Emera Incorporated (EMA) Q1 2024 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Emera Q1 2024 Earnings Conference Call. At this time note that, all participant lines are in the listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] Also note that this call is being recorded on Monday, May 13, 2024. I now would like to turn the conference over to David Bezanson. Please go ahead, sir.

Thank you, Sylvie, and thank you all for joining us this morning for Emera's first quarter 2024 conference call and live webcast. Emera's first 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. Earlier this morning we reported Q1 2024 earnings of $0.76 per share as compared to $0.99 per share in the first quarter of 2023. As we look at our first quarter, I want to provide some context on our results and to express our confidence as we look ahead to the rest of 2024. Results this quarter compare to an unusually strong first quarter last year across many of our businesses. As a result, our results don't seem as strong in comparison, and Greg will talk more about this in a few minutes. Despite the reduction in EPS for the quarter, we remain confident about the year ahead and our ability to deliver solid earnings. Across the board, our regulated utilities continue to execute well on their business plans. They remain focused on safely and reliably delivering energy to their customers and investing in their systems, and to continue to do so with investments focused on reducing carbon, improving reliability, and supporting electrification. Since the start of 2024, we've already deployed more than $600 million in capital. We're well on the way to fully executing our 2024 capital plan where we will invest almost $3 billion, part of our 7% to 8% three year rate-based growth forecast, and a driver of our forward-looking earnings growth expectations. Our capital investments are focused on the core pillars of reliability and energy transition. Our work this year will help our operating companies ensure the reliability of their grids, while managing through the energy transition in a manner that is as cost-effective as possible for their customers. We're also working to ensure we continue to secure the timely return on and return of our investments, which is even more important within the higher cost of capital environment we're in today. Our operations in Florida continue to be the growth engine of Emera. Three quarters of our capital plan is being deployed into customer focused investments at Peoples Gas and Tampa Electric, largely to support the overall growth we continue to see in the region. Florida is one of the fastest growing economies and populations in North America. At Tampa Electric, investments include our storm protection plan, where we expect to spend $185 million this year to continue to increase the resiliency and thus reliability of Tampa Electric System. This capital program will see Tampa Electric underground approximately a 100 miles of higher risk existing overhead lines this year, and upgrade more than 1,100 poles. Of more than 12,500 miles of distribution system, more than half are now underground. The team in Tampa is also continuing to invest in solar generation, which is both cost effective for Tampa Electric's customers, but also reduces reliance on fossil fuels. By the end of 2024, we expect to have 1,350 megawatts of installed solar capacity. The team continues to deliver value to Tampa Electric customers, and these projects are excellent examples of that value. Still looking at Florida, Peoples Gas is investing to support growth in the state and its role as an integral part of the energy ecosystem. Peoples Gas has recently signed up another Renewable Natural Gas or RNG facility as it continues to invest in diverse and cleaner energy solutions to meet the growing needs of Floridians. The Polk RNG facility will connect the Polk County Landfill operation in Winter Haven, Florida with the Florida Gas Transmission System. This important project is in the engineering stages and should take approximately 12-months to complete. Additionally, the team of Peoples Gas are supporting Florida in its Highway 98 expansion, which involves replacing 12 miles of existing transmission pipeline to accommodate the widening of Highway 98 in Polk and Pasco Counties. And of course, the growth in this business continues as Peoples Gas is adding approximately 20,000 new customers this year. Peoples Gas is on pace to soon become our second largest business. Reliability, efficiency and safety are common themes across our operating companies. In Nova Scotia, the Nova Scotia power team continues to work with our New Brunswick neighbors to advance work on the Atlantic Reliability tie. This project will strengthen the transmission connection between the two provinces. To deliver more reliable electricity to Nova Scotia and to support the integration of new wind energy that we expect to be added to the grid in the future. The project has received environmental approval in Nova Scotia and engineering and project management work will continue through 2024. Nova Scotia Power is targeting an in-service date of late 2027 to mid-2028. The Nova Scotia portion of this project is estimated to cost $800 million of which Nova Scotia Power will be responsible for investing 50% with the remaining 50% funded by the Canada Infrastructure Bank. We remain confident in our ability to not only successfully execute on our three-year capital plan, but also to ensure a timely recovery on prudently incurred investments through a rate case cadence that aligns our infrastructure investments with the regulatory processes required to support them. Given how topical it is, I would like to note that while data centers are not yet impacting our service territories, we are working with the economic development agencies in Tampa to better position and ready the Tampa region and Tampa Electric for the opportunity. In the meantime, Tampa Electric team remains focused on serving our existing growing customer base reliably and safely. Tampa Electric has filed a petition for future rate increases with the Florida Public Service Commission requesting US$297 million in new rates effective January 1, 2025. The rate case outlines additional increases that would take effect January 1, 2026 of $100 million and $72 million on January 1, 2027. These subsequent year increases would be tied to the successful completion of specific capital projects that are already in motion. We expect hearings for the rate case to take place in the second half of August with a decision in the fourth quarter of 2024. On April 30, Nova Scotia Power received $117 million from the province of Nova Scotia for the securitization of the balance of 2024 fuel costs. This is an important example of the province working collaboratively with Nova Scotia power to develop solutions that benefit Nova Scotia's and help Nova Scotia power continue to focus on reliable service delivery for customers, while maintaining the financial integrity of the business. We were pleased that the New Mexico gas team and all interveners achieved a settlement in New Mexico gases rate case supporting an annual base revenue increase of US$30 million to take effect October 1st of this year. Pending final review and support by the PRC. The ROE and capital structure remain unchanged at 9.375% and 52% respectively. Our teams work very hard to engage with regulators and stakeholders to achieve regulatory outcomes that first and foremost benefit customers, but which also and essentially deliver reasonable financial outcomes, thus ensuring continued access to competitive cost of capital at our utilities. I'm pleased to report that our regulatory agenda remains on track for the year. Despite the fluctuations that can happen in every any given quarter, the underlying drivers of growth in our business remain strong. We have significant population growth in our core geographic service territories of Florida and Nova Scotia. We have significant demand for investments to be made in support of our utility customers, and we have constructive and professional regulators that understand the business we operate in. This is underpinned by the focus we have at Emera. Focused planning, focused investments and focused teams. Before I turn it over to Greg, I want to say that while we don't have anything to announce today on our asset sale program, we continue to be encouraged by what we've seen so far in the processes. We continue to be on track to provide clarity by the end of June. And with that, I'll turn it over to Greg to take you through our financial results.

