value Projects. At our Western Canadian Electric and Gas Utilities, clean energy initiatives include renewable and liquefied natural gas investments in British Columbia and distributed energy resource integration investments in Alberta. Investments in the Wataynikaneyap transmission project in Ontario and alternative energy technologies and battery investments in the Caribbean also support our sustainability strategy. Our carbon emissions reduction target is on track as we reduce emissions by nearly two million tons in 2020. With our continued investment in cleaner energy infrastructure, the planned closure of the San Juan Generating Station next year, and the beginning of seasonal operations at Springerville Generating Station, we are well on the path to meet our 75% carbon emissions reduction target by 2035. Our target is balanced and ensures reliable and affordable service while providing time and support for impacted communities. By 2035, we expect 99% of our assets will be related to energy delivery and renewable carbon-free generation. Beyond reducing scope one emissions, all of our utilities are focused on improving their environmental footprint, including their scope two and three emissions. Through investments in RNG and LNG, renewable interconnections, electric vehicles, energy efficiency initiatives, and other efforts, we are working to reduce economy-wide greenhouse gas emissions. In addition to improving our already low carbon footprint, the capital plan also supports steady rate-based growth across our portfolio of utilities. Central Hudson continues to lead the way with average annual rate-based growth of over 7%, driven by investments in infrastructure upgrades and information technology. Our consolidated rate-based growth will be mainly driven by our three largest utilities, ITC, FortisBC, and UNS Energy. The plan is expected to increase rate base by CAD 10 billion from approximately CAD 31 billion in 2021 to nearly CAD 42 billion in 2026, supporting average annual rate-based growth of approximately 6% through 2026. We have many other opportunities that could expand and extend growth at our regulated utilities, which are not reflected in our capital plan today. As we have previously discussed, ITC is strategically positioned in the Midwest to invest in incremental transmission required to support a renewable energy transition in the United States. The Lake Erie Connector Transmission Project and the MISO Long-Range Transmission Plan could be large additions to our plan, and we expect to have additional clarity on these opportunities early next year. In Arizona, Tucson Electric Power's Integrated Resource Plan will require investments in renewables and battery storage beyond 2026 in order to exit its coal generation in 2032. At FortisBC, reducing customer greenhouse gas emissions continues to be a priority. Whether it's LNG, renewable natural gas or hydrogen, the infrastructure needed to support a decarbonized economy will complement our organic growth strategy and support CleanBC's roadmap to reduce customer greenhouse gas emissions. In light of these opportunities, as well as the potential acceleration of a clean energy transition in North America, we remain optimistic that we will be able to secure investments that will be additive to our current plan. Next, I'll spend a moment discussing recent increases in commodity prices and supply chain considerations given the impacts the pandemic is having on the economy. First, we are seeing increases in natural gas prices, which are impacting our utilities in British Columbia, Arizona, and New York. While hedging policies and recovery mechanisms for these costs vary by regulatory jurisdiction, they are ultimately recovered from customers. This is expected to increase our customers' rates while these higher costs persist. As prices moderate, the same mechanisms will allow those rates to decrease. We remain focused on mitigating customer bill impacts through energy efficiency and conservation programs wherever possible. We will also continue our efforts to manage costs across our enterprise through innovation and process improvements to maintain affordable service to the communities we serve. As it relates to the supply chain, our Fortis operating group is focused on proactively managing our supply requirements with coordinated buying and utilizing supplier alliances to maintain reliable service and ensure the execution of our capital plan. Notably, to date, we have had only minor supply chain concerns. However, we are currently doubling down on our supply chain efforts to be ready for 2022 and beyond. Due to the length of our planning cycle and the long-term nature of our capital plan, the recent price increases for commodities such as steel and copper are not fully reflected in our five-year plan. We will be evaluating these impacts going forward. As I mentioned, last month, our board of directors declared a fourth-quarter dividend of CAD 0.535, representing an increase of approximately 6%. Again, this marks 48 consecutive years of dividend increases. The strength of our local energy delivery businesses, coupled with our diverse geographic and regulatory footprint, positions us well to extend this record. To that end, today, we are reaffirming our 6% average annual dividend growth through 2025. Now I will turn the call over to Jocelyn for an update on our third-quarter financial results. Thank you, David, and good morning, everyone. Turning to slide 15, reported earnings per common share for the quarter was CAD 0.63, consistent with the third quarter of 2020. Adjusted earnings per common share was CAD 0.64, CAD 0.01 lower than the third quarter of 2020. During the quarter, cooler weather in Arizona tempered