Good morning, ladies and gentlemen, and welcome to the Emera Inc. Q1 2023 analyst conference call. At this time, all lines are in listen-only mode. Following the presentation, we'll 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 Friday, May 12th, 2023. I would now like to turn the conference over to Dave Bezanson, VP of Investor Relations. Please go ahead. Thank you, Colin, and thank you all for joining us this morning for Emera's first quarter 2023 conference call and live webcast. Emera's first quarter earnings release was distributed this morning via 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 would like to take a moment 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 will turn things over to Scott. Thank you, Dave. Good morning, everyone. Emera reported strong first quarter results this morning with $0.99 of adjusted earnings per share and a 36% increase in operating cash flow before working capital compared to the first quarter of 2022. The 8% increase in adjusted earnings per share year-over-year was primarily driven by higher earnings from our marketing and trading business and the impact of new rates and an asset management agreement at New Mexico Gas. The benefit of new rates at Tampa Electric and Nova Scotia Power were offset by the impact of higher interest rates as well as milder weather in both Florida and Nova Scotia. Results at Nova Scotia Power were negatively impacted by the requirement to recognize the full provision for the $10 million penalty related to the province's renewable energy standards. As a result of the delays in the commissioning of the Labrador Island Link and the ongoing testing in 2022, we received less renewable energy from Newfoundland and Labrador, which put Nova Scotia Power modestly below the 40% renewable energy requirement. I'm pleased to say that with flows of energy from the block this year continuing to stabilize and increase, Nova Scotia Power's energy supply year to date has exceeded the 40% renewable requirement. While accounting rules required us to recognize the penalty in the quarter, we respectfully disagree with the penalty and intend to appeal it to the regulator, and we would anticipate a decision on that before the end of the year. Last month, Newfoundland and Labrador Hydro successfully completed high-power testing on the Labrador Island Link and as such, received the confirmation of commissioning from the independent engineer. Nova Scotia Power customers have already received more than 1 million megawatt hours of clean hydro energy over the Maritime Link, which has meaningfully reduced carbon emissions in the province. This investment also saved customers in Nova Scotia almost $100 million in 2022 by reducing the need to purchase high carbon fuel at elevated prices. With commissioning complete, we've now begun recognizing cash earnings on our LIL investment, an important step forward towards our cash flow and credit metric targets. We deployed over $600 million in capital in the first quarter of 2023, we're on track to deliver our capital plan of almost $3 billion this year. Over 75% of our three-year capital program will be invested in our Florida operations, driven largely by the significant economic growth in the state. Florida was the fastest-growing state in the U.S. last year and is also one of the 20th largest economies in the world. With significant customer growth in excess of 2% at Tampa Electric in 2022 and approximately 5% at Peoples Gas, our capital deployment reflects the capital investment necessary to service that growth and deliver reliable energy for our customers. At Tampa Electric, we continue to invest in solar with another 239 megawatts to be installed by the end of the year, which will bring Tampa Electric's total solar generation capacity to over 1,200 megawatts, representing approximately 22% of Tampa Electric's generation capacity and 14% of expected actual energy production. We're also making significant investments in grid hardening and reliability through Tampa Electric's Storm Protection Plan. These projects are transforming the grid in Tampa for benefit of our customers. We're also highly focused on investments in system reliability in Nova Scotia and at our gas utilities, as well as to support customer growth and in continuing to strengthen these systems from the impacts of severe weather events. We continue to manage our capital plans to ensure we are meeting legislative requirements as well as customer and regulator expectations, while at the same time managing the pace of investments in the energy transition in order to minimize cost impacts for our customers. Our investments in cleaner and more reliable energy across the business are enabling significant progress towards the first milestone in our climate commitment, a 55% reduction in CO₂ emissions by 2025. Last year, we achieved a 41% reduction in carbon emissions compared to 2005, thanks in large part to our investments in solar and clean hydro energy being delivered over the Maritime Link. With over 60% of our capital plan focused on investments in cleaner and more reliable energy, we remain on track to achieve our first climate goal in less than two years. As we continue to work towards meeting the federal and provincial government's ambitious climate goals for Nova Scotia, we continue to believe that the Atlantic Loop is the most cost-effective solution for our customers without putting system reliability at risk. The federal government reinforced its support for the project in its March budget, and I'm pleased to say we're supporting active negotiations in an effort to make this transformative project a reality. Given the scale of this capital project, and with 2030 quickly approaching, it's critical that we get started as soon as possible with clarity needed on the path forward this summer. With the recent successful conclusion of several major regulatory proceedings, it's a little quieter on the regulatory front this year. During