Good morning, ladies and gentlemen, and welcome to the Emera Q4 2023 earnings 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 0 for the operator. This call is being recorded on Monday, February 26, 2024. I would now like to turn the conference over to Dave Bezanson. Please go ahead, sir. Thank you, Lara, and thank you all for joining us this morning for Emera's fourth quarter 2023 conference call and live webcast. Emera's fourth quarter earnings release was distributed this morning 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 morning'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. Before we begin, I'd like to advise you that this morning'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 references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. Now I'll turn things over to Scott. Thank you, Dave, and good morning, everyone. This morning, we reported annual adjusted earnings of CAD 809 million and adjusted earnings per share of CAD 2.96. Adjusted EPS in 2023 was down approximately 2% over 2022, which was a record earnings year for Emera even when you adjust for the CAD 45 million after-tax earnings impact of a litigation settlement received in the fourth quarter of 2022. Our fourth quarter adjusted earnings were CAD 175 million, and adjusted EPS was CAD 0.63. We saw softer earnings results than we expected in the fourth quarter, largely driven by the impacts of higher interest rates and unfavorable weather in Florida. And so while our full-year results for 2023 were down year over year, we have nonetheless still delivered a 5.3% average annual increase in adjusted earnings per share over the last three years. Florida continues to drive our recent earnings growth and our expected forward growth. Tampa Electric's U.S. dollar earnings have increased an average of nearly 8% per year since 2020, and earnings at Peoples Gas have increased on average 15% year-over-year over the same period. Looking ahead, we see many reasons for optimism. We have new base rates effective January 1st at two of our utilities. We're executing well on our nearly $9 billion three-year capital plan focused on clean energy and reliability investments, and we are continuing our disciplined approach to capital allocation and cost management. Plus, we see strong customer load growth in nearly all our service territories. All of these elements together reinforce solid growth in the business and underscore our continued confidence. We continue to make progress on our capital plan, which is focused on delivering cleaner and even more reliable energy, and we're making meaningful progress on our decarbonization goals. In fact, we're pleased to note that the percentage of coal in our generation mix in 2023 was 77% lower than it was in 2005. Thanks to increased solar and natural gas generation, coal made up less than 4% of the generation last year at Tampa Electric and is down more than a third over 2022. In 2023, Nova Scotia Power's generation from coal and petroleum coke was nearly 25% less year-over-year and notably is down more than 60% since 2005. This is due in large part to the strong energy flows across the Maritime Link, which made up 13% of the supplied energy for the year and helped bring the total to over 40% renewables at Nova Scotia Power for 2023. By all measures, the Maritime Link is performing well. It delivered 1.6 million MWh of the Nova Scotia block. That is 130% of contractual requirements. Since commissioning of the Labrador Island Link in April, it has delivered more than double the energy requirement established for the Nova Scotia block. The Maritime Link also achieved availability of 99.9% for 2023. This puts the Maritime Link in the top 10% of high-voltage DC links globally in terms of availability. We're proud that it's among the best in the world and pleased that it's doing the job of delivering cleaner energy to Nova Scotians. We remain focused on improving reliability for customers right across the business. In 2023, Tampa Electric experienced its best reliability year ever, setting all-time records in four out of their five main reliability metrics. It's worth mentioning that the average duration of customer outages has decreased by 56% since 2018. Nova Scotia Power continues to be focused on a five-year plan to improve the overall system reliability experience for customers. 2023 was certainly an extremely tough weather year for Nova Scotia, but we're pleased to see that the team still managed to deliver year-over-year improvements in the metrics that measure both the frequency and duration of outages. Our utilities continued to see strong growth. Tampa Electric increased their customer base by 1.8% year over year as the local economy remains strong. The customer growth at Peoples Gas also continues to be very strong, with 4.7% growth in 2023. Nova Scotia is also growing. Nova Scotia Power's new service connection requests have increased by 28% in the past two years. Of course, safety remains our top priority, and in 2023, the team continued to do what they do best: safely delivering the energy our customers count on every day. Last year, we continued to improve upon our overall safety performance. Our lost-time injury rate improved by 24% compared to the average of the last five years, achieving the best-ever level of safety performance. While we're proud of this achievement, we remain vigilant and never lose sight of the work required each and every day to keep each other safe. This safety performance is particularly noteworthy given all the projects the team is advancing. Last year, we successfully executed on nearly $3 billion of our capital program, which is the largest annual capital program in our history. We are investing for the future with a focus on projects that support a balanced, clean energy transition. Last