Good afternoon, ladies and gentlemen, and welcome to the Emera Q3 2024 Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Friday, November 8, 2024. I would now like to turn the conference over to Dave Bezanson, Vice President of Investor Relations. Please go ahead. Thank you, John. And thank you all for joining us for this afternoon's Emera's Q3 2024 conference call and live webcast. Emera's third quarter earnings release was distributed this afternoon by Newswire, and the financial statements, management's discussion and analysis, and the presentation being referenced on this call are available on our website at emera.com. Joining me for this afternoon's call are Scott Balfour, Emera's President and Chief Executive Officer, Greg Blunden, Emera's Chief Financial Officer, and other members of Emera's management team. This evening's discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide. Today's discussion and presentation will also include reference to non-GAAP financial measures. Please refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. And now I will turn things over to Scott. Thank you, Dave, and good afternoon, everyone. We appreciate you joining us on an earnings call at 5:00 P.M. Eastern Time on a Friday. Schedules conspired against us to make this a necessity. With the Edison Electric Institute's financial conference beginning this weekend, we wanted to be sure that you had our most recent quarterly results in your hands before we meet with many of you over the coming days. With that, thank you for making the time, and we hope to make this an efficient call to allow you to get to your weekend as soon as possible. Before turning to our financial results, I want to touch on the record-breaking storms that impacted our customers, communities, and teams in Florida over the last few weeks. I want to express my gratitude to our teams for their tireless efforts and many long hours spent restoring energy to our customers. It was a massive effort. Hurricane Milton was the most powerful storm to hit Tampa Bay in the last 100 years, and the restoration effort by the team was the largest in Tampa Electric's history. As soon as it was safe to do so, a team of more than 6,000 power line technicians, damage assessors, and forestry technicians worked around the clock to safely restore power to all impacted customers. In addition to the local Tampa teams, crews came in from across North America, a testament to the spirit, collaboration, and support that exists across our industry. We even had crews on the ground from Nova Scotia Power, who traveled in to support their Tampa colleagues. Hurricane Milton brought a one-in-1,000-year rainfall event to parts of the Tampa Bay area. This came on the heels of Hurricane Helene, which had already saturated the ground with its record storm surge. This meant that the damage was more significant as trees were more easily uprooted by the heavy winds. Despite the severity of these storms, we were able to effectively complete restorations within a week. This enormous restoration effort involved more than 900,000 work hours in incredibly challenging conditions, and this work was completed with no serious safety incidents. We're all very proud of the entire team for their efforts and what they accomplished for customers. Overall, Tampa Electric's system held up to these storms very well, and it's clear that the extent of the damage would have been worse and restoration times much longer if not for the investments made over the past few years to harden the grid through Tampa Electric's Storm Protection Plan. Investment in reliability and storm protection are essential to ensure timely restoration during major storms, but the value for customers from these investments extends beyond mitigating the impacts and restoration times from severe weather events. As a direct result of the nearly $200 million invested in storm protection every year since 2020, Tampa Electric experienced its best-ever reliability in 2023, and despite the significant storms this year, we've seen very strong reliability to date in 2024 as well. This is evidence of the importance of these investments that allow us to deliver the reliable energy our customers expect. On behalf of our team, I also want to thank the thousands of crews from across the U.S. and Canada that came to Florida to help restore power to our customers as quickly and safely as possible. Storms like Milton and Helene underscore the essential work we do, as well as the incredible cooperation that occurs within our industry to serve and collectively restore power to all customers. Of course, restoration efforts of this magnitude come with a cost. Our restoration costs from Hurricane Helene are estimated to be between $45 million and $55 million. While we can, and from Hurricane Milton, they will be in the range of $320 million- $370 million. While we continue to finalize these costs, we're also exploring options to balance the need for timely recovery through the well-proven regulatory mechanisms in place in Florida with sensitivity to customer bill impacts. We intend to finalize our plans and make our regulatory application to the Florida Public Service Commission in