the quarter, the Florida Public Service Commission approved Tampa Electric's fuel and storm cost recovery request as filed. The timely recovery of these previously incurred costs will allow us to make important progress on key credit metrics this year as we pay down the related short-term debt. The team at Peoples Gas also filed their petition for a future rate increase with the regulator for a requested $138 million in new rates effective January 1st of 2024. Since their last rate increase in 2021, Peoples Gas has deployed more than $1 billion of rate-based investment to serve the growing population of Florida and to ensure their system continues to operate safely and reliably. We expect hearings for the rate case to take place in late summer with a decision in the fourth quarter. Overall, our businesses are performing well. Weather, of course, will always be a variable in our industry, but the underlying growth in our core utilities is strong. We remain intensely focused on strengthening our balance sheet and looking forward to the rest of the year. With new base rates at 3 of our 4 core utilities, we expect to continue to deliver solid earnings growth and cash flow performance. With that, I'll turn it over to Greg to take you through our financial results. Greg? Thank you, Scott, and thank you all for joining us. This morning, we reported first quarter adjusted earnings of CAD 268 million and adjusted earnings per share of CAD 0.99 compared to CAD 242 million and CAD 0.92 in 2022, representing an 8% increase in adjusted earnings per share year-over-year. This quarter's results continue to demonstrate the value of our diverse portfolio. We saw stronger contributions from Emera Energy and New Mexico Gas, which was able to more than offset the lower contributions from Tampa Electric and Nova Scotia Power, whose results were somewhat weaker due to higher interest rates and milder weather conditions. Of course, Nova Scotia Power booked the CAD 10 million penalty that Scott referenced a few moments ago. Operating cash flow before changes in working capital increased by 36% year-over-year, despite the unfavorable weather in the quarter. Excluding the impact of fuel deferrals, operating cash flow increased by $56 million or 10% over Q1 2022, in line with our expectations. At our Investor Day in March, we outlined the step changes in cash flow and debt reduction we expect to achieve in 2023 that will result in meaningful improvement in our key credit metrics. This includes new rate agreements at Tampa Electric, Nova Scotia Power, and New Mexico Gas, all of which went into effect in Q1. It also included cash contributions from the Labrador Island Link, whose AFUDC earnings converted to cash earnings in April with the commissioning of the LIL. Finally, it included the recovery of storm and fuel costs at Tampa Electric. The recovery of which was approved as filed by the Florida Public Service Commission during the quarter. The recovery began on April first. Perhaps more importantly, fuel costs have stabilized. Where last year we were under-recovering on fuel, so far in 2023, we are seeing an over-recovery that is helping to further pay down the unrecovered balance faster than we otherwise would have expected. While we're adjusting for the effect of the collection of fuel costs on our cash flow, this will reduce the outstanding debt balances associated with financing these under-recoveries and therefore will improve our credit metrics. As we execute on the strategy that we laid out for you at Investor Day, we are already beginning to see measurable progress. While cash flows this year from LIL will be modestly lower than anticipated due to the delay in commissioning and an expectation that the incremental LIL investment will be deferred, this is more than offset by the stronger than expected performance at Emera Energy and New Mexico Gas in the first quarter. Compared to Q1 2022, operating cash flow before changes in working capital, excluding the impact of fuel deferrals, increased 10%. We remain on track to achieve the $2.1 billion CAD in operating cash flow and 11.5% cash to debt metrics that we outlined in March. Now I'd like to turn our attention to the details of our quarterly results. Emera Energy's marketing and trading business delivered a very strong quarter with $53 million USD in adjusted earnings, more than double their $25 million USD contribution in 2022. The weather was generally mild, Emera Energy realized unfavorable hedges that were entered into during 2022's elevated market. In addition, the mild winter meant more gas transportation capacity was available, which the business was able to capitalize on. Finally, there was a brief cold spell in early February that brought price and volatility spikes and thus trading opportunities. Despite the strong start, Emera Energy is not adjusting its annual earnings guidance, which stands at $15 million-$30 million. While Q1 had the benefit of the hedges I just mentioned, similar to what we saw in 2019, we expect some of those impacts to reverse in Q2 and Q3. Q2 and Q3 are always challenged for profitability because the cost of the transport and storage are amortized equally over time, despite the fact that related revenues are mostly earned in the winter months. The 2023 contracts were bid into 2022's market, costs are somewhat elevated compared to the last couple of years. Moving to our gas utilities, New Mexico Gas delivered a $14 million or 73% increase in earnings compared to Q1 2022. Similar to last quarter, this was driven by favorable asset management agreements that the business entered into to utilize excess pipeline capacity, as well as new base rates that went into effect on January first. Due to a combination of market conditions and weather in the region surrounding New Mexico Gas, the AMAs generated approximately $38 million of benefit, of which $27 million will be returned to customers, the remaining $11 million before tax contributed to the