year, Tampa Electric added an additional 230 MW of solar generation to their system, increasing the total solar generation to 1,255 MW now in service. Together with advancements at Bayside and the Big Bend modernization, our generating fleet efficiency improved by almost 500 BTU per kilowatt-hour in 2023 compared to 2022, reducing the cost for customers. Our investments in solar alone have already saved customers more than $200 million in fuel costs. In November, Tampa Electric was advised that the Polk CCS Carbon Capture and Sequestration Project was successfully awarded a third U.S. Department of Energy award, providing 80% co-funding up to $110 million for site characterization and permitting, including installation of two new wells and full-site seismic surveying. We remain optimistic and excited about the opportunity that this project presents and will keep you informed as it advances. At Nova Scotia Power, we continue to support the government's ambitious climate goals. We recently received provincial cabinet approval to build 3 50-MW grid-scale battery projects, which will help support the province's procurement of new wind energy resources and Nova Scotia's clean energy transition. The project received a CAD 110 million grant from the federal government through NRCan's Smart Renewables and Electrification Pathways Program and a CAD 138 million low-interest financing loan from the Canada Infrastructure Bank, which will help reduce project costs and rate pressures for customers of Nova Scotia Power. We're also proudly partnered with an entity owned by Nova Scotia's 13 Mi'kmaq First Nations, which will be an equity investor in these projects. Another Nova Scotia project that supports the province's clean energy plan is the Nova Scotia–New Brunswick Reliability Tie, a 345-kV transmission line upgrade between the two provinces. This critical new infrastructure, which is expected to be in service in 2028, was developed in conjunction with Nova Scotia Power and First Nations in the region, and we recently received environmental assessment approval for the Nova Scotia Power part of the line. At Peoples Gas, the New River, Brightmark, and Alliance Renewable Natural Gas projects were completed in the fourth quarter of 2023 and are now online and functioning well. Additionally, a new renewable natural gas pipeline was approved and is now in early development stages. Not all of projects have advanced the way we expected, as last week, the New Mexico Public Regulation Commission's hearing examiner issued a recommendation against New Mexico Gas Company's application for a proposed new LNG facility. Given that the PRC requested that we look at storage options and because of the clear customer benefits that were highlighted in the application, we're surprised by the recommendation, which we're continuing to review. Whether it's investing to meet the growth in our customer base, decarbonizing our generation mix, increasing reliability, or modernizing the grid, Emera is investing to grow our business and deliver for our customers. 2023 was also a very busy year on the regulatory front. In January of this year, Nova Scotia Power filed a proposal with the UARB to support the acquisition of CAD 117 million of the FAM balance by the province of Nova Scotia to help ease the financial burden on customers and allow Nova Scotia Power timely recovery of prudently incurred fuel costs. On Friday, the Nova Scotia Clean Electricity Solutions Task Force issued its final report. The task force was formed by government in April of last year. The report included 12 recommendations to government, including the introduction of the New Energy Modernization Act that would create a new independent nonprofit system operator, an ISO, and establish a new distinct energy regulator in the province. The team at Nova Scotia Power worked closely with the task force throughout the process. [They] will be working with government on the next steps. Our goal is and will continue to be to ensure that affordability and reliability for customers remains the focus throughout the energy transition in the province. While the team continues to assess the recommendations, let me say that we believe the creation of a new dedicated energy regulator and the development of an independent system operator in Nova Scotia is a positive step in the path to 2030. Nova Scotia's coal-fired plants will be phased out by 2020-2030 and the energy replaced in large part by wind. The wind projects are already being procured by the province and will be executed with the independent power producers, or IPPs, in the province. Since the procurement of new energy resources already resides with the government today, it makes sense that they would assume overall responsibility for generation planning and dispatch, including execution of those wind projects and managing system capacity requirements and renewable energy standards targets. Government have confirmed that the new independent system operator will oversee open competition for new generation and storage infrastructure, but not for transmission and distribution, which remains under the service obligations of Nova Scotia Power. This would allow Nova Scotia Power to continue to focus on providing reliable service to customers through the clean energy transition and to focus increasingly upon the important role the utility plays on transmission and distribution in the province. At Peoples Gas, we completed the fully litigated rate case in early November, and rates came into effect on January 1st of this year. In September, New Mexico Gas filed for new rates to take effect on October 1st of this year. That rate case is progressing well, with a hearing expected in April. Finally, Tampa Electric has started the regulatory process to seek new rates by filing its test year