Thank you, Scott, and good morning. This morning we reported first quarter adjusted earnings of $216 million in adjusted earnings per share of $0.76 compared to $268 million and $0.99 in 2023. The reduction in EPS this quarter was not unexpected. Q1 2023 was an unusually strong quarter with New Mexico Gas and Emera Energy reporting their highest quarterly earnings ever, and Tampa Electric, experiencing very strong weather driven load compared to historical norms. Whereas in Q1 2024, we've experienced the mildest weather seen in West Central Florida in 50 years, higher operating costs resulting from growth in our business and investments in reliability, and increased holding company costs, largely from the timing differences on the mark-to-market of hedge on our long-term compensation plan. On the positive side of things, this quarter's results reflect increase in continuing customer growth in Tampa Electric, Peoples Gas and Nova Scotia Power. It reflects new rates of Peoples Gas resulting from the 2023 rate case and solid starts the year for Emera Energy, albeit lower than last year. Operating cash flow before changes in working capital decreased modestly year-over-year, largely as a result of the lower operating earnings in the quarter. And now I'd like to take a deeper look at the details of our quarterly results. Peoples Gas recorded its highest quarterly earnings ever driven by new rates at the beginning of the quarter that reflect the growth that has been experiencing over the last three years. This increase was muted a little by a return to more normal AMA earnings at New Mexico Gas. As a result, the gas segment was up $3 million or $0.01. Very mild weather in the quarter was responsible for $14 million or nearly two thirds of Tampa Electric's $22 million or $0.08 earnings decrease. The balance was due to higher cost to run the business, partially offset by new base rates and customer growth. Tampa Electric is seeking recovery of these higher costs in its base rate application. Nova Scotia power earnings were $11 million or $0.04 lower quarter-over-quarter as they experience higher operating costs to support the customer growth that we are experiencing partially offset by higher revenues as a result of that customer growth. Emera Energy recorded second best Q1 ever, but it didn't compare to the strength of Q1 of 2023 as I mentioned earlier, when they benefited from a much stronger natural gas market, they were down $10 million or $0.04 for the quarter. And higher share count, decreased adjusted earnings per share by $0.04 in the quarter as a result of our drip in ATM activity over the last year. Our corporate costs increased by nearly $24 million or $0.08 this quarter, primarily driven by higher long-term compensation hedge expense and higher interest expense offset by lower corporate taxes. By far, the large driver of this would be the hedges, which negatively impacted pre-tax earnings by $18 million or $0.07. On our fourth quarter call, I outlined three key areas of focus for us as we work diligently to strengthen our balance sheet. I'm pleased to say that we continue to make progress on all three fronts. Timely collection of deferrals remains a key area of focus for us, particularly in Nova Scotia. As Scott mentioned, we have received $117 million of fuel funding from the province, and we are actively working with stakeholders on a plan to collect the remaining FAM deferral in a way that balances timely recovery with customer affordability. Minimizing regulatory lag is an important part of managing our growth, last month, Tampa Electric made its 2025 base rate application. Given the outcome of the people's gas rate case last year, we are confident that we will receive a constructive outcome that will allow Tampa Electric to recover on the rate base investments it has been making since 2022. Our traditional financing plan supports our rate-based investment program in addition to reinvested cash flow, the ATM and Drip will remain an important source of equity for us in 2024. We also continue to evaluate the hybrid capital market on both sides of the border, and we believe this presents an opportunity, a viable opportunity to further strengthen our capital structure. In addition to our traditional sources of financing, we remain committed to executing our asset sale program. We intend to use the proceeds to retire variable rate holding company debt, which will further improve our ratio holding company debt to total debt and strengthen our overall credit profile. We are firmly committed to retaining investment grade ratings and are confident that our actions to sell assets and reduce holding company debt will significantly improve our credit metrics. These activities are further supported by our ongoing rate base investments and regulatory filing that will drive predictable cash flow growth over time. Executing in these three areas will ultimately result in a stronger balance sheet and returns to stable investment grade metrics in the near future. And with that, I'll turn it back over to Scott.