higher earnings for the quarter. We do not expect to see this kind of contribution continue for the balance of the year. Contributions from Tampa Electric decreased $9 million compared to Q1 2022. The decrease was primarily driven by higher interest in operating expenses. While weather in the quarter started off mild, especially compared to the very favorable weather in Q1 2022, impacts on load were largely offset by strong customer growth. With new base rates in effect as of January 1st and the continued economic and customer growth, the business continues to be very, very strong. Contributions from our Canadian utilities decreased $10 million compared to Q1 2022. Much like in Tampa, we incurred higher interest expense and experienced a milder winter here in Nova Scotia. In addition, during the quarter, Nova Scotia Power was required by accounting rules to recognize a CAD 10 million penalty related to renewable energy standards. We intend to appeal this imposed penalty to the regulator later this year. Excluding the impact of the penalty, the financial performance of the utility in the first quarter of the year was solid, as new rates are in effect, and we continue to see load growth year-over-year driven by customer growth and the impacts of electrification. However, we continue to expect performance for the year to be close to or slightly below the bottom end of our ROE range at a reduced equity thickness of 35%. Corporate costs increased CAD 13 million this quarter, primarily driven by higher interest costs. These were partially offset by the timing of share-based compensation expense and the related hedges. Finally, higher share count decreased adjusted earnings per share by 3 cents in the quarter. Earlier this month, we completed a CAD 500 million issuance of senior unsecured notes at Emera to address our only holding company maturity this year. In March, we issued CAD 500 million of unsecured notes at Nova Scotia Power for general corporate purposes. We saw strong market support for both transactions. I want to take this opportunity to reinforce that we remain committed to our investment-grade credit ratings and that we continually do engage regularly with the credit rating agencies. In support of our financing transactions this year, all 4 rating agencies confirmed our ratings and outlooks in their standard letters. As we continue to execute on our capital and funding plans this year, I am confident that our growth in our utilities will allow us to achieve the targeted credit metrics that we have set out on a sustainable basis. Now I'll turn it back over to Dave. Thank you, Greg. This concludes the presentation. We'd now like to open the call for questions. Thank you. Ladies and gentlemen, we'll now conduct the question-and-answer session. If you'd like to ask a question, please press star, followed by one on your telephone keypad. If you'd like to withdraw your question, press star, then two. If you're using a speakerphone, please lift the handset before pressing any keys. One moment for your first question. Your first question comes from Rob Hope from Scotiabank. Rob, please go ahead. Morning, everyone. First is on the financing plan. At the Tampa Investor Day, a couple of weeks ago, you highlighted a number of other levers you could pull to strengthen metrics in 2023, including deferring some CapEx as well as optimizing some working capital. Can you maybe give us an update on those items? I guess, as well, it seems like your cash flow was strong or in line with expectations in Q1. I would imagine this wouldn't take into account the fuel over-recovery, and that would be additive. First of all, good morning, Rob. It's Greg. On the first part of your question, obviously, given the timing of the LIL commissioning, and we're quite pleased that that is now fully commissioned, it looks like the CAD 240-ish million of true-up capital will likely be in early next year as opposed to this year. Absent that, we're still looking through our capital plans, nothing definitive at this point that we're ready to communicate to you. We'll certainly refresh our capital plan as we go through the year and of course, in November, provide an updated three-year forecast at that point in time. In terms of how we're viewing cash flow, certainly if you recall, at Investor Day, we were expecting on a fuel-normalized basis to have our cash flow increase 10% on a year-over-year basis. We achieved that in the 1st quarter of this year. That was obviously not incorporating any incremental cash from Labrador Island Link because that commission didn't start till April 1. Certainly, on a non-fuel adjusted, cash flow is significantly stronger than we would have expected, in large part because of the softening commodity prices. I referenced that at this point in time, we're actually over-recovering fuel costs at Tampa Electric. Of course, the 36% increase in cash flow quarter-over-quarter, that is obviously before starting to collect cash in Labrador Island Link and also before collecting the unrecovered fuel costs and storm costs at Tampa Electric that did not start until April 1. Yes, I guess in summary, we're feeling really, really good with how cash flow has started the year and our forecast going forward. Excellent. Maybe just reading between the lines here, on the Atlantic Loop project, the commentary or tone surrounding it seems more positive than in prior quarters. Could you maybe give us an update of the gates that have to be achieved to get the clarity towards the summer, as well as, you know, when could capital or how far out can you push out capital deployment on that project? Yeah, Rob, it's Scott Balfour. I'll let Peter answer most of this. Sort of the back part of that question in terms of, in terms of capital, we'd still be in a place where we're not expecting to invest any material capital in the Atlantic Loop project itself. We're, you know, we're looking to support from engagement from other parties in terms of