letter earlier this month. The test year letter indicates they anticipate seeking incremental base rate revenues of $290 million-$230 million in 2025, with $170 million increases related to specific investments in each of 2026 and 2027, respectively. We plan to file a request for new rates in early April, with the expectation that any new rates would be effective on January 1st next year. Overall, we continue to safely advance a balanced energy transition while improving system reliability, supporting strong customer growth, and steadily improving our safety performance. While 2023 didn't deliver the earnings results we hoped for, we remain confident in our path ahead, with the steps we're taking to continue to strengthen our business and with our 8%-9% rate-based growth profile driving continued earnings and cash flow growth over time. And with that, I'll turn it over to Greg to take you through our financial results. Thank you, Scott, and thank you all for joining us. This morning, we reported fourth quarter adjusted earnings of CAD 175 million and adjusted earnings per share of CAD 0.63. This compares to CAD 249 million and adjusted earnings per share of CAD 0.93 in the fourth quarter of 2022. As a reminder, our 2022 fourth quarter results included the recognition of a CAD 45 million Canadian after-tax settlement related to a litigation award, which represents CAD 0.17 of adjusted earnings per share. Excluding the impact of the settlement, adjusted earnings were CAD 204 million for the fourth quarter of last year, and adjusted earnings per share was CAD 0.76. For the year, adjusted earnings were CAD 809 million, and adjusted earnings per share was CAD 2.96 as compared to CAD 805 million and CAD 3.03 per share for 2022 when adjusted for the settlement I just mentioned. Our fourth quarter results were not what we had planned, due in large part to increased financing costs across the business and unfavorable weather in Florida. The impact of weather reduced Tampa Electric's contribution to EPS by $0.02-$0.03 compared to the fourth quarter of last year. However, we remain confident in the health and stability of our business and our ability to deliver earnings per share growth in 2024 and beyond, supported by our strong rate-based growth. With the constructive Peoples Gas rate case result now behind us and both Tampa Electric and New Mexico Gas rate cases occurring in 2024, I expect the business will continue to strengthen over the next couple of years. Now, turning to the details of the quarter. When you adjust for the impact of the legal settlement mentioned earlier, adjusted earnings per share decreased $0.13, or 17%, over Q4 2022. Canadian Utilities' earnings were higher, driven by new base rates and growth in the business. Emera Energy's earnings decreased $16 million quarter-over-quarter. Emera Energy's trading business had a strong quarter but lower than the fourth quarter of 2022, which was their strongest on record. Our gas utilities were down for the quarter, largely driven by lower earnings in New Mexico Gas due to lower asset optimization revenues. Tampa Electric's earnings were down due to increased interest expense, depreciation, taxes, and unfavorable weather, partially offset by new base rates and customer growth of approximately 1.8%. Excluding the litigation settlement, corporate costs increased CAD 9 million this quarter, largely driven by higher financing costs offset by the timing impacts of share-based compensation expense and related hedges. And finally, higher share count decreased quarterly adjusted EPS by 2 cents in the quarter. Excluding the impact of the legal settlement, annual adjusted earnings per share decreased by 7 cents, or 2%, driven by higher interest expense across the business offset by increased base rates at Tampa Electric and Nova Scotia Power and the impact of a weaker Canadian dollar. Foreign exchange worked in our favor this year, adding 11 cents to EPS. The weighted average exchange rate on adjusted earnings was $1.31 in 2022 compared to $1.35 in 2023. Our Canadian utilities contributed $0.09 in EPS growth, benefiting from both increased rates and increased sales volumes in Nova Scotia Power, as well as higher earnings from our Maritime Link and Labrador Island Link investments. Tampa Electric's U.S. dollar earnings contributed $0.03 in EPS growth due to higher base rates and load growth, partially offset by higher costs. Corporate reduced EPS by $0.15, largely driven by higher interest expense, which was partially offset by the timing impacts of share-based compensation expense and related hedges. Lower earnings from our gas utilities and infrastructure segment were driven in large part by higher interest expense across the segment, offset by the strong asset management agreement results recorded in New Mexico Gas in the first quarter of this year. Emera Energy had a solid year but lower than the exceptionally strong 2022. Earnings for the Emera Energy marketing business were above our guidance range, but $22 million lower than 2022, which was the business's second best on record. Finally, the higher share count decreased adjusted EPS by $0.09 for the year as we continued to issue equity through both our ATM and dividend reinvestment programs. As expected, operating cash flow before working capital rebounded this year, increasing 104% over 2022, making it the company's highest ever. Cash flow growth was supported by the recovery of the 2022 fuel and storm costs at Tampa Electric and increased cash flow contributions from our regulated utilities. This growth was partially offset by the undercollection of fuel and storm costs at Nova Scotia Power and higher financing costs. At Tampa Electric, we have reduced our total underrecovered fuel and storm costs by nearly 90%, collecting almost $700 million this