earnings by CAD 0.05, while a lower foreign exchange rate lowered EPS by CAD 0.03. Excluding these impacts, our regulated utilities delivered strong results driven by rate-based growth, new customer rates at TEP, and higher earnings at ITC, FortisAlberta, and in the Caribbean. For the nine months ended September 2021, adjusted EPS was CAD 1.96 per common share, CAD 0.08 higher than the same period in 2020, and this growth was despite the FX impact of CAD 0.10 year-to-date. Before getting into the specific drivers of the quarterly and year-to-date earnings results, I want to touch on the recent sales trends across our utilities. Similar to the previous trends we discussed last quarter, we continue to see an increase in the commercial and industrial sales and lower residential sales. Notably, commercial and industrial sales increased 6% for the quarter. Lower residential sales were associated with decrease in work-from-home practices and cooler weather in Arizona, and this was partially offset by warmer-than-normal weather in Alberta. Taking a further look at Arizona, retail sales were down in the quarter by approximately 8% compared to the same period in 2020 due to cooler temperatures, which reduced air conditioning load in the region, equating to a 5% EPS impact. As you can see on the slide, during the third quarter of 2020, Tucson recorded the hottest month on record. Absent weather impacts, retail sales in Tucson were down 1%, driven by lower residential sales, reflecting changes in work-from-home practices, partially offset by higher commercial and industrial sales. Slide 18 highlights EPS drivers for the quarter by segment. At ITC, rate-based growth and an adjustment related to interest rate swaps contributed to a CAD 0.05 increase in EPS. Our Western Canadian regulated utilities contributed a CAD 0.03 EPS increase for the quarter, driven by rate-based growth as well as higher sales due to favorable weather and the timing of expenditures in Alberta. At our other electric segment, EPS increased by CAD 0.01, driven by higher sales in the Caribbean due to the continued recovery of the tourism industry. At our U.S. electric and gas utilities, EPS decreased CAD 0.03 in the quarter. CAD 0.01 was driven by lower earnings in Arizona due to the cooler weather I discussed earlier, and this decrease was partially offset by the impact of new customer rates at TEP, effective January 1, 2021. In New York, Central Hudson decreased EPS by CAD 0.02, mainly driven by the timing of its pending rate decision. A decision is expected to be concluded in the fourth quarter, and once the outcome is finalized, earnings associated with the delay are expected to be recognized. At our energy infrastructure segment, EPS decreased CAD 0.03, mainly due to realized losses on natural gas contracts at Aitken Creek. Contracts were settled during the quarter of 2021 in consideration of market conditions and favorable forward curves. Higher weighted average shares outstanding issued through the dividend reinvestment plan decreased EPS by CAD 0.01, and the US dollar to Canadian dollar exchange rate of $1.26 for the quarter compared to $1.33 for the third quarter of 2020. This unfavorably impacted quarterly results by CAD 0.03. Turning to slide 19, this waterfall breaks down the EPS drivers year-to-date through September. To not repeat myself, the EPS drivers for year-to-date largely reflect the same factors discussed for the quarter by segment, except that on a year-to-date basis, earnings were higher in Arizona due to new customer rates at TEP, partially offset by lower sales due to cooler weather and higher operating costs. All in all, our utilities have delivered strong underlying earnings growth year-to-date absent foreign exchange. Turning now to our funding plan, the new five-year capital plan is expected to be funded with cash from operations, debt issued at our regulated utilities, and our dividend reinvestment plan. With no discrete equity required to fund the capital plan through 2026, the funding plan is largely consistent with last year's plan, and our capital structure is expected to remain steady over the planning period. Overall, we continue to take a conservative approach to running our business, and our funding plan positions us comfortably within our existing credit ratings through 2026. In particular, Moody's CFO-to-debt metric is expected to average 12% through 2026, and S&P's FFO-to-debt is expected to average above 11%. Both the Moody's and S&P metrics are above their respective thresholds and provide ample cushion to maintain our current ratings. Turning to recent regulatory developments, first, ITC awaits a final rule from FERC in relation to the supplemental notice of proposed rulemaking on transmission incentives, which proposes to eliminate the 50 basis points RTO ROE incentive. Although any potential impact remains uncertain, every ten basis points change in ROE at ITC impacts Fortis' annual EPS by approximately one cent and would be applied prospectively. Next month, FERC will hold a technical conference in connection with the advanced notice of proposed rulemaking issued in July 2021, focusing on regional transmission planning, cost allocation, and generator interconnection processes. This progress is positive and underscores the important role transmission plays in achieving the Biden administration's climate goals. At Tucson Electric Power, you may recall that in 2019, FERC issued an order accepting formula transmission rates as filed, including an ROE of 10.4% and equity thickness of 54%, subject to refund and settlement procedures. A settlement in principle was reached in August 2021, and the procedural schedule was suspended to allow the settlement to be finalized. The