that. We're still, at this point, not looking for at capital deployment other than projects inside province of Nova Scotia, inside Nova Scotia Power proper. Let me let Peter answer the substance of your question. Sure, Scott. Hi, Rob. Yeah, I think it's fair to say how you're reading between the lines is that discussions with the federal government and other parties involved, remember this is, you know, a complex multi-stakeholder project, have intensified, I would say, over the last number of weeks. We're having productive discussions with the federal government. We've always said that for this project to work, our customers in Nova Scotia need direct federal support to help with the transition. I think you've seen public comments from the federal government that sounds that they're very committed to this project, and we're pleased so far with the activity around the negotiation table. I'd probably leave it there for now. Other than to reinforce Scott's point that we really. To hit the 2030 target, there's a lot to do. We really need clarity on the path forward. The biggest piece of that, what is the federal funding support, that we would need that clarity sometime this summer. Thank you. You're welcome. Your next question comes from Maurice Choy from RBC Capital Markets. Maurice, please go ahead. Thank you very much, and good morning. We're just sticking with the credit metrics theme here. You mentioned that you're feeling really good with your cash flow generation so far in Q1, yet you've reconfirmed 11.5% target for this year. Were there any headwinds that we should be aware of that might be preventing you from accelerating past 11.5% by the end this year? Also with regards to differing CapEx, maybe being a little bit more direct here. Given where the market uncertainty is there a motivation to perhaps consider that even more forcefully, despite being having good cash flow generation, just in case, and then re-accelerate next year? Yeah. I think, Maurice, it's important to remember when I mention and I refer to the 11.5% cash flow to debt metric, we're talking on a fuel normalized basis. On a fuel normalized basis, cash flow is unfolding pretty much exactly as we would have expected. You remember the catalyst to drive that were the 3 rate cases at rate increases at Nova Scotia Power, Tampa Electric and New Mexico Gas, which are now complete. Of course, the Labrador Island Link commissioning, which is also complete. We're feeling really good on that path. What we are seeing, though, is obviously a reversal of what we saw last year in terms of commodity prices and the timely recovery of fuel costs. That'll help on an overall basis. When we look at it on a normalized basis, it's been pretty much consistent with where we expect it to be. In terms of capital, again, just following up on my comments a few minutes ago, Maurice, there's nothing at this point material that would be worthy of disclosing to you. I think it's also important to remember that, you know, our capital is being deployed in our utilities for the benefit of our customers. When we're seeing large customer growth, quite frankly, not just in Tampa Electric, but in Peoples Gas, we're seeing customer growth here in Nova Scotia Power and requirements to continue to storm harden the system. That on our core business, doesn't necessarily give us a lot of flexibility to move capital, but we're still looking at the timing of the execution of that capital. There might be some capital move between years, but I would say at this point in time, we're not expecting anything material above and beyond the Labrador Island Link true-up investment that I mentioned earlier. Thanks. Maybe just a quick follow-up. Your expectation of how the rating agencies respond to these and any recent engagement with them about changing the outlooks back to stable. Yeah, I mean, that's an ongoing conversation, Maurice. I mean, generally, they look through the fuel cost recovery side of it, so looking through maybe the cash flow perspective. I think they're fairly consistent across the board. They don't normalize for the associated debt with respect to those fuel cost recoveries. Obviously, the, you know, with the majority of our underrecoveries in 22 at Tampa Electric and now having regulatory approval for that's helpful. Seeing an accelerated recovery of those costs, which does mean we're reducing our debt. Given that they don't normalize for the debt, that will certainly be a positive. Having said all of that, I'm not anticipating that we'll see a shift back to stable outlooks anytime soon. Thanks. Maybe just finishing up here on Emera Energy. Back at Investor Day, obviously we heard that, you know, Judy highlighted that the business outperformed the normal range in five out of the last nine years. In this quarter, results were clearly strong. Thoughts on your normal range of $15 million-$30 million, and if this probably should be updated? Hi there, it's Judy. Well, we're, we said we're sticking with our guidance for the year. We are. You know, everybody here I think on the call understands the phenomenon we have where our gas transportation costs are amortized evenly through the year. We have to bear the burden effect of the summer months. When we come off of a period of high pricing, it, you know, the reality is we can hedge that up in the winter and make a little bit of money, but the costs that we have to absorb over the summer are higher. When we look at our forecast now, it's only a forecast, and we do have volatile earnings, we're still comfortable for this year, at in the $15 million-$30 million range. As the summer unfolds, you know, that could change. If it does, we'll provide updated guidance. At this juncture, that's the range that still feels right to us. Great. Thank you for the color. Your next question comes from Ben Pham from BMO. Ben, please go ahead. Hi. Thanks. Good morning. Maybe back to the credit metrics and the F loaded debt target. I guess with the