year. The remaining 2022 deferral balances will be collected by the end of this year. In Nova Scotia, fuel and storm-related undercollections increased our deferral balances. However, incremental fuel revenues of approximately $115 million and the $117 million of fuel cost relief from the province of Nova Scotia are expected to stabilize deferrals for 2024. And as we've done in the past, we will continue to work with stakeholders to further manage the impact of collections on customer rates. Lastly, in 2023, we collected the final outstanding fuel balances in New Mexico related to 2021's winter storm, Uri. Recovering deferral balances was a major focus of management this year. Even in the extreme circumstances of 2022, the effective regulated fuel and storm cost recovery mechanisms in Florida and Nova Scotia are working and give us confidence that we will fully recover any remaining balances and future prudently incurred costs in a timely manner. We also remain focused on reducing our exposure to variable rate debt. Over the last few months, we have reduced our exposure to variable rate debt by approximately $2.3 billion and will continue to work to further mitigate our interest rate exposure. In addition to the ATM issuances in the quarter, we issued $925 million of long-term debt at Peoples Gas and, in early January, $500 million at Tampa Electric. These higher interest costs have been or will be fully reflected in customer rates by January 1st of 2025. While interest rates remain persistently high, our actions to date have reduced our exposure to this macro headwind. Looking forward to 2024, operating cash flow as in changes in fuel and storm cost deferrals will grow, supported by new rates at Peoples Gas that include the recovery of the higher interest costs, increased dividends from the Labrador Island Link, incremental base rates at Tampa Electric, and ongoing growth in the business. These known drivers support the positive trajectory of our cash flow. Beyond 2024, new rates at Tampa Electric and New Mexico Gas and continued growth in the business will contribute positively to predictable cash flow and earnings growth. In 2022, fuel and storm cost deferrals significantly impacted our credit metrics. Over the past year, we have been focused on three key areas with the objective of returning to stable and predictable credit metrics. The first of these I discussed a moment ago. We were focused on the collection of 2022 deferrals. The other two areas of focus are prudent investment in our regulated utilities and management actions to reduce the holding company debt. As always, we are committed to making prudent rate-based investments to support growth and provide our customers with reliable energy. In our sector, there is a leading leg to the recovery of these investments as capital is deployed and recovered from customers in future rate cases. Between rate cases, we manage our capital program to ensure we continue to meet our customer needs while minimizing this lag. In 2023, debt increased at several of our utilities in support of capital investment for the benefit of customers. However, the implementation of new rates at Peoples Gas and New Mexico Gas in 2024 and Tampa Electric in 2025 will allow us to recover on our capital investments, reducing this regulatory lag. In addition, as Scott mentioned, we have taken advantage of various incentives in both Canada and the United States to further manage capital investment and lower costs to customers. We have been granted $88 million of federal government support for our Polk CCS project, and here in Canada, CAD 111 million in federal government support for our battery investments in Nova Scotia. Our capital program relies on reinvested cash flow, operating company debt, and equity. As we got in on our last call, we caught up on our ATM issuances in the fourth quarter and raised approximately CAD 670 million of equity in total last year through both our ATM and DRIP programs. On the management action front, we have reduced our ratio of holding company debt to total debt to 37% at the end of 2023 from about 40% last year. This represents a reduction in holding company debt of approximately $350 million. Using the anticipated proceeds from targeted asset sales to reduce corporate debt will allow us to further improve our ratio of holding company debt to total debt and strengthen our overall credit standing. Depending on the adjustments made to normalize for deferrals, we estimate that our ratio of cash flow to debt was relatively flat to 2022. As a result of higher interest expense and less favorable weather in Q4, the improvements we expected did not materialize. However, we believe we have provided the market with far more confidence in the recovery of these deferrals and exhibited through our commitment to investment-grade ratings and our previously communicated targeted asset sales and reduction in holding company debt. These activities are further supported by our ongoing rate-based investment and regulatory filings that will drive predictable cash flow growth over time. Executing in these areas will allow us to get to stable investment-grade metrics in the near future. And with that, I'll turn the call back over to Dave. Thank you, Greg. This concludes the presentation. We would now like to open the call for questions from analysts. Thank you, sir. 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 three-tone prompt acknowledging your request. 