I'd like to wrap up today's call by reiterating that we are confident in the path we're on, whether that's executing this year's portion of our nearly $9 billion three-year capital plan, successfully navigating Tampa Electric’s rate case, or strengthening our balance sheet through asset sales. We are focused on delivering value for our customers and creating value for our shareholders. We have meaningful growth in front of us, and in the short term, our focus to ensure we are best positioned to fund that growth. That concludes our remarks, and I'll turn the call back to Dave.

Thanks Scott. We'd now like to open the call for questions or mails.

[Operator Instructions] Your first question will be from Maurice Choy at RBC.

I wanted to pick up on your 2024 outlook on Tampa Electric. Despite the week Q1 results at the utility. You've not changed the commentary in your MD&A for the outlook. So what are you expecting it may happen over the balance of the year that'll keep you towards the low end of the re range.

Thanks for the question, Maurice. Archie, I'll let you respond to Maurice.

Sure. Great. Good morning, Maurice. Greetings from Tampa, Florida. A couple of things Maurice in response to the question. First of all, as Greg and Scott alluded to the weather in Q1 was unusually mild, meaning it was neither warm nor cold. We generally benefit from a fair level of heating degree days in the first quarter driven by cold weather. And we just didn't get that in the first quarter of this year. It was just mild weather not good for heating and not good for cooling either. Over the balance of the year, we expect the -- we expect to see a reversion to the mean and a return to the historical 20 year average. The first quarter tends to be a quarter that contributes a disproportionately small portion of our overall annual net income. And so, as we look for the towards the last nine months of the year, we just have every confidence that we'll see stronger weather, and in and increased discipline on O&M management and some of the other costs that dragged this down in Q1.

Just so I'm clear, I understand the oil management bit, but you mentioned weather. Are you expecting the nine months to have stronger weather than the past to offset the weaker weather than Q1?

Again, Maurice, like the earnings contribution from Q1 is disproportionately, it tends to be our weakest quarter, our smallest quarter. I should rephrase that. Our smallest quarter from an earnings contribution perspective. So ample opportunity over the remaining nine months to more than make up for our shortfall in revenue in Q1.

And just to clarify, O&M management, you mentioned that, what type of O&M management are you expecting to better control?

I think the biggest ones would be for in the first quarter, we saw a higher bad depth than historical. And that's just driven by -- it's a bit of a lag associated with higher rates, higher bills from 2023. The fact that we have reduced electricity rates so substantially in 2024, largely driven by a sharp decline in the fuel markets has manifested itself into lower bills for customers that are easier for them to manage and therefore lower bad debt expense over the balance of the year. First quarter of the year also tends to be a big one for us from an O&M perspective on generation maintenance that tends, that's our shoulder season where we're doing a lot of our big major maintenance and we had a fair level of that in the first quarter of this year.