way you're framing it, you're excluding the or normalizing for the fuel costs recovery. You know, assuming like the Q1 trend continues through year-end, is it correct to say like on a GAAP basis that you're gonna be well above the 11.5%? Yeah. Yeah, Ben, it's Greg. It's probably too early to tell that, but I think there's a strong possibility of that. Look, as I've said before, I don't think we should be penalized when we under-recovery fuel costs and have to finance with that short-term debt, nor do I necessarily believe we should get the benefit of that. Certainly from a GAAP perspective, it's trending in a fairly material positive way on the upside. You know, just to follow up on a couple of the other questions, you know, we're feeling really good about it. Don't anticipate that there'll be any change in outlooks in the near term. Near term being the next quarter or so. I think if this trend continues, I think we'll be well positioned later in the year, on a GAAP basis with both, or quite frankly, with all four rating agencies. Okay. Can you remind me on gas hedging at the utilities? Are you restricted from doing that? We are at Peoples Gas. At New Mexico Gas, we hedge our firm base load gas, so what we expect to have as a base load requirement for our customers. In, in Florida, like the gas or like the electric utility, there's no hedging. Okay. Maybe just one clean up on the $10 million penalty at NSPI. Is that, are you reflecting that in your or should we reflect in the ROE or is that outside of the rate base calculation? I would expect that that would be excluded from the ROE calculation. Okay. Got it. Okay. Thank you. You're welcome. Your next question comes from Dariusz Lozny from Bank of America. Please go ahead. Hey, guys. Good morning. Thank you for taking the question. Maybe just starting off on the Peoples Gas rate case, acknowledging it's early days still. It's recently filed, how do you feel about prospects for settling there? I know there's been some opportunities for that in the past at the other Florida utilities. Maybe just in the past, you framed it as largely being about catching up with customer growth, OpEx, things like that, which seems fairly standard. Any other puts and takes as far as the context of the filing that you could elaborate on? Thank you. Helen? Good morning. With respect to the first part of your question, you know, our intention at this point is to continue through with a full hearing process. Both FPUC and Florida City Gas had their rate cases proceed in that way, and they had some very good results. With respect to your other question about framing, yes, you've got it absolutely right. It's largely about capital and going back to what Greg said, that's in response to very strong customer demand. Outside of that, it's really trying to ensure that we have the organizational capacity to continue to serve that demand, and then obviously effects of inflation and interest expense are the other factors. Okay, excellent. Thank you for the color. One more if I can on New Mexico Gas now. Just maybe following up on those AMAs obviously gave you a strong start to the year, $27 million back to customers, I imagine the regulator is very happy about. What about the part of that $38 million gain that goes to the utility? Is that? Do you view that as giving you additional flexibility to perhaps de-risk, O&M either later in the year or into future periods? Just curious how you're thinking about effectively using that additional gain from the AMAs. Yeah, Dariusz, this is Greg. I mean, I think it's important to maybe take a step back and think about it. We have a requirement to purchase pipeline capacity to service our customers. We've entered into asset management agreements so that when we don't need that capacity, we can utilize it and have a third party manage that for us and create some value, the majority of which goes to customers. Just wanna start with that is the benefit is largely going to customers and it's a very constructive thing. To the extent that we have an opportunity to create that benefit for customers and there's some residual value to shareholders, we don't necessarily look at that as anything that provides us with flexibility in terms of how we manage our day-to-day operations. It's nice to have. We appreciate it. It's, you know, it's real earnings, it's cash, all of those kinds of things. As an outcome of that, we wouldn't be adjusting any of our operational plans at the utility. Okay. Got it. Thank you for that. I'll leave it here. Thanks, Dariusz. Your next question comes from Linda Ezergailis from TD Securities. Linda, please go ahead. Thank you. Just wondering when you reflect on the learnings from Maritime Link and Labrador Island Link, how Emera might approach participation Atlantic Loop, beyond requiring direct federal support for NSPI customers. If it were to proceed, you know, how would you ideally see either the revenue model, construction or operations? Like, what would translate well, what would ideally be adjusted? If you can share any reflections, that would be appreciated. Yeah. Linda, it's, you know, I'd say it's still, it's still a bit early to frame a lot of that up. Really, you know, the focus that Peter and the team have had in working with the province and the federal government and the other stakeholders is how to enable the Loop as a part of a solution path to achieve the closure of coal plants and 80% renewable by 2030. The Loop is certainly a key enabler of that. It's what we consider to be what we believe is the best path forward for Nova Scotia. Of course, in addition to that, there's still a lot of things that have to happen in Nova Scotia, a stronger intertie between the province of Nova Scotia and New Brunswick. More wind needs to be built. Batteries are likely part of a solution. Other forms of providing backstop capacity as more and more intermittent renewables and wind is brought onto the system. We continue to see the loop, this