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 your handset before pressing any keys. One moment, please, for your first question. Our first question comes from the line of David Quezada from Raymond James. Please go ahead. Thanks. Morning, everyone. Maybe just starting with the Clean Energy Solutions Task Force at Nova Scotia Power, I'm just wondering if there's any additional color you could provide on just how you see clean energy opportunities shaping up in the province with the establishment of an ISO. Do you think it changes the magnitude of the opportunity you see there at all? It's a good question, David. And it's Peter Gregg, by the way, from Nova Scotia Power. So obviously, early days, the report was just made public on Friday. As Scott indicated in his comments, we are supportive of the two broad recommendations. That's the standalone energy regulator in Nova Scotia. We think that's a positive development and supportive also of a standup of an ISO here in Nova Scotia. You'll know that the transition to 2030, the broad decarbonization agenda the province has, is ambitious and will require a lot of focus. The province also established this past year the Clean Power Plan, which is all of the projects that will get the province to 80% renewable and off coal by 2030. We're very supportive of that plan. And I think having an independent system operator to do the long-range planning and oversee that transition is a natural next step in that transition to 2030. Okay. Excellent. Thank you. Appreciate that color. And then maybe just one more for me, just generally on the topic of asset sales. I'm curious if there's any color just on what you're seeing in the market for or whatever proceedings you have going on with respect to that and any kind of relevant activity or comments on what you're seeing from valuation perspective today. Yeah, David, it's Scott. I'd just say that we mentioned in our Q3 call last year that asset sales are part of our financing program for our capital investment plans. We're well advanced in exploring options. We're encouraged. We don't see any sort of market dynamic that would discourage us from the path that we're on. But we're still in a place where no decisions have been made. And of course, when they have, we'll provide a further update. But in the meantime, we're encouraged with our progress so far. Excellent. Thanks for that, Scott. I'll turn it over. Our next question comes from the line of Robert Hope from Scotiabank. Please go ahead. Good morning, everyone. First question is on credit metrics. Previously, you've talked about getting to 12% FFO to debt in 2024. When you take a look at the headwinds and tailwinds in front of you right now, what needs to happen to get to 12% in 2024? And would that include kind of a full slug of ATM or potential asset sales? Yeah. Good morning, Robert. It's Gregg. What we really experience, I think, in 2023 doesn't really have much of a reflection on our confidence in where we're going in 2024. Certainly, mitigating the exposure to interest rates is helpful. The execution of our regulatory filings, whether it was Peoples Gas last year, resolution on some of the outstanding fuel in Nova Scotia, and the filing at Tampa Electric, I think, gives us some confidence. We said all along that the execution of asset sales would de-risk our path to 12%. And we still feel confident in both the organic path as well as de-risking it through the execution of asset sales. So still very confident in the targets that we set for ourselves for this year. Good to hear. And then moving back over to the Clean Energy Task Force, I realize that the government only adopted the first recommendation. But if we go through the full list, recommendation five includes some commentary on open competition for additional upgrades to the transmission grid. Can you maybe speak to what the communication has been with the government or other stakeholders for potentially opening up the other investments to competition, not just power? Sure, Rob. It's Peter again. I'd point you to the Minister of Natural Resources and Renewables issued a statement on Friday, and he did a number of interviews following that too, and made it clear that while recommendation five does talk about transmission resources being competitively procured under the new ISO, that he will not accept that recommendation. So our understanding is that the role of the new ISO will be to competitively procure generation and storage, not transmission. Appreciate the clarity. Thank you. Thank you. Our next question comes from the line of Maurice Choy from RBC. Please go ahead. Thanks, and good morning, everyone. Maybe just follow up on the cash flow debt metrics here for a moment. What was the cash flow to debt metric as of the end of 2023, recognizing that the goal was to reach 11.5%? Yeah. As I indicated, Maurice, we would expect it to be relatively flat at around 11% compared to what we were last year. Got it. So I guess within this year, you're anticipating that 11% to jump to 12%. If you can confirm that. But a quick follow-up to that. When I think about your asset sales, the size of it, which is 15% of your CapEx plan, are you willing to sell more than that in order to achieve not just a 12%, but also a certain cushion above the 12%? Yeah, Maurice. As part of this, we've identified a couple of assets that we think might make sense from a capital recycling perspective. To the extent that we see favorable market conditions on more than one asset, that wouldn't preclude us from moving ahead with that, even if it was more than we may have initially set as a target. I guess when you highlight interest and marrying this with Scott's earlier comments about the interest level, is it fair to say that the interest level that you've seen so far would somewhat justify the potential of selling these couple of assets? I'd say the interest level we've seen so far is expected. Got it. If I could just shift over to the dividends for a moment. I think you've disclosed in your MD&A that the dividend payout ratio is at 94% for 2023. There is obviously potential that asset sales might bring this number higher if