timeline and outcome of this proceeding remains unknown. In New York, Central Hudson filed a joint proposal in August seeking a three-year rate plan effective July 1, 2021. The proposal includes an ROE of 9% and an equity layer of 50%, declining by 1% annually to 48% in the third rate year. The proposal also reflects the use of existing regulatory balances and other measures to reduce impact bill impacts, as well as initiatives to support the state's climate goals. An order from the New York Public Service Commission is expected in the fourth quarter of this year. That concludes my remarks. I'll now turn the call back to David. Thank you, Jocelyn. Why invest in Fortis? It's simple. With the strength of our utilities and local business model, we offer long-term, low-risk, diversified growth, as demonstrated by our new five-year capital plan, a plan that supports our dividend growth guidance through 2025. We remain optimistic about the path ahead as we pursue incremental growth opportunities that will allow us to deliver a cleaner energy future for all our stakeholders. 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. Ladies and gentlemen, we will now conduct the question-and-answer period. If you would like to now register a question, please press the star followed by the one on your telephone. 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 to 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 with RBC Capital Markets. Thanks, Ann. Good morning. My first question is to just pick up on the 6% rate-based growth you've announced. Any thoughts on what this rate-based growth may translate to in terms of EPS growth? Taking this a step further, have you seen a change in your ability to achieve a similar 6% translation versus, say, in the past? Has this ability changed? What has changed? Yeah. Thanks, Maurice, and good morning. Good to hear from you again. As you know, we don't give earnings guidance, and we obviously give rate-based guidance as a proxy to somewhat. Of course, on a longer-term basis, we would expect rate-based growth and earnings guidance to converge. Obviously, in a business like ours, where we have different regulatory cycles and ups and downs, et cetera, in investment, it's not linear. On a longer-term basis, I mean, that's what we would all expect. Thank you. My second question is on the dividend growth guidance. You've reaffirmed your growth guidance, which takes you to 2025. Traditionally, we've seen you extend this guidance in lockstep with the length of your capital plan. Is it a case of maintaining flexibility in the outer year, or is there something else that motivated this decision? Thanks, Maurice. You answered the question yourself. You know, the four years is still a long time to be given dividend guidance, and we wanted to make sure that we were reaffirming the guidance that we had put out there, and keeping that, and obviously showing a plan that supports that, which is key. That, of course, paired with our track record of hitting that, I think is the right spot to be in. As we see, you know, in essence, half a trillion dollars of additional investment opportunity and government support in the U.S. related to the budget reconciliation bill, we think that there's gonna be a lot of opportunities in the tail end of our five-year plan, as we mentioned. We mentioned some of them, but there's this big bucket of what does all of these additional investments mean? Does the drive for a faster clean energy transition in the U.S. translate into additional investments for us? We think that answer is yes, but we have to see how that trickles down over time. We'd like to maintain some flexibility in the tail end of our five-year forecast to be able to address that. Thanks. Maybe just a quick follow-up and just to tie this first and second question together then. If you expect over the long term for EPS and rate-based growth to converge, and in this case, you're hoping to have flexibility on the dividend outer year, is there a target dividend payout ratio that in your mind you're looking at, as you balance all these? Not really, Maurice. I mean, these are conversations we have every year with our board of directors to, you know, based on the situation in that year and how we see things on a going-forward basis. Yeah, we don't have a target in mind as we sit here today. Okay. Thank you. Our next question comes from the line of Ben Pham with BMO. Please proceed with your question. Hi. Thanks. Good morning. First question on the quarter specifically. Do you expect any of your segment results in Q3 to reverse into Q4, whether positive or negative? Or do you expect that to mostly flow into your realized ROE? Yeah, the question. I'll kick over to Jocelyn. It was breaking up a little bit there, but whether or not we see any earnings timing between Q3 and, say, Q4. Do we expect any of this to reverse? Hi, Ben. Thanks for the question. Yeah, we do have some timing. We referenced Central Hudson's rate case. Clearly, that's a deferral of earnings that we would've originally expected in Q3 because new rates were to be effective July 1, but now that's moved to Q4. We did have some timing of some costs also in Alberta that we, you know, did move earnings to Q3 versus Q4. Outside of that, no major other timing variances that we see between the quarters. Okay. Great. Your comments around the commodity price situation not being reflected in your base plan, should we read that as more there's a flow-through upside to your CapEx as you start to bake that in? Or is it more reflective that it could temper your growth outlook with the rising prices on the commodity side? Well, Ben, we have a base capital plan that's real projects. If those projects have higher