transmission interconnect between Nova Scotia and Quebec through New Brunswick as a key enabler. As to what Emera or Nova Scotia Power's role is in the loop, you know, as we said, we continue to support the negotiations between the parties. Part of the ongoing conversation with the federal government is how they can assist in enabling that without or reducing the cost pressure that would impact Nova Scotia Power customers. That involves the... That includes the involvement of Canada Infrastructure Bank, which may, you know, create some innovative solutions that allows for their participation without the need for Nova Scotia or New Brunswick to directly invest and instead relying upon some financing techniques from CIB. This is all still very much in motion, in discussion, until we sort of further advance these conversations to know as to whether this is a workable path or alternative paths without the Loop need to be addressed. This is all part of the reference that Peter had to the ongoing discussions that need to be sorted through this summer in order to create a clear pathway forward to achieve those 2030 goals. Thank you. Maybe, just turning to Emera Energy Services. If we think about the capacity that you've committed to for the balance of the year, is that related to typical prior opportunities just getting more expensive, or are you adding some scope and contracting more capacity related to doing a little bit more, doing things differently? It's mostly that it's more expensive, Linda. As you know, it runs cyclically a bit. If the market gets heated, we're bidding into these kind of short-term capacity assignments every year. If you're doing that in a relatively hot market, everybody can look and see the value of the transport, they adjust their bids accordingly. It winds up, you pay a little bit more, of course, you're able to hedge it out at higher value. It's a wash there, a bit of a wash there. That's a cyclical phenomenon. If prices stay where they are currently, kind of the next round of bidding will be at materially lower amounts. We've been through that cycle before, we'll be through it again. You know, we do have a little bit more activity in the Southeast. That's something that we're picking away at building that business. Most of this would be our what we still consider our core area in the Northeast U.S. and transportation associated with that. That's helpful context. Thank you, Judy. Just a quick follow-up question. Energy is losing a little bit less money this year than last, it looks like. When is your path to getting to breakeven, and how large a contribution do you think it can make once it reaches scale? Yeah, I'd say it's, you know, it's too early to frame that up at any clarity. I'd, you know, say, Linda, we continue to be excited about the prospect of BlockEnergy. We continue to support it, fund it, obviously, as you see, and continue to be encouraged by the, you know, the reaction that we're seeing from prospective customers, from existing customers, where that product is deployed and also in the advancement of the technology to the commercial version of that technology. It's still, you know, it's still early days with this. Wouldn't want to get ahead of ourselves in terms of, you know, framing a timing for breakeven or framing up how bright the future might be for BlockEnergy. It's one that we continue to advance, be excited about. We're also, you know, cautious and realistic at the same time. Stay tuned. Thank you. Your next question comes from Mark Jarvi from CIBC Capital Markets. Mark, please go ahead. Thanks. Good morning, everyone. Wanted to touch on the At-the-Market program. As far as I could tell, it didn't seem like you guys used it in Q1. Is that a reflection of share price or just the strong fuel recovery in your energy? Assuming that the fuel recoveries track well through the balance of this year, does that change at all your sort of usage of the ATM this year? Yeah. Hi, Mark. It's Greg. Yeah, nothing's changed from our financing plan. As you know, we often access that program at different levels in different quarters. To be quite frank, it's actually often more about timing. If you think of we were relatively late in the cycle, releasing our annual results in February, so in effect, we were out of the market in January and February because of blackout. We spent quite a bit of time, kind of in the March, early April timeframe, meeting with credit rating agencies, and given the sensitivity around there, at that point, just didn't feel it was comfortable. Obviously, it's hard not to look at the share price and have that weigh in on the decision. I'd say it's more of the mechanics of the timing and market access than anything else. Okay. That makes sense. Then, you know, there's been some more, you know, press releases from different consortiums talking about offshore wind and exports on transmission down in the U.S. from Atlantic Canada, other people talking about green ammonia. Any thoughts in terms of, you know, getting involved there? I mean, why export to other markets when obviously there's a decarbonization need in the province of Nova Scotia? Sort of updated views on how those consortiums are operating and if there's any fit to try to keep more stuff local. I mean, I'd say, Mark, that, you know, Nova Scotia Power has certainly been engaged in supporting a number of developers in terms of their efforts to create a both a hydrogen and an offshore wind development opportunities here in the province. I know, you know, that continues to be a focus of one. In fact, Peter, maybe I'll let you sort of carry on with the question, actually talk a little bit about south of the border. Sure. Mark, hi. Just to reinforce that. Yeah, we're in regular discussions, collaboration with a number of hydrogen developers here. We see the potential that the development of a hydrogen economy presents for the Nova Scotia economy, very supportive of that, and have been very supportive