there's any EPS dilution. We've seen quite a number of dividend actions of late in Canada and globally in infrastructure land. I wonder if you could refresh us as to how you approach your policy on dividends, including the potential for changes in the growth rate, how is that sized, and even potential for any dividend cuts. Thanks. Yeah, Maurice, it's Scott. I would not want anybody to think that there is any suggestion or inclination of a dividend cut. Since you used those words, that is not something that we would consider nor need to consider. To your broader question, our dividend policy is obviously something that is a board-determined matter and something that we engage with and discuss with the board on a regular basis. Typically, as you know, we would announce our annual dividend approach coming out of a meeting that we hold every year in September. Typically then for the dividend application to the dividend in the November dividend cycle. So ultimately, as I say, that's something that we generally look to and provide market guidance to in the fall. The dividend growth rate itself, is that usually sized or is that a minimum number that you try to achieve? Or Or inflation, how should we think about that rate? Well, as you know, when we reduced the dividend growth guidance that we had prior to 2018, we worked to set our dividend growth guidance at a level that we believe over the long term, our earnings per share growth would outpace our dividend growth. And that continues to be true today. That continues to be true. And that's the primary measure that we look at is ensuring that our dividend growth rate is at a level that makes sense relative to our earnings per share growth rate. And we continue to have confidence that that dividend payout ratio will reduce over time as our earnings growth continues to outpace our dividend growth. Of course, we continue to look at that. Our payout ratio obviously negatively impacted this year by the unexpected fourth-quarter results. But overall, we've been continuing to track a reduction and continue to target a reduction in our dividend payout ratio over time. And that's something that Gregg and I and the board are all very engaged in and ensuring, and that won't change. Thanks, our color. Our next question comes from the line of Linda Ezergailis from TD Cowen. Please go ahead. Thank you. I'm just wondering, in addition to reassessing maybe the merits of upsizing your asset sale program and relative contribution to your funding plan, is there any ability maybe to reassess or have you put thought to the relative attractiveness of your capacity for hybrid instruments, whether a discrete common equity offering might be an option this year? And also, what ability might you have, if any, to consider deferring any sort of discretionary capital at this point? Yeah. Good morning, Linda. It's Gregg. As you can imagine, we look at all options available to us from a funding perspective. We do have, as you noted, some capacity on our balance sheet to do something either with a Canadian preferred share offering or maybe a hybrid offering, albeit from a cost of capital perspective, that's not overly attractive in this market. We are not contemplating a discrete equity offering, nor do we believe we need one at this point in time. We're happy with the path we're on, which is continually to utilize our at-the-market equity program as well as our DRIP and to complement that financing plan with asset sales. So that is, in fact, the path that we're on. Okay. Thank you. And just as a follow-up, in your discussions with the debt rating agencies, you mentioned—are there any kind of changes in tone or what sort of forbearance do you expect in terms of the timeline to achieving your credit metrics? And maybe as part of that, was there any discussion about the dividend and maybe pausing growth, if not cutting it? Yeah. I think that, as they always have been, I think the conversations with the credit rating agencies have been constructive. I think they're supportive of the path we're on. But I want to be clear, the delivering of that plan is on us. I'm confident that as we execute our plan over the course of 2024, whether that be asset sales, continually utilize the at-the-market equity program, focus on recovering fuel and storm cost deferrals, as well as executing a regulatory strategy, I think we are all confident both internally, and I think the rating agencies have some degree of confidence in that as well. I would suggest if you look at the S&P report that came out on Friday, and if you look at the Moody's report that came out late December, it kind of, I think, reinforces that, that I think the time for us to execute is there. Once we do that, I think we'll be where we need to be. In terms of any discussions around dividend growth, there have been none. Although maybe from a credit perspective, there might be some positive optics related to that, the reality is it has no meaningful impact on credit metrics at all. And given that that's the focus with the rating agencies, that would not at all be not surprisingly, that's not a discussion item with them. Thank you. You're welcome. Ladies and gentlemen, just a reminder, should you have a question, please press star followed by the number one on your touch-tone phone. Our next question comes from the line of Mark Jarvi from CIBC Capital Markets. Go ahead, please. Thanks. A couple of questions around Nova Scotia. One is maybe on the province picking up the tab on some of the fuel costs. Can you elaborate how that came to be and whether or not that signaled something around the evolving relationship with the provincial government? Yeah. Thanks, Mark. It's Peter again. Around evolving of that, really, it's as simple as, I think, a constructive working relationship we have with the