costs, then those costs would be built into that capital and would end up getting passed through as higher costs and capital costs, et cetera, on a going-forward basis to customers through rates. We do have to pay attention very closely to control those costs because we wanna make sure we're getting the most bang for the invested buck for our customers. At the end of the day, it wouldn't drop out capital projects. It would just increase the cost of them, which makes us really focus on across our entire footprint in every one of our subsidiaries, to focus on other cost reductions that we can do for our customers to help them manage the bill impacts. Now a lot of these things that you have to remember from a capital perspective, a lot of these projects don't necessarily add to, you know, customer rates. Just for an example, in Arizona, when we are shutting down our coal plants and replacing them with solar and battery storage, that actually saves our customers money. There's some of that in there as well. Okay. Great. Maybe last, if I may, acquisitions. Would love to hear updated comments on that as you rolled over the CapEx program, whether large scale or smaller scale. Updated on what? I missed the question, Ben. Updated on M&A stuff? Yeah. Would love your thoughts on appetite for M&A as you've gone through your budgeting process and looked at upside to the plan, downside to the plan. I know you've communicated thoughts on that in the past, but would wanna hear if you're more maintaining your past view, or is there a slight change in appetite? It'll probably sound really familiar. I mean, this is a big capital plan. It was a big deal to get the CAD 20 billion capital plan put together. It'll be a big deal to execute it. We are not resting on our laurels and saying CAD 20 billion capital plan's enough. We're gonna be out shaking the bushes, looking for additional investment opportunities that are right for our customers and our stakeholders and our shareholders. We will continue to keep that as our number one focus. That doesn't mean we're sitting here asleep at the switch and not paying attention to things that are going on in the market and looking for opportunities that can add value for our shareholders as well. We will continue to be, you know, good fiduciaries looking for opportunities to, you know, to find value even outside the capital plan for our company, like we always have been. Okay. That's great. Thank you. Our next question comes from the line of Linda Ezergailis with TD Securities. Please proceed with your question. Thank you. I'm wondering, as you look at those opportunities out there, what, you know, what sort of guardrails are you imposing on your world of possibilities as it relates to geographies, technologies, commercial attributes? Specifically interested to hear whether you see any initiatives around hydrogen of whatever color or attribute, or carbon capture as within the range of possibilities and how they might manifest themselves in leveraging your competencies in your existing footprint. Yeah, Linda, we don't really have any, you know, guardrails around looking at some of these investment opportunities because we are gonna probably cast a pretty a wide net. They have to fit within our, you know, risk-return profile, right? If we're gonna do an investment, it has to, you know, look like a lot like a regulated investment always has looked to us. Whether it's looking at things like hydrogen or carbon capture utilization storage, I mean, each one of our jurisdictions has different pieces that they're looking at for some of these new technologies. Out in British Columbia, renewable natural gas, hydrogen opportunities, that's where we're gonna probably be looking at that and testing the water. If the investments don't meet our, you know, risk return appetite, then, you know, we won't do them. We don't have any real guardrails on those types of investments. We don't start with any guardrails on that. We have got a great sustainability picture as we sit here today with 93% of our assets being T&D. We will always have in the back of our mind the fit on investments and how that impacts or affects our ESG profile as well. Okay, thank you. Maybe just some thoughts around when you are considering new projects or opportunities how you might approach the financing part of the equation. In the past, you have looked at partners for various reasons. You know, those tended to not have come to the top of the list. Now you might have some, like, sustainability financing linked opportunities as well. Can you just talk about how you think you might approach financing any additional opportunities? Thanks, Linda. This is Jocelyn. Yeah, I think, you know, with additional capital above and beyond the base plan, I've said this before, and this may also sound like an old story, but, you know, everything goes on the table. We have used partners. We typically like to do it ourselves, but we have used partners. It depends on the size of the project. You're absolutely correct that you're going to see more sustainability-linked financings associated with our investments because the investments are likely to be in the space of the green energy investments with what's happening, particularly in the U.S. But at a very high level, everything goes back on the table because it depends on the amount of growth and the timing of growth. We will look at everything from asset sales to equity to partners, and everything in between. I think everything goes back on the table. Okay, thank you. Just as a follow-up, given the expectation that interest rates might be going up, how might you think about potentially pre-funding, taking a more conservative approach to kind of lock in any sort of