of the needs of hydrogen developers as they get up to scale. We'll continue to work with them in supportive of the general direction. That's really the Nova Scotia Power role at this point. Beyond that, we're, you know, we're looking at our capital is really based on reliability investments inside the business. I guess just to sum it up, supportive of the activities of the hydrogen economy here in Nova Scotia. Yeah. Then as it relates to the, you know, the prospect of, you know, transmission of wind energy from Atlantic Canada south. You know, as you know, we've participated and had a number of efforts of that in the past. We're not actively engaged in that today, but, you know, there are skill sets that we've got. To the extent that those kind of opportunities develop and become more meaningful than would be something certainly that we'd be looking at and considering, but nothing that we're actively involved with today. Just to follow up on that, like the Atlantic Link project that you guys did, I think a handful of years back, that's not something that has a fit here with what that consortium is looking to do? It's, you know, a little different in terms of start point and endpoint, Mark, but certainly it's, you know, sort of the reference I made earlier that, you know, we've been engaged in a number of projects that as well as over land transmission initiatives. You know, it's a space we understand well. We understand the complexities of it. Obviously, we've had some success with subsea electric transmission cables in the past. You know, beyond the opportunities to assist any offshore wind developers that do progress in terms of interconnection into the Nova Scotia Power system, to the extent that those, you know, opportunities also look for a transmission path down to the U.S. You know, we'll certainly, you know, we'll certainly engage in discussions and explore to the extent that there is a role or an opportunity of interest or fit for us. I'd say we're not actively involved in any of those discussions today. Okay. All right. Thanks a lot. Your next question comes from David Quezada from Raymond James. David, please go ahead. Thanks. Morning, everyone. Maybe just, starting off with a question, Peoples Gas, it seems like SB 1162 has been moving forward in Florida. I'm wondering if that, I guess maybe could, bring forward or, you know, change the size of any opportunities or investments you might be able to make there in either RNG or hydrogen? Helen? I'm going to sit. Sorry, just need to make sure I'm talking about the same thing you are. SB 1162, if you're talking about the RNG and hydrogen cost recovery bill, can I just confirm? That's correct, yes. I just... Wait. Perfect. Thanks. I mean, it's interesting. We've been studying it closely and are tracking it and making sure that we're well-positioned to advocate for that. It's possible that it will have some, you know, some positive effects for us, but at this stage, it's still reasonably early and, you know, we're just evaluating it. Okay, excellent. Thank you for that. Maybe just wondering if there's any update on the plans that you rolled out at the Investor Day at Polk Power Station? Any upcoming milestones that we should be on the lookout there for some of the big projects that you have moving forward there? Archie, over to you. Good morning. No real update on our plans at Polk Power Station. We continue to work through the engineering analysis, the business cases. In Q1, I am pleased to say that we did successfully negotiate an agreement with the U.S. Department of Energy on the first tranche of funding, which they provided to us in 2022. Actually, just a week or so ago, we were informed by the U.S. Department of Energy that we have successfully, we applied for and were successful in a second tranche of funding that supports the engineering studies at Polk. We're still... This is a, this will... There's a year's worth of effort just working through all of the detailed engineering that's needed to finalize our plans there, and that's what the team is very focused on. Excellent. Thanks for that. I'll turn it over. Your next question comes from Andrew Kuske from Credit Suisse. Andrew, please go ahead. Sorry, Andrew. Unfortunately, you're breaking up, and we can't quite hear you. Sorry. Is that better? It is, yes. Yeah. Okay. I'm sorry about that. Is it fair to say the learnings from the Atlantic Link project, you know, a number of years ago is transmission, frankly, just takes a long time to get approved? You had a good idea, but it's just challenging. Are you sort of stepping back a little bit, focusing on, you know, what you can control to a greater degree on the onshore, and then seeing opportunities to connect with offshore wind in more of a, like, a backing in kind of fashion should those projects proceed? Yeah. If I'm understanding you correct, your question, Andrew, if it's in relation to our role or participation in offshore wind. Yeah, you know, I think the way you framed it would be correct, where, you know, the reality is for Nova Scotia Power in serving its customers, onshore wind is far less expensive, far more cost-effective than offshore wind. There continues to be significant onshore wind development opportunities. You know, that's been the focus for both the province of Nova Scotia in its procurements and for Nova Scotia Power in its integrated resource plan, is continuing to advance and support onshore wind. The offshore wind development, you know, offshore wind continues to get more economic as the size of turbines continue to increase to impressive scale. You know, the offshore wind, I think, has been an area of particular interest when looking at hydrogen development in the province as being an enabler and a supporter of the significant energy requirements that are needed for the production of hydrogen, particularly in green hydrogen form. You know, we continue to be here trying to be as helpful as we can to hydrogen and offshore