And if I could finish off with the asset sale program from what I recall, the asset sale program was sized to be up to 15% of your roughly $9 billion CapEx plan. As you're encouraged by the process, and you do have clarity coming by the end of Q2, I wonder whether you could just refresh us on how you see the size of this program, and also the number of asset sales that you have ongoing right now.

Scott again, so as we chatted about in our Q4 call, we shared that we're running two processes with this really to ensure that we're successful with at least one that would meet that objective in terms of the capital funding program as you described. But to the extent that we can be successful with both and achieve value expectations, then we would execute on both. And we hope to have, as I say, clarity on all of that by the end of June.

To be clear, you expect to have clarity on both processes by the energy.

That's right.

Next question will be from Rob Hope of Scotiabank.

Question on the credit metrics. When we take a look at the target for 12% for 2024, just given the weaker than expected to start to the year, can you do that organically or will you have to rely on asset sales to get there? And I guess maybe as well as how are kind of fuel costs trending relative to collections?

I wouldn't if you think of what we experienced in the first quarter, despite the disappointing earnings results, a large portion of that's non-cash and the timing of the mark-to-market on the hedge, our operating cash flow was still well north of $600 million in the quarter. So nothing from an organic perspective that that was overly material in the quarter. Although, as we said all along, one of the things, one of the reasons why we were looking at asset sales was to de-risk the achievement of those targeted credit metrics. And nothing has changed from that side of it either. So between the organic growth we're seeing in the business and with the asset sales, we're confident that we'll be where we need to be in 2024.

Thanks for that. And then maybe we can revisit the Atlantic Loop, appreciate the commentary on it. However, it's been fairly topical in recent weeks in the media with various people. When you take a look at the path forward for this project, kind of what do you think are the risks or the key gating factors that we should be looking for?

Rob, Peter is here, and I'll pass to him in a second, but just for clarity, obviously, part of the solution to address the clean energy ambitions for province of Nova Scotia is the need for incremental transmission. And the Atlantic Loop is still a project that is in line of sight, but isn't what the current focus is. And maybe with that set up, Peter can take it from there.

Thanks, Scott. Hi, Rob. So we're focused on the Nova Scotia, New Brunswick timeline. So 345 kV transmission project connecting Nova Scotia to New Brunswick primarily for reliability purposes. That would run from Onslow on the Nova Scotia side to Salisbury. You've probably heard it referred to as the first leg of the Atlantic Loop, but we're not currently developing that total Atlantic loop at this point. We're just focused on that timeline. I think your question was around the risks, the risks of that project or like any transmission project, but we've been progressing very well in terms of land acquisition. All the early engineering, that we're doing in cooperation with New Brunswick Power is going well, looking to supply chain, to manage, make sure we get what we need on time. And so, Scott, I think mentioned in his earlier comments to have that in service by late 2027 or at least the first half of ‘28, certainly is achievable.

Next question will be from Ben Pham at BMO.

Maybe on that, continue on the last question on the tie in, you mentioned the Canada Infrastructure Bank earlier. Was that reference to the debt component of it or is it -- or are they investing alongside, differently?

Yes, early days yet, we haven't finalized that. It's the concept. But we're looking at a special purpose vehicle, special purpose entity where we would fund 50% of that project, and CIB would fund 50% of that project. I would expect that it would be a combination of debt and equity on their side.

Okay. Got it. And maybe, as you think about your payout for the year, you've reaffirmed the dividend growth afford of 5%. As you look at that internally, do you -- does a mirror normalize for weather volatility as they think about the payout? And is there a scenario here where your payout ratio could be increasing versus 2023 results?

Ben, -- we don't generally look to sort of normalize whether for purpose of calculating our payout ratio. We know we just really drive that off of adjusted earnings. And we think about that, obviously, both as to where we're at relative to current adjusted earnings and historical adjusted earnings. And of course, we also look at it on a forward-looking basis. But no, we don't get into the fine tuning that in terms of pro forma calculating that on a weather adjusted basis.

And may maybe the - just I think with the payout then you have some of the directional earnings drivers. You mentioned Tampa up gases is up NSPI flats. I mean, is that you think what the puts and takes the payout ratio, you, you think in directionally then it's -- it could probably be improving versus ‘23 or you potentially seeing going on the other side?