financing costs associated with the capital spend that you're certain will come? Yeah, Linda, I think you've hit it. We did the same thing in 2020 as well. When COVID hit, we advanced a lot of financing. I know right across our organization now, we are looking at all of our financing, you know, where it's appropriate to do interest rate locks or whether it's appropriate to advance. All of our subs are looking at this. Most of our financings are within the regulated utilities, as you would know. And in some of those utilities, we do have mechanisms whereby the interest costs or rising interest costs are actually included in regulatory deferral mechanisms or a part of the PBR structure where it's shared with customers. But yes, it is something that we're always looking at, and advancing financings is certainly one of the options. Great. Thank you. I'll jump back in the queue. Our next question comes from the line of Rob Hope with Scotiabank. Please proceed with your question. Good morning, everyone. Just want to first focus on kind of some of the potential additions to the capital plan. Lake Erie Connector, the government's kind of, you know, looking at that plan. Can you maybe comment on kind of your discussions with off-takers there, as well as kind of what next steps and when that could be put in the capital plan? Yeah, there's only one off-taker, and that is the IESO. So that's the contract negotiations that we are currently in the midst of. There's not really much to tell you in the middle of contract negotiations. You know, obviously turning term sheets back and forth and trying to come to the agreement of the deal structure. We do expect, and the Minister of Energy in Ontario is requesting that report back by the end of this year. So we are going as fast as we can to make sure we get that done by the end of the year and get that report back to the Minister. All right. That's helpful. Just taking a look at FortisBC, we saw some CapEx move in this plan. Can you kind of give us an update on, you know, some of the larger opportunities there, including, you know, additional LNG as well as kind of the Woodfibre project connection and where these all stand? Yeah, certainly. I'm actually going to turn that one over to Roger Dall'Antonia, who's the CEO of BC, and he's on the line. Roger, will you want to address that? Yeah. Morning, everyone. Thanks for the question, Rob. On Woodfibre LNG, continuing to work closely with Woodfibre LNG. They are, l ooking to make FID here potentially as early as the end of the year. Progressing that project, but nothing materially new on the expectation that we laid out I think last quarter. As far as other opportunity, the focus for us is LNG bunkering right now, working closely with proponents and the government on the EA process on the Tilbury Marine Jetty. Once that is in hand, we would look to an expansion of the opportunity for LNG bunkering. All right. Thank you. Appreciate the color. Our next question comes from the line of Michael Sullivan with Wolfe Research. Hey, everyone. Good morning. Morning, Michael. My first question was just can we get a little more of an update on the latest expectations for timing around the MISO long-range transmission plan and any additional color on expectations there? Yeah. The timing has slipped as I think we were kind of reiterating earlier this year that it was gonna be quite a feat to get those projects in front of the board before the end of the year. Indeed now MISO is publicly saying that study, basically the first mover project should be out in February of 2022, with the hope of getting those before the MISO board for approval in March of 2022. It has slid, which is, you know, we wanna hear the outcome of that probably more than anyone else. As soon as we hear it, we'll make sure that we get that out to you all as well. Okay. Great. Thanks. My second question was just can you quantify the earnings pickup that we should expect from the New York rate order in Q4 if the settlement's approved as is? As a follow-on to that, just remind us how that addressed COVID in New York and any potential recovery there. Michael, this is Jocelyn. I would say a couple of pennies, two pennies that you'll see a pickup from what should have probably been recorded earlier rather than later. You'll see that pickup in Q4. On the details around the pieces that are included in the settlement from a COVID perspective, the other half of your question. Charlie, you want to provide any color on that? In relation to COVID, a couple of things were addressed for Central Hudson, even though the generic proceeding in New York continues. For Central Hudson, part of our revenue requirement comes through finance charges, and obviously, finance charges have been put on hold throughout COVID. We did get treatment related to the lost revenue associated with finance charges, and we also were able to get deferral treatment for bad debts as well. Both of those are elements that are part of the generic proceeding but were addressed directly in our settlement discussions. Got it. Super helpful. Thanks, everyone. Our next question comes from the line of Mark Jarvi with CIBC Capital Markets. Please proceed with your question. Thanks. Good morning, everyone. I want to come back to investments like the Lake Erie Connector project or for something similar that you do down the road like that might not be in rate base. How would you think to frame that in terms of growth and impact if it's not going to be in rate base and your hesitation to provide EPS growth? Yeah, I think, well, the way you should think of that is it should look like a, you know, kind of a rate base asset. I mean, it's basically what we're trying to do is make this look like a