wind developers to the extent that, you know, Nova Scotia Power participates in the interconnection and system support components of that. It will obviously be doing so. If and when we see opportunities from an Emera perspective to be exploring investment and participation, you know, we'll continue to assess that the same way we always have in terms of ensuring that it makes sense for us from a financial and risk perspective. It's a, you know, these are files that we continue to actively watch. We are building relationships We're not specifically engaged in investment or advancement of any of those particular developments currently, but it certainly files that we're watching and we'll engage if and when it seems to make sense. Okay, appreciate that. Maybe just, not completely obscure, but it's gaining a lot more popularity recently just on pump storage and your Bear Swamp exposure. If you could just maybe just give us a brief highlight of the contractual length around Bear Swamp and, just what your expectations are of the asset. Andrew, it's Judy. Bear Swamp doesn't really have. It's a market facility now. It's entitled to capacity payments from ISO New England. You know, it basically, Brookfield is the commercial manager, and they manage it on a daily basis in the market. Years ago, it had a long-term supply agreement with LIPA, that ended, I think, April of 2021. It's a market-facing facility. Just had a big upgrade on both units, it's in excellent condition. I would say it's the largest battery in New England. It's there. It's a challenge, and we're working it every day. Is we feel it should be paid a little bit more for the value it provides in terms of its callability and that kind of thing. That's a long process with the, with ISO New England to try to get that properly recognized. In the meantime, it's basically a market facility. Okay. Appreciate that. Thank you. Thanks. Your next question comes from Patrick Kenny from National Bank Financial. Patrick, please go ahead. Hey, good morning. Just wanted to come back to the fuel costs over recoveries in the quarter. The $81 million at Tampa Electric makes sense. Can you just walk us through the drivers of the $33 million of underrecovery at NSPI? I guess if commodity prices stay where they are, if you expect NSPI to switch to overrecoveries for the balance of the year. If so, wondering if there might be any mechanism within the new regulatory framework where you could reallocate some of those overrecoveries towards non-fuel rate increases, say above the 1.8% cap that might allow you to bring forward some capital projects in Nova Scotia. Thanks. Patrick, it's Greg. We're not expecting because we have a fairly extensive hedging program at Nova Scotia Power, we're not expecting to have any overrecovery of fuel costs this year. If you think of the rate settlement, the majority of the rate increase in 2023 was directed to non-fuel, that effectively flips in 2024. The underrecovery that we're experiencing is kind of by design. That'll get, you know, largely collected in 2024. You may recover or may recall as well that the agreement that we have with the customer groups that the UARB has approved, that we'll be filing later this year as well for any incremental change that we need on fuel rates for 2024. At this point in time, we wouldn't expect that profile to reverse at all. Got it. Okay, thanks for that. I would say- And the- Sorry, Patrick. I would say it generally is higher in terms of total dollars in Q1 just because that's where the majority of our load is over the course of the year as well. Makes sense. Okay. Thank you. At New Mexico Gas, again, just given the lower natural gas price outlook, wondering if there's been any change in thinking around the need for LNG storage or perhaps any delay in development of that project, at least until you have maybe more certainty on the macro commodity price environment. Ryan, do you wanna answer that one, please? Yeah, I'm happy to take that. I think our view on LNG is it's still very good for customers. It's not only a pricing play but a reliability play here in New Mexico. We believe if we own the storage ourselves that it's a much more reliable asset. We can get our gas quicker, it's under our control. We still feel it's an important asset for the business for the long term. We, you know, I understand that gas prices have moderated here in the last month or so, we certainly don't know in the future where gas prices will be. We still think it's a very positive investment for customers. Okay, perfect. Thanks for that. Last one, maybe for Greg as well. Just back to your commitment to the investment-grade credit rating, and I know your metrics are moving in the right direction, but just wanted to confirm that your commitment to, your commitment is to an IG rating across all rating agencies, or is it more of a, an average IG rating? In other words, if 1 rating from 1 agency slipped, you know, 1 notch to non-IG, but the others stayed intact, would you be okay with not taking any action unless more than 1 of your ratings fell to non-IG? Thanks. Yeah, Patrick, it's probably a hypothetical question. I mean, we're committed to investment-grade credit ratings across the board. in general, I mean, the rating agencies are, you know, typically in line with each other on their views. We're happy with the progress. We're on the path that we have in front of us. we don't believe we're gonna be in a situation where we're gonna have to contemplate that. Excellent. I'll leave it there, guys. Thank you. Thanks, Patrick. Ladies and gentlemen, as a reminder, should you wish to ask a question, press star followed by one. Okay, there are no further questions at this time. I'll turn it back to Dave for closing remarks. Thank you, Colin. That concludes our call for today. Please reach out to investor relations if you have any questions. Thank you very much and have a great day. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.