December. The collection of prudently incurred costs on a timely basis is not unfamiliar territory in Florida. Greg will highlight that we recently were able to collect approximately $650 million of deferred fuel and storm costs at Tampa Electric over a 21-month period beginning April 1 of 2023. A different but connected storm-related story was the one we experienced at Peoples Gas, the largest gas utility in the state of Florida. Overall, our gas system held up very well, with virtually no damage through both historical storm events. Throughout and following both storms, the gas system remained operational and available to provide much-needed energy to customers, demonstrating the resiliency, importance, and value of our gas infrastructure in Florida. Turning to the quarter, in September, our board of directors approved an increase to our dividend in line with our dividend growth guidance. This marked the 18th consecutive year of dividend increases. These dividend increases reflect our fundamental confidence in our premium portfolio of assets and our ability to deliver reliable earnings and cash flow growth. Emera shareholders can continue to expect dependable and growing dividends, underpinned by our prudent financial management and disciplined capital allocation. This quarter, the team at Nova Scotia Power worked with the Canadian federal government and the province of Nova Scotia to negotiate a CAD 500 million federal loan guarantee to securitize the remaining deferred fuel costs at Nova Scotia Power. These costs were incurred for replacement energy that was required during the several years of delay in the Muskrat Falls Hydroelectricity Project in Newfoundland and Labrador. This support provides important relief for customers in Nova Scotia by providing cost-effective, longer-term financing with a longer recovery period. It also protects the financial health of Nova Scotia Power, significantly reducing debt, resulting in an improvement in key credit metrics. This securitization is the latest in a series of strategic actions we've taken in 2024 to strengthen our balance sheet and optimize our portfolio to capitalize on the robust growth opportunities that we see ahead. We'll share more details about these opportunities at our investor day on December 4th. Our third quarter results demonstrate our ability to deliver strong earnings growth. Our results for the quarter also reinforce our confidence in the three-year average adjusted EPS growth rate guidance of 5% - 7% that we announced in June. Adjusted earnings per share for the quarter increased 8% compared to last year. This growth was primarily driven by our Florida businesses. Quarter- after- quarter, year- after- year, we continue to see how the underlying economic and population growth in Florida also drives growth for Emera. With Florida experiencing strong population and economic growth, the influx of new customers has directly translated into increased demand for both electricity and natural gas across both residential and commercial sectors. This growth has yielded strong results at Peoples Gas, the largest gas distribution company in the state. With new rates in 2024 supporting the more than $1 billion invested in infrastructure expansion and ongoing investment in reliability since 2021, the meaningful increase in earnings contribution for Peoples Gas reinforces the importance of natural gas to the energy ecosystem and the growth opportunity for the business, especially in a vibrant and growing market like Florida. Tampa Electric also saw strong earnings growth this quarter. While weather has generally been milder in 2024 compared to last year, the impact of electrification, higher demand, and customer growth are helping to offset the impacts of less favorable weather. Before turning it over to Greg, I want to briefly highlight a few important regulatory developments. Last week, Emera, along with New Mexico Gas Company and Bernhard Capital Partners, jointly filed an application with the New Mexico Public Regulation Commission for approval of the sale of New Mexico Gas from Emera to BCP. This transaction was announced in early August of this year. We're optimistic about next steps and pleased with the strong partnership between our organizations as we continue down the path of securing regulatory approval. Finally, later this month, we expect to receive the staff recommendation on the Tampa Electric rate application. While the final hearing has been moved to December 3rd due to an administrative delay, we expect to be able to discuss the outcome and its impact on Emera at our investor day on December 4th, and with that, I'll turn the call over to Greg. Thank you, Scott, and thank you all for joining us today. This afternoon, we reported third quarter adjusted earnings of $ 236 million and adjusted earnings per share of $ 0.81 compared to $ 204.75 in Q3 2023. Our third quarter reported earnings of $ 4 million were impacted by the recognition of a goodwill impGairment loss related to the sale of New Mexico Gas. If I could just take a moment to provide some context on that, and I'll try and avoid getting into the technical details of how purchase price accounting works. But at a high