contracted asset that mimics a rate base. You know, obviously the levels of, you know, return, equity, all of that stuff are part of the negotiation. We really can't give you that level of detail now. That's how we're viewing it, and that's how you should view it as well. If you were to sign a document on that agreement, you would kind of quote, unquote, put it in as sort of rate base then in your growth forecast? Would we put it in as a rate base in our capital forecast? Yeah. No. It wouldn't. It would be in the capital, but not in a rate base number. Got it. Okay. Obviously, there are a lot of headlines around Arizona, around another utility in the state. Maybe you can take this opportunity to kind of give us your updated view, maybe contrast, compare how you guys see your sales position versus APS. Obviously, you've already done your rate case, sort of updated views given all the headlines going on there. Mark, I'm glad you asked, and I'm amazed that this question fell so far down the queue. I thought that it was on everybody's mind, given some of the analysis around the case, the APS's case, recently. You know, I'll start out by saying this is definitely a utility-specific situation. This isn't a systemic issue or problem from a regulatory perspective, in the state of Arizona. I think if you listened, and you probably did, as I did, listen to some of the hearing, I think you'll see that that's how these issues are being addressed and the rhetoric around them from the commission is a utility-specific situation. Now you and us and the utilities that we have in Arizona have a very good working relationship with the commission. We do everything that we possibly can to make sure that we build the trust with our regulators, and we do that through making sure that we're transparent and we have integrity with everything and every interaction that we have with that commission. That's been our MO. I've been testifying in front of that commission for almost 20 years and can tell you that we make sure that we always do the things because we know that we got to do the things that maintain that trust because we know as hard as it is to build that it can go away pretty quickly. I think the most important part of our business structure from a Fortis perspective is the fact that we have a business model that has the people on the ground in our jurisdictions managing these relationships. That's absolutely critical to make sure that we maintain them and know exactly where those regulatory outcomes are gonna come. Speaking of regulatory outcomes, you mentioned I can't believe it was less than a year ago. Less than a year ago, in December of 2020, we actually got a very constructive rate outcome from the corporation commission for TEP. You know, that I think is indication. It was in the middle of COVID, we're still in the middle of COVID. There's not a lot of things that are different, but we obviously got quite a bit of different treatment and quite a bit different outcome than what you're seeing. I guess that's a long way of saying that the situation there shouldn't be projected through to other utilities in the state, including ours. Got it. Thanks for those comments. Just coming back to the supply chain question and some rising CapEx costs. Can you just remind us again, like, on the PBR-based utilities like at Western Canada, I assume that there's capital trackers and things to manage that. Is it just the utilities with the historical test here, or would there be regulatory lag where you might feel a bit of, I guess, temporary pressure from higher CapEx costs? If you can kind of comment in terms of any sort of transient impacts around that. Yeah, you hit the nail on the head there. The Canadian utilities have PBR. They actually have inflation built into their rates as well, capital trackers, et cetera. ITC has a forward test here, so that all gets trued up. It's really probably only Arizona that would see a little bit of a drag on increased costs from an O&M and capital perspective. In Central Hudson? Central Hudson. Charlie, you know, I have to say that that's the rate structure I don't know quite as well as the rest. Charlie, you wanna opine on that? We have approved capital budgets and net plan targets within our rate structure. If we experience higher costs, what it would typically do is not increase our capital budget in a particular year, but it would really kind of extend out our projects over longer periods of times because it may displace another project in order to cover those costs. Got it. That's very helpful. Thanks, everyone. Thank you. Our next question comes from the line of Andrew Kuske with Credit Suisse. You may proceed with your question. Thank you. Good morning. Probably a question to start off with David, and it's really about your, I guess, your last home state in the U.S. and Arizona. You're there, UNS as a standalone and really under the Fortis umbrella, not really impacted by a lot of the regulatory noise. I guess it's a bigger, broader question just from a regulatory philosophy. You know, what's your thought on jurisdictional concentration, where you're the only utility in a region versus having, you know, we could call it a foil, a competitor, or comparable within a certain jurisdiction that you can effectively play off as you've done in Arizona over the years? Yeah, Andrew. Yeah, that's an interesting question. I think really we don't really look necessarily to have a foil or hide behind, you know, other utilities. You know, we just wanna be the best utility that we can be and let our record and the transparency that we give to our regulators stand on its own and create that relationship. We're not necessarily looking for, you know, for a foil as it were. We