provincial government. So discussions happened over the latter half of last year around the outstanding fuel amount and the impact on rates. And so we had discussions on a range of potential alternatives for managing that amount and ended up with what I think is a very constructive approach that allows for the recovery of that fuel amount but does so in a more affordable manner for customers. So back to your point, I think there is a constructive working relationship, and that is some evidence of it, some other evidence. Scott spoke to our grid-scale battery projects. For us to advance on those, that required a cabinet approval here in Nova Scotia. Again, I think just lines up nicely with our support of the province's Clean Power Plan and their objectives to achieving the 2030 goals. To briefly take those comments, Peter, and maybe bring Gregg in the conversation, just S&P, one of their big issues was regulatory risk, business risk. How would you say the relationship with the government's evolved? How is that communication with S&P going to cost to them in terms of their perception of it? And I guess just maybe the task force, does that change any of the math or any of the questions that S&P might have around Nova Scotia Power? Yeah. I'd say S&P in particular, their response, I would say, or perspective on it, Mark, has been balanced. I think they clearly see it as a positive, as, from a pure financial perspective, the funding of some of the fuel providing some kind of prospective relief for customers as constructive. Obviously, part of that was done through a recognition of challenges with credit metrics. So I think that has been perceived as slightly positive. But at the same token, I think S&P, and this is something that we've seen in other jurisdictions as well, will be keeping an eye on the next-generation rate application as well and whether or not that can go from start to finish without any kind of intervention from the government. But all to say is I'd say it was a balanced reaction, probably slightly positive. Okay. And then just on the conversation with rating agencies, maybe comment a couple of things. One would be, based on where you're heading with holdco debt and variable rate debt, will you be there by mid-year to appease rating agencies on those metrics? And second, just maybe comment on the magnitude of the ATM usage in Q4. What forced you to be a bit more aggressive with it? Was there anything in terms of a firm deadline or commitment that you needed to make there? Yeah. I think the path we're on, look, there's never a specific date where the rating agencies say you have to be at a particular place. But I think all the activity that we've got underway, the steps that we've taken, we're confident the negative outlooks are going to get resolved in 2024. I wish I had a perfect clarity as to the exact month that those would happen, but we have a high degree of confidence in that, Mark. In terms of the ATM issuances, it was not in response to any kind of direction mandate from the rating agencies. You'll recall we hadn't done anything in the fourth quarter of 2022 or the first three quarters of 2023. Of course, as you can imagine, it's been in a blackout since the beginning of the year because of the timing of our release of our financial results. So really, what we issued in the fourth quarter was covering six quarters, if you will. And so I would say largely in line with what we would have expected. There was just a clear path in the market for us to get done a reasonable amount of ATM and catch up to what we hadn't done over the previous four quarters. And so we took advantage of that opportunity. Okay. Last just one quickly for me. Obviously, you have a lot of keen interest on the asset sale progress. At what point would you be in a position, you think, to provide an update to the market with more sort of either direction on the magnitude or timing? Is it something you could provide clarity by the Q1 results in May? I'd say certainly before the end of the second quarter, Mark would have some confidence that we should be in a position to provide some clarity by then. Sounds good. Thanks, everyone. Thanks, Mark. Our next question comes from the line of Ben Pham from BMO. Please go ahead. Hi. Thanks. Good morning. A couple of questions on asset sales, and just on that last question as well from Mark. You mentioned earlier around your expectations on asset sales and incoming, it's been in line with your expectations. Can you add a bit more color to that? Because when you announced the asset sale program, yields were much higher than where they were today. And most of the infrastructure companies that we've been following have suggested that it's night and day with respect to their conversations on asset sales. Yeah, Ben, I guess I'd just lean in again with the comment that we are encouraged with where we sit in terms of our progress and sort of market conditions and working, as I said to Mark, to be in a position to provide more clarity by the middle of the year. Okay. And would you say then, I mean, when you put together your asset sales and your expectations and where yields were at that time called high threes, that you were anticipating that yields would decline and that led to really an expectation that you'd get maybe better valuations in 2024 versus 2023? Is all baked into your plan already? I'd say we have reasonable valuation expectations would be the way that I'd say it. And if we're in a place where yield movements work in our favor and create a better valuation level, then that's great. But I'd say we have reasonable valuation expectations. Okay. Got it. And maybe just continuing on that, and I'm not sure you answered this question early on, the EPS impact of asset sales and the FFO differences. And I guess it depends on