level, the way to think about it is that when we acquired TECO, there was goodwill on the TECO balance sheet related to their original acquisition of New Mexico Gas. Our purchase price allocation on acquisition effectively carried that over to our consolidated balance sheet, and that's how you should really think about what we're revaluing today. Year-to-date adjusted earnings were $603 million, and adjusted earnings per share was $2.10 compared to $634 million and $2.33 for the same period in 2023. We saw continued growth in operating cash flow before changes in working capital in the third quarter. Excluding the impact of fuel and storm regulatory deferrals at Tampa Electric and Nova Scotia Power, the business generated operating cash flow of $1.5 billion in the first three quarters of this year. The increases to cash flow were primarily driven by new rates of Peoples Gas and the impact of customer growth at both Peoples Gas and Tampa Electric, partially offset by $20 million in transaction costs related to asset sales, higher interest costs, and lower contributions from Canadian utilities and Emera Energy. When discussing our cash flow for the past two years, we've been presenting a normalized view of cash flow, excluding fuel and storm cost deferrals at Tampa Electric and Nova Scotia Power. This is because we have confidence in the regulatory mechanisms for deferral recovery that, in essence, represent short-term timing difference between when costs were incurred and when they are recovered. Therefore, normalizing for them best reflects our underlying operations. At Tampa Electric, there are clear, well-established regulatory processes to address regulatory deferrals, and over the past 21 months, the Tampa Electric team has managed through recovering approximately $650 million in fuel and storm costs, and while 21 months is longer than a typical recovery period in Florida, we were thoughtful and deliberate about the pace of recovery to best manage the cost impacts for customers. To put this into context, we exited 2022 with $650 million of fuel and storm costs under recoveries, and now, less than two years later, all of those amounts have been collected. Scott referenced the storm costs incurred with Hurricanes Helene and Milton. Those storm costs, combined with the current expected over-recovery of fuel costs this year, mean that we are expecting to end 2024 with a total storm and fuel costs to recover of approximately half of what it would have been at the end of 2022. At Nova Scotia Power, the path forward looked differently, but ultimately led to the same outcome. By working collaboratively with both the provincial and federal government, the team at Nova Scotia Power was able to identify and implement solutions that were both in the best interest of customers and that would allow us to maintain the financial health of the utility. In doing so, the team effectively securitized over $600 million in current and future fuel balances. The strategic actions we've taken so far this year to strengthen our balance sheet, with our two asset sale announcements, our U.S. dollar hybrid issuance, and the securitizations just mentioned, we've delivered continued improvement in our credit metrics on a normalized, trailing 12-month basis since the end of 2023. And we remain solidly on track to achieve our credit metrics on a sustainable basis in 2025 and beyond. Now, turning to the quarterly results, Tampa Electric delivered strong results this quarter with growth of $16 million in earnings, or 9%, over the third quarter of last year. This was driven by continued customer growth, new base rates, lower operating costs, and lower tax expense due to higher ITCs related to solar investments. Corporate costs decreased by $21 million, or $0.07 cents, this quarter as a result of a net gain on long-term compensation expense and hedges driven by changes in our share price. This was expected and is largely a reversal from what we experienced in the first two quarters of this year. Absent the net gain on long-term compensation expense and hedges, corporate costs were higher as a result of higher interest expense and lower income tax recovery. Contributions from our gas utilities increased $11 million, or approximately 50%, for the quarter, driven by continued robust performance from Peoples Gas. The increase reflects the incredible customer growth that Peoples Gas has experienced over the last two years, which is reflected in the new base rates that went into effect in January. The weakening Canadian dollar modestly increased the earnings contribution from our U.S. operations by $4 million for the quarter. Earnings from our Canadian electric utilities were $12 million, or $0.05 cents lower quarter- over- quarter, driven by the sale of the Labrador Island Link, which reduced contributions from our Canadian equity investments by $15 million, or $0.06 cents. This was partially offset by higher contributions from Nova Scotia Power, primarily due to lower storm costs. Our higher share count decreased adjusted earnings per share by $0.05 cents in the quarter because of our DRIP and ATM activity over the past year. Contributions from Emera Energy decreased by $8 million, or $0.03 cents, for the quarter, driven by less favorable market conditions and investment tax credits recognized at Bear Swamp in 2023. Year-to-date contributions from our gas utilities increased $18 million, or $0.09 cents, driven by new base rates reflecting the robust customer growth at Peoples Gas. This was partially offset by lower contributions from New Mexico Gas, primarily due to AMA revenues recognized in 2023. The weakening Canadian dollar increased the earnings contribution from our U.S. operations by $7 million for the year. From a total impact on earnings perspective, though, this is largely offset by losses in foreign exchange hedges, which contributed to higher corporate costs. At Tampa Electric, strong performance in the second and third quarters has offset the challenges from less favorable weather and higher operating costs, increasing our year-to-date earnings by $0.02. This highlights the importance of the economic backdrop in the state, with economic and population growth driving customer growth and higher demand, which is helping offset the impact of less favorable weather compared to 2023. Year-to-date Emera Energy's results were solid but did not compare to the strength of 2023 that benefited from a much stronger natural gas market. Emera Energy is down $ 21 million, or $ 0.08. However, we continue to expect annual earnings within their guidance range of $ 15 million-$30 million. Higher share count decreased adjusted year-to-date earnings per share by $ 0.12 compared with 2023. For the year, lower contributions from Canadian utilities was primarily due to the sale of the Labrador Island Link, as I previously noted, as well as higher operating costs at Nova Scotia Power, driven by increased investments in reliability initiatives and in support of customer growth. Finally, higher interest costs contributed to the increase in corporate costs year over year, partially offset by lower OM&G due to the timing and the valuation of long-term compensation and related hedges contributed, and higher corporate income tax recoveries. And while there has been some volatility on our long-term compensation expense and related hedges, both on a quarterly basis and on a period-over-period basis, our year-to-date expenses are in line with what you should expect for nine months of the year. And with that, I'll turn the call back over to Scott. Thank you, Greg. This year, we've embarked on a strategic plan focused on strengthening our balance sheet and optimizing our portfolio. We've made great progress, with the business now better primed for growth. We're at the threshold of a transformational shift in the utility industry, making it a pivotal time to invest in our portfolio to meet the needs of our customers. With a stronger balance sheet, a disciplined capital investment plan, and a premium portfolio of assets located in high-quality jurisdictions across North America, Emera is well positioned to capitalize on this moment to deliver for our customers and, in turn, deliver growth and value for our shareholders. We look forward to meeting with our capital market community at our investor day on December 4 in Toronto. There, we will unveil our new five-year capital investment and funding plan, share the outcome of the Tampa Electric rate case, and showcase the growth opportunities we see in front of us. The event will feature not only the leaders from our operating companies but also subject matter experts from across the business who will discuss the transformation underway to build the electricity grid of the future, a transformation that will be a meaningful and durable growth driver for Emera. We expect it will be a compelling day, and we hope to see you there. And now, I'd like to open the call for questions. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press Star, followed by the number one on your touch-tone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press Star, followed by the number two. If you're using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from the line of Robert Hope from Scotiabank. Your line is now open. Good evening, everyone. I want to start off on the storm costs. So can you maybe add a little bit of color about how you're thinking about the recovery on a timely basis versus customer rates, especially given the fact that, or I guess that gas pricing is much lower here, as well as can you add a little color as well on any early discussions with the rating agencies on how they will treat the storm recoveries? So I know Archie's on the line. Archie, do you want to share a little more perspective on thinking around recovery? And then Greg can address the rating agency perspective. Sure, I can do that. Good afternoon, Rob. I think your question was, what are we looking at as far as the regulatory process? What I would say is you heard the numbers that were shared by both Greg and Scott that for us, Helene is somewhere in the neighborhood of $45 million-$55 million. We're still tabulating the cost for Milton, but we think it's $320 million-$370 million. If you put it all together, it was probably the question that's really on your mind. We think we're looking at a number that's a total number, which would