are focused on doing regulation right. We're focused on having that relationship again with the regulators and making sure that we, you know, stay on side in everything that we do. There's a lot of, you know, competing interests that show up in a regulatory proceeding, and we wanna make sure that we have those relationships, not just built around the com-- with the commission, but around all of those stakeholders. I think a great example of that is the process that we went through down in Arizona to get the Integrated Resource Plan done. It was that broad stakeholder process that brought everyone together. That's the kind of atmosphere that regulators are looking for these days. They have, obviously, agendas. They have plans and policies they wanna implement, and we gotta show up and help them implement those policies. Okay. That's helpful color and context. I guess the next question, it's along the lines of regulation, but it's probably also more directed towards Roger, and it's really just on, you know, RNG. And obviously, it's important. It's a small part of the overall business, but if you could just give us some color and context on, you know, just your RNG activities in BC and really beyond. Yeah. Roger, you wanna take that? Yeah. Thanks, Andrew. The RNG story is developing quite nicely in BC. Back in the summer, the BC government amended the greenhouse gas regulation around RNG. We had previously a 5% renewable portfolio allowance, if you will, and that got moved to 15% and included additional renewable gases such as green hydrogen, lignin-based fuels from the forestry industry. We announced our 30 by 30, which included 15% of our natural gas portfolio coming from renewable gases by 2030. We're probably a third of the way there with signed contracts. I think we're just over eight petajoules approved by the BCUC. We have a couple more contracts that we still have to file, so we're approaching 10 petajoules in about the first two years of announcing our plans to increase RNG. We're well on track to get to the target we set for ourselves in 2030. B.C. government just announced CleanBC, which is a very ambitious plan on carbon reduction. We expect further opportunities on the RNG front to come. If I can, maybe just one follow-up on that. You know, Roger, how broad-based are your procurement activities? Because we talked to a number of utilities that increasingly have RNG goals and aspirations, but there's only so much of it out there. How broad-based are your acquisition activities at this stage? Right now we're signing procurement deals across North America. We've got, I think, now two contracts approved from U.S. projects. We have a handful of contracts approved outside of BC, Alberta and Ontario. We're really looking at RNG from a North American grid perspective. Anything that we can tie into the grid that can be delivered to BC is what we're pursuing, so we have a pretty big footprint. Your comment on more utilities chasing RNG, I think is a fair one. That's why hydrogen over time will become an increasingly important part of the mix. It won't simply just be the landfill waste water treatment plants or agricultural. That'll still be important, but I think hydrogen, blue, green or otherwise will be an increasing part of the renewable gas mix. Okay. Thank you very much. Our next question comes from the line of David Quezada with Raymond James. Please proceed with your question. Thanks. Morning, everyone. So my first question here is just on the topic of interregional transmission planning as it relates, I guess, to ITC. I understand FERC has had some discussion with the industry on a right of first refusal for incumbent utilities. There's been some discussion around that as well as potential requirements for more in-depth, I guess, interregional transmission planning. Just curious how those concepts, how you see them developing and how that could affect things at ITC maybe in the longer term. Thanks for that, David. Or that question, David. I'll turn that over to Linda to address. Great. Thank you and good morning. Thanks, David, for the question. Yeah, you know, look, I think it's hard to specifically know or understand how FERC will specifically address the ROFR issue. I can tell you that it's definitely on their radar screen. I think there was significant amount of comments that were made around the ROFR, the competitive provisions of Order 1000 in the ANOPR comments that were filed. I mean, there have been some comments made by various over various points in time that have indicated that they also believe that, you know, those competitive provisions of Order 1000 have stood in the way of realizing sort of these regional transmission projects. From our perspective at ITC, you know, we have actively been pursuing ROFR legislation in our various states. We have ROFRs in Iowa, we have a ROFR in Minnesota, and we are in the process of pursuing, along with other utilities, a ROFR in Michigan. To the extent that we can reinstate the right of first refusal in our footprints, it certainly would protect us in terms of any future, you know, regional transmission projects. But I do think FERC needs to address the issue more holistically, because I think right now, approximately half of the states in the U.S. are covered under, you know, kind of ROFRs or the competitive provisions don't apply because their members are not in an RTO. It's not a holistic proposal the way at least it's currently structured. We're hopeful that FERC understands that these competitive provisions have really stood in the way of realizing the needed investment in transmission to facilitate sort of the new green economy. That's great color. Thank you for that, Linda. Maybe just one other one for