I'm not going to get into a forecast of what our payout ratio will be for 2024. I know you'll understand that, but maybe -- let me get at it this way, Ben, is to say, look, we know our pay ratio is higher than where we would like it to be. It's higher than where our target is. But I also say that we continue to believe that our dividend -- current dividend growth profile is sustainable. That over time our EPS growth will outpace that 4% to 5% dividend growth profile, and therefore, our payout ratio will come down over time. And it obviously that will take some time, but we continue to be confident that our payer ratio will come down over time. Now, I will say that we have had feedback and input from some investors suggesting that moderating that dividend growth profile might be something that we should consider. And we've certainly heard that input looking at dividend growth and the setting of dividend, of course, that as you know, is a decision for the board, not for Greg and I, but we will engage with the board and share of course that investor feedback and discuss that with them. But in the meantime, we continue to believe that that payout ratio will come down over time as a result of our earnings growth expectations exceeding the dividend growth guidance.

Next question will be from Mark Jarvi at CIBC capital markets.

Just clarify on the comments around the clarity around the asset sales by the end of June. Is that that you have seen indicative offers that you'll proceed with that? Or is that expectations to have binding base at that point?

I'm not going to get too fine tuned in terms of where we're at in the process given the end of the end of June is only six weeks away Mark. But obviously, we would expect to be providing clarity in terms of where we sit and path forward by the end of June. So I think you could reasonably interpret that to be in a position where we're hoping to make an announcement within the timeframe between now and the end of June.

Understood. And then Greg, coming back, you made some comments around hybrid market, north and south of the border. Would you say that the opportunity to access that market is stronger today than maybe a couple months ago?

Yes, it is Mark, and well, it is certainly stronger in the United States. We've seen spreads tighten up quite a bit, and some of the methodology changes that the rating agencies have implemented have made it a little bit more attractive. You certainly would've seen some of our peers in the U.S. do fairly substantial hybrid offerings in the United States. I wouldn't necessarily say the Canadian market has been this constructive recently, but we're certainly seeing a much more constructive U.S. market.

Okay. And then obviously a lot of chatter about low growth, particularly in the U.S. data centers, reshoring, all that kind of stuff. You think about Tampa Electric, it starts at a fairly high level of load growth, great population growth activity there, economic activity. Is there less of an upside case than Tampa Electric? Or do you think sort of that spread between current load growth and where it could go across the U.S. could translate as well into Florida and your service territory?

Yes, let me start, Archie can backfill. You're right, Mark, we're fortunate enough that the economy, the business climate, the population growth in Florida are all very strong. And we're blessed to have not just one but two utilities of course based in that state. And as a result of that underlying growth, economic population growth, we're obviously seeing good growth of those utilities. The data center driven, the generative AI driven, load growth that I know is evident in some service territories has not been part of our story thus far. But the team at Tampa and Archie and team are positioning to see if they can take advantage of some of that opportunity to position the Tampa region and Tampa Electric to be able to respond to and maybe even attract that kind of opportunity into the service territory. But it has not been part of the growth story to date. The growth story is thankfully quite robust without it, but to the extent that there is some success in seeing some of that data center generative AI type of load activity that that creates incremental opportunity for growth for Tampa Electric. Archie, anything else you'd want to add to that?

Well, I think you answered that well, Scott. I think, Mark is asking the question because as a cost of service utility, there's a range within which we are permitted to earn. And so trying to figure out whether or not added load driven by data centers what does that really represent from a net income perspective, we're required by regulation here in the state of Florida to maintain 20% reserve margins in our winter and summer capacity. So to the extent, there is meaningful data center growth that impinges on our current reserve margins, then we would need to add new generation in order to maintain the thickness of those reserve margins. I think, the other side of the coin for us is, while we are running hard at data centers from a growth perspective. I think our real interest in data centers is really driven by customer affordability. The best way for us to keep electricity price increases in check is to grow revenues. And as you said, Mark, we benefit from strong revenue growth on an annual basis now because of customer count increases annually. But to the extent we could, we could meaningfully grow revenues through data center growth and push down residential rate increases or commercial industrial rate increases, or very, very interested in pursuing that on behalf of our customers.

If I just kind of summarize that, the view would be that the low growth that you've seen in the last couple years persists not inflecting up higher yet in that inflection, if it low growth goes higher, would be beyond the current rate case that you're proceeding right now?

Definitely.

[Operator Instructions] And your next question will be from Patrick Kenny at National Bank.