include the replenishment of the storm reserves, that's probably in the $400 million-$425 million range. We have no doubt that these were prudently incurred expenses. Quite frankly, we're really proud of the speed with which the restoration was executed and done safely. As far as, I think, our plan is to file the application with the FPSC in December. The period over which we will seek to recover those costs is still sort of moving around. We don't see it being drawn out too long. We have the benefit of the $100 million or so in fuel favorability that is working in our favor, which will serve, at least in the near term, to offset these storm costs. So we're still working through the numbers. We're not prepared at this time to say exactly what the restoration recovery period will be that we request. We want to see where the numbers land. We're very mindful of trying to find that balance between timely recovery of these prudently incurred costs and about also managing the impact on customer rates. And maybe if I just add into that a little bit, Rob, before Greg speaks from sort of the rating agency part of your question, the traditional recovery period is 12 months. But as Greg mentioned, when we had extraordinary fuel costs back in 2022, we looked at a slightly longer recovery period in order to be sensitive to rate impacts for customers. And that's really the thought process that the team is going through before we formalize a filing in December. Greg? Yeah. And Rob, not surprisingly, we've had lots of conversations leading up to and subsequent to the hurricane's landing. Interestingly enough, the majority of the costs incurred actually won't actually flow out the door, meaning the money won't flow out the door until 2025, when most of the invoices will be collected and paid. So we'll have zero impact or next to zero impact on our credit metrics in 2024. And of course, with the money going out in 2025 and collections starting from customers at some point in 2025 over the periods that both Scott and Archie referred to, it again won't have any kind of meaningful impact on our 2025 credit metrics either. Appreciate that. Moving north of the border, Nova Scotia, we have a number of moving parts here with an election here in the coming weeks, as well as two fuel securitizations. How do you think about when the optimal time is to file for new rates there to improve the ROE back into the band? Hi, Rob. It's Peter. That's an active discussion now. I don't have a date for you, but obviously, we're thinking about what the optimum time it would be for our next general rate application. But I don't have a date targeted right now that I could tell you. So we're looking at it. And as soon as we do know that, we will let you know. Thank you. Your next question comes from the line of Maurice Choy from RBC Capital Markets. Your line is now open. Thanks and good evening, everyone. Maybe I'll just stick with Nova Scotia here and be a little more pointed as to what just came out from the Progressive Conservatives about potentially capping rate increases to the average of the Canadian average. Thoughts on that? Do you think that this cap is more specific to non-fuel rate increases or inclusive of fuel as well? Even big picture, does this even change how you approach your rate-based growth and earnings at NSPI? Hi, Maurice. Again, it's Peter. So I'll take that one. Obviously, we are in an election period, and I don't think it's appropriate really to discuss individual platforms. But I will say this. I think I've said several times, we have a much improved relationship with the provincial government. We work with senior officials and staff on a daily basis on many files that we have in common. Both Scott and Greg talked about the work we did on the federal loan guarantee hand in hand with the provincial government. We also know that governments are struggling with issues like affordability in a high-inflationary environment. And we understand that that would be raised during an election. And we also share the commitment to affordability for our customers. So we have that in common. Our focus is being the best utility partner that we can be and work on the issues that matter most to our customers. And they continue to tell us that's affordability and reliability. And we leave the policymaking to government. We're looking forward to, after the election, getting back to work with the government on the issues that relate to energy in Nova Scotia and also working with them to assist with policy implementation that is affordable for customers. So I guess to answer the question at the end, I don't believe it really does change our approach. I think there's a path forward here with a constructive relationship to do what we need to do to serve our customers and deliver on policy requirements from governments. This is if I could just finish off with a question on the balance sheet as well. Greg, you mentioned that you're not expecting a meaningful impact from this hurricane cost for 2025. Is that pretty much on the basis that if you recover beginning April and it's a 12-month period, you would recover nine out of the 12 months? Is that the thought process there? And could