me. I saw a comment, I guess, in the presentation about IPP interconnections in Western Canada. I'm just curious if what nature of projects those are. Would that be your share of transmission investments in Alberta or something different? Yeah, those are just connections to Alberta's distribution system that we own out there. There is a lot of activity in Alberta related to distributed resources and of course that needs us to interconnect them and that's what that reference is. Understood. Thank you very much. Yep. Again, if you would like to ask a question, please press star then the number one on your telephone. Our next question comes from the line of Matthew Weekes with iA Capital Markets. Please proceed with your question. Good morning. Thanks for taking my question. I think some of the kind of downside to earnings on Central Hudson was quantified a little bit. I was wondering if you'd be able to provide some color or quantify how much maybe of a positive impact one-time events might have had at ITC in terms of the interest rate swap adjustment and the timing of expenditures in Alberta and maybe some one-time adjustments there as well. Matthew, with respect to the swap adjustment that we made at ITC, this related to a swap that had been executed previously, and this was just truing up some amortization related to a swap that they had. That was pushing CAD 0.02 in the quarter. You won't see that again. That's just more of, like, a one-time thing. With respect to Alberta, you know, I would say from a timing from Q3 to Q4, potentially with respect to expenses, probably about CAD 0.01. I mean, that's all we're talking about. It's not material in terms of what we're seeing between one quarter and the other, but that's about the extent of, you know, the changes between the quarters. Okay. Thank you. That's helpful. I'll leave it there and turn the call back. Our next question comes from the line of Dariusz Lozny with Bank of America. Please proceed with your question. Hi, good morning, and thank you for taking my question. Most of them have been answered already. Just to come back to COVID, as it relates to the Central Hudson settlement, just wanted to clarify. There's some language in there about, I believe it's Central Hudson potentially convening some discussions to specifically discuss the resolution of arrears that are related to COVID. I'm just curious absent much updates in the generic New York docket, have those discussions taken place? And if so, can you give any update there? Yeah, I'll turn that one right over to Charlie. Thank you, Dave. The New York Public Service Commission staff had put out a white paper associated with arrears management programs and related to COVID specifically. That is essentially been rolled into the generic proceeding. In our resettlement discussions, there was a lot of conversation around arrears management programs. We felt that it was best not to try to address that as an individual utility, recognizing it is within the generic proceeding. Rather than come to a conclusion on how we're gonna handle an arrears management program, we agreed that we, following the agreement being approved, that we would, you know, participate in conversations about the different options associated with it. Now, as I mentioned earlier, within our settlement, we did come to agreement related to finance charges, we did come to agreement related to bad debt, and we did come to an agreement related to some of our COVID costs. The concept of arrears management is a little bit more complicated, and a number of different ideas have been thrown around, which is why we agreed to not tie up our individual settlement when it was also being handled through a generic proceeding. I hope that answers your question. Yes. That's very helpful. Thank you very much. If I could ask one more quickly. Sure. On Alberta, it looks like I realize it's a smaller piece of the overall pie, but it looks like on a percentage basis from last year's plan to this one, the planned CapEx over five years increased substantially. Can you just talk a little bit as far as is that a relative determination for that jurisdiction versus others or just maybe specific opportunities that you're seeing there that perhaps you didn't one year ago when you put out the other plan? Just curious about the puts and takes there. Yeah. Darius, thanks for that question. It's really a bit all over the map in FortisAlberta because it's not like one big project or anything. It's customer growth and sustainment investments and new technology, et cetera. So there's a little bit of everything in that pot. I think probably what happened on a year-over-year basis from a plan perspective is last year when we were sitting here at this time, we basically had oil at $40 a barrel. Now it's at $80 a barrel. We were probably at the doldrums of the economy in Alberta as well as in the deep throes of COVID, although we're still there. From a forecast perspective, we weren't seeing a lot of that growth opportunity going forward. Now we do. We see some of that growth coming back. We see oil and gas coming back. Frankly, we have looked at the capital budget with a closer eye and looking for opportunities. Investing in resiliency is also a big add there that the team has done since last year. It's all of those things combined. It's not one specific like project to point to. Okay. That's very helpful color. Thank you, and I'll turn it back. Thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo. Thank you, Phyllis. We have nothing further at this time. Thank you everyone for participating in our third quarter 2021 results and new five-year capital outlook 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. You may disconnect.