what assets you sell. Some might be accretive to FFO, maybe dilutive to EPS. I think you mentioned last call you would not sell an asset unless it's at least neutral to EPS. Is that still the case today, just getting away from FFO to debt? Is it trending for you? Yeah, Ben. I mean, look, every asset would have different dynamics depending on proceeds, use of proceeds. I mean, first and foremost, the execution of this program is to fundamentally accelerate our deleveraging and improve our credit metrics. So the use of proceeds will be primarily targeted at the reduction of holding company debt. Obviously, in a perfect world, you'd have no impact on EPS. And as short-term interest rates remain high, there's an opportunity to mitigate any kind of impact. But if we find ourselves in a situation where it might have a very modest impact on EPS but a material impact on credit metrics, that's certainly something that we wouldn't discard in the moment. But I'd say it's too early to tell on all those things. It's not just EPS today. It's what do we think the growth rate of those assets are and what are their contribution to EPS over the next couple of years as well. So a lot of factors come into play. Okay. That's understood. And maybe just lastly, you've got your CapEx program, CAD 8.9 billion, and you've noticed some other items on slide 5, Atlantic Loop. You've talked about the storage maybe not happening. Can you talk about how some of those projects flex the CapEx? Is it all in there, or is it leads to some upside later on? Yes. That's one of the reasons when we rolled out in November, our roll forward at CapEx, Ben, is we had a number of projects in our opportunities under development. And you would have recalled, I hope, that we characterize them as one of the things we needed to have is regulatory certainty, support, and a clear path for cost recovery on some of those projects. The storage facility in New Mexico would be an example of that. We had it under our opportunities under development because there was some uncertainty of whether or not there was a path forward that, of course, has played out kind of in real time related to that. So to the extent there's other projects like batteries now, we have moved those up into our core projects. So you'll see a little bit of shifting as we go through time, as we get certainty around some of these projects. And certainty meaning not just the ability to invest and the desire to invest, but also a clear path to earn a return on enough capital. But I'd say in total, there hasn't been anything meaningful on a consolidated basis that would cause the numbers or our view of the ability to invest that capital to change materially. Okay. Got it. Thank you. Thanks, Ben. Thank you. We have our next question coming from the line of Patrick Kenny from National Bank Financial. Go ahead, please. Thank you. Good morning. Just maybe on your gas utilities here, just in the context of the depressed state of natural gas prices, I guess implying a bit of a tailwind for customer and demand and just overall affordability. Just wondering if you're experiencing any sort of outperformance either at Peoples Gas or New Mexico in light of the low natural gas price environment. Yeah, Patrick, it's Greg. It's a good question. I mean, obviously, what we've seen in natural gas prices has been relatively recent. And if you think of certainly the impacts that that would have on our system, whether at Peoples Gas or New Mexico Gas, we don't see a lot of change in volume in the near term because of significant movements in gas prices. People still need gas in New Mexico to heat their homes and in Florida for more of the amenities. So we don't find it as sensitive in the near term. Obviously, if gas prices remain at these levels, we would expect that to probably provide some underpinning for some additional commercial and industrial growth. But I think it's still a little bit early to tell. I'd also add, in the meantime, it's also helpful on the electric side just in helping to keep the cost of energy, sort of the gas generation cost of energy lower. So it's certainly helpful across both our gas and electric utilities. And then I guess from an affordability perspective as well, looking out more over the medium term, would it help to bring any of the additional potential investments that you've highlighted here over the next three years bring those projects forward a little bit? Yeah. And again, well, it depends, Patrick. And it certainly is different by jurisdiction and the nature of capital investments. Certainly, lower gas prices helps from an affordability perspective, whether it's on our gas LDCs or, as Scott mentioned, from a fuel cost perspective, at Tampa Electric. Does that give you some headroom? We don't really think of our capital program necessarily through the lens of headroom. We're investing capital to support our customers. And it's capital that is ultimately required. The timing of that may change. But also, low gas prices, if they're here to stay, and I think we all know that they will be volatile over time, does mean that when you look at the economics in some jurisdictions of renewable energy, those economics change as well as gas becomes more favorable from a price perspective. So there's a lot of different dynamics. But all to say is the current pricing environment is certainly helpful for customers overall on both the gas and electric side. Makes sense. That's great. Thanks, guys. Thanks, Patrick. Thank you. There are no further questions at this time. I'd now like to turn the call back over to Mr. Bezanson for final closing comments. Thank you. Thank you all for joining us this morning. Thanks for your interest in Emera. Have a good day. Thank you, sir. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a lovely day.