you just confirm that you're still on track to hit 11%-12% by the end of this year? Yeah. So I can confirm that, Maurice. And yeah, one of the, I can't remember what Archie or Scott alluded to, the fact that we are planning to file at the FPSC for the storm rider in December. And there's a 60-month period for them to rule on that. So. 60 days. 60 days. Sorry. Thank you. 60 days, which would potentially start collection as early as March 1st. Understood. Thank you. You're welcome. Your next question comes from the line of Ben Pham from BMO Capital Markets. Your line is now open. Hi. I wanted to go back to the storm costs and your rate case ahead in TP, and I'm wondering, do you think that there's a situation here where you can get a good outcome on TP, you can get the storm costs recovered in 12 months, and then you can balance the credit rating and balance sheet? Or do you think there's going to be a bit of push and shove in some relationships between all three dynamics? I'm not sure. It's Greg. I'm not so sure I understood the first part of the question, but nothing from what we've experienced in storm costs, the regulatory processes and mechanisms in place in Florida, or our views on what we think will be a reasonable outcome in our rate case decision. Nothing has caused us to change our confidence or our views on meeting and exceeding our threshold credit metrics in 2025. So you don't get the sense that the Florida Commission, knowing that they have this big rate case around the corner, your first-year revenues are quite high relative to the second and third, and then the storm filings ahead, that it's not tied in together? Archie, do you want to answer that? Yes. Sure. Happy to. Hi, Maurice or Ben. I would simply say that I am very confident that the rate case is assessed on its own merits and that the commissioner's judgment is not clouded by external factors like what's happening with change in the White House or what's happening with interest rates or what's happening with gas prices or what's happening with storm cost recovery, so I'm very confident that the rate case will be assessed on its own merits, and what's happening here with an unprecedented storm season in Florida in 2024 is not going to have a bearing on that outcome. Okay. That's very useful. And you had a comment around these storms reinforcing the storm hardening investments and case ahead. As you think about the industry and all the costs that have been disclosed by the utilities, does this create or incent some sort of regulatory review where you can assess storm hardening costs or look to push up higher CapEx within that bucket of the Tampa side of things? Archie? I'm happy to take that. Yeah. I'm happy to take that question as well. As we reflect on what happened, what the impact was to our customers and to our infrastructure from both Helene and Milton, both of those, Helene was a storm surge event. Milton was the biggest hurricane to hit Tampa Bay in 100 years, and as was already alluded to, a one-in-1,000-year rainfall. So a lot of inland flooding that affected our customers. But both of those hurricanes really were very modest capital. They're not capital hurricanes. They really are operating cost hurricanes as you try to put the assets back together. And for us, that tells us that our grid is a very strong grid, very well designed, and it stood up to the winds, to the rain, to the surge associated with these hurricanes. Unfortunately, it was the trees in West Central Florida that were no match for the winds of Milton. So for us, we go through a storm season like that, and then we will reflect on the programs that are embedded within the Storm Protection Plan. And I think it's fair to assume that we will be recommending some new programs or some acceleration to some existing programs to really try to improve the resiliency of the grid more quickly. We've got a grid here at Tampa Electric that is, our distribution grid is 52% underground today. And so clearly, that provides a lot of resilience against storms like Milton. We're going to have to learn to live with the beautiful tree canopy that we have in West Central Florida. And so for us, that means we're going to have to move a bit more quickly on putting some of our assets underground. So I think that what we've experienced is a testament to the value of SPP. We're going to be now reassessing whether there are new programs that we would like to recommend be considered for inclusion in SPP. And once we've done that analysis, we'll be presenting our thoughts to the commission for consideration. Okay. Thank you. That's useful. As a reminder, if you have any questions, please press Star one on your telephone keypad. Your next question comes from the line of Patrick Kenny from National Bank Financial. Your line is now open. Oh, thank you. Good evening. I'm just wondering on the back of this week's election here. And I know last time around, the 2017 corporate tax cut really caused quite a bit of noise around revenues and the impact on FFO and credit ratios. Just wondering any thoughts on how you might be able to perhaps get ahead of that and mitigate that risk this time around? Yeah. Thanks for the question, Patrick. Obviously, it's early days, and the direction that the administration takes in Washington on taxes is a little bit unknown right now. But if you take a look at face value, some of the corporate tax cuts that the newly elected president has talked about, that would be a fraction of what those tax cuts were in whatever year that was, 2017, 2018 type of frame. So it wouldn't have anywhere near the impact that we would have seen then. The other thing to note too, the reason we had a little bit of noise and had to adjust customer rates, that was because we had a clause in the settlement agreement that required us to make those adjustments for a change in tax rate. That settlement agreement and that particular clause expires at the end of this year. So we're continually monitoring it. But to the extent that it unfolded similar to what it did a few years ago, the impact would be much, much less than what we experienced. Okay. Thanks for that. And then also, I guess I know it's early days just in terms of policies and whatnot, but just wanted to confirm. And I know a lot of this is at the state level, but no change to decarbonization targets or emission intensity reduction targets over the medium to long term? Patrick, it's Scott. So no, largely because, of course, there really aren't any of those in place right now in Florida. The investments that are being made in Florida in solar and in the coal-to-gas conversion that was recently done and investments in batteries are all being done on an economic value basis for customers. They're cost-effective for customers. They're not being driven by emission target requirements or renewable energy standards or some of the things that we certainly need to comply with here in Canada. So I wouldn't really expect any impact from any of that, truthfully. And so continued execution and investment of capital on behalf of customers in Tampa, proving to be cost-effective. And part of that journey has been some element of decarbonization there, is an added benefit, but principally really is being driven by making economic decisions for the benefit of customers. Archie, anything you'd want to add to that? No, I think that you got that, Scott. That's good. Okay. No, that's great, Scott. And look forward to seeing everybody in December. Thanks. Thanks, Patrick. Your next question comes from the line of Mark Jarvi from CIBC. Your line is now open. Yeah. Good evening, everyone. Maybe just coming back to Rob's question about discussion with the credit agency. Just wondering if you guys have had a conversation since you've been able to get a rough estimate of the storm costs. You've had the federal government securitization benefit in Nova Scotia, and just wondering how the conversation between S&P and Moody's have evolved in the last couple of months. Sorry. Just the last part of that, you just broke up. Just. Yeah. Just whether or not you've had any conversation with S&P and Moody's in recent weeks or last couple of months and see how their perspective on these different events that have transpired have looked at their view on your outlook right now? Yeah. I mean, obviously, we have ongoing conversations with both S&P and Moody's and will continue to do so. I mean, all the steps that we've taken, whether it's the asset sales, the utilization of the ATM, the fuel securitization, the U.S. hybrids, all very much credit positive. I think from a storm cost perspective, as indicated earlier, it's a very manageable number. We've been in situations where it's been significantly higher in recent years. So there's been no negative overreaction to that. So I think both agencies are quite pleased with the progress. Obviously, focused now for us and obviously for them a little bit is waiting to see the outcome of the Tampa Electric rate case and ultimately continue to advance the closing of the sale of New Mexico Gas. Maybe just follow up on that, Greg. Given where you think you'll be at year-end and assuming you get a reasonable outcome on the ROE at Tampa, would you be on side with the credit metrics with S&P this year at year-end? Yes. Okay. Last question for me is just since the application has been filed in New Mexico, any initial views in terms of response from stakeholders in terms of what was put forth in the application from a net benefit perspective? And yeah, anything sort of that's come up from those discussions in the last week or so? No, I just say that the process is advancing as we would expect. And there'll be a prehearing. I've forgotten the term, Greg, but a prehearing in the next month that will start to set schedule for the process from here. But from our perspective, a robust application has been put forward and process has begun. And we continue to believe that we'll see closing in the latter half of 2025, sort of targeting that October time frame. Sounds good. Okay. Thanks, everyone. Thanks, Mark. Once again, if you have any questions, please press Star one on your telephone keypad. There are no further questions at this time. I will now turn the call back to Dave Bezanson. Please continue. Thank you all for joining us this evening and have a great long weekend. Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.