Just on Tampa Electric and the new GHG standards and the CCR rules, is it too early to quantify the costs to comply with these rules and maybe the timing of when these costs might occur? Also, just wondering from a cost recovery standpoint, if it might be too late to go back in for a bump to the revenue requirement through 2027 for these costs, or if you have to wait until the 2028 timeframe.

Over to you, Archie.

I think the short answer on this is the incremental costs that Tampa Electric would have to incur to comply with the new -- the final version of these power plant rules is very, very small. And it's largely because of the it's the result of the proactive actions the company has taken, quite frankly, over the last 10 or 15 years that have insulated customers from being impacted by these regulations today. And I think that's something that Tampa Electric can be very proud of and how it's run -- how it's managed the business over the last 10 or 15 years. I don't think all utilities have been as forward looking and are as well positioned. The only impact to us from our examination of the various elements of those power plant rules is that our one remaining coal burning asset, which is Big Bend 4, which two years ago was converted to be able to consume, achieve full load on natural gas. The only impact is that unless we elect to invest in the best available technology in the year 2039, to extend the life of Big Bend 4 would have to retire in the year 2039. Our current expectation what's on our books, we we're depreciating Big Bend 4 out till 2040? So with a pretty nominal impact in one year shorter life on Big Bend 4, should we not elect to invest in the best available technology in 2039?

And then maybe just for Greg, looks like there's still 176 million remaining under your existing ATM program. Just wondering, in light of the midcourse fuel cost adjustment for Tampa other moving parts that might be affecting near term FFO, just if you're considering maybe upsizing the ATM program at all through 2024, or if that's, I guess, contingent on how the asset sale program goes?

Yes, Patrick, yes, I mean the mid-year course correction, obviously, well, let me say it this way. It doesn't really have that impact any impact on cash, because the reason we're making a correction is because gas prices are low. We're paying less for gas and therefore collecting less from customers. So net-net it doesn't really have an impact on operating cash flow for 2024. We haven't made any determination obviously, we on normal course business outside of asset sales, we would raise summers around $250 million to $300 million a year on our ATM program. If we were to continue down our traditional path over the balance of ‘24 and ‘25, then obviously we'd need to amend the shelf to have the capacity to do that. But we're not doing that at this moment.

Next question will be from Linda Ezergailis at TD Cowen.

Just trying to get a sense of with respect to asset sales to the extent that they will clearly be credit positive, I'm just trying to get a sense in terms of order of magnitude as to how dilutive potentially they might be on an EPS basis. And has the board kind of taken that reset potentially into account when they, consider the dividend growth over the next couple of years? Or is that something that might get reassessed, once, you kind of crystallize the asset sale number and value?

Yes, Linda, it’s Greg. Thank you for the question, but I'm not going to get into specifics in terms of expectations on value and impact on credit metrics and EPS, I think it's premature to do that would all get disclosed with any associated announcement. But I think it is fair to say that as we have continually evolved our financial plans going forward and use those financial plans to also evaluate our dividend policy, all of those things are of course, always taken into account.

Okay. Thank you. And maybe you can help me understand one of the shifts in your outlook semantics that I picked up, and maybe you can let me know if there was anything substantive beyond this was in your New Mexico gas. I guess there's higher expenses expected, was that substantially in Q1 or is there kind of a run rate of higher expenses in your gas utilities expected going forward? Can you help us understand that?

Ryan, maybe you could respond to that.

Yes, I'm happy to. We had higher cost in Q1, and I would expect those to continue in the second and third quarter. But we do anticipate rate starting in October, which should cover the increase in cost. So it would just be for the second and third quarter where we'd see that increase not covered in revenues.

Okay. Thank you. And are there any other areas of your business that have a shift in outlook in terms of the run rate of cost this year? Or is that the main one?

Yes, I don't think so, Linda. I mean, we've had a little bit higher operating costs at Nova Scotia Power largely because of the customer growth and the reliability work the team is doing there. That was not unexpected to us. When we would've provided the overlook at in our year end results, that would've contemplated that that kind of run rate we would maybe not at the same pace, but continued to some degree over the balance of the year. And then of course from a consolidated basis on the corporate side, the market to market on the hedge is effectively a timing difference.

And I realize that there's still a lot of runway in the year to have some hot days and air conditioning load, et cetera, but can you just give us a sense Q2 to date what sort of weather you've been seeing in your regions and how that might be deviating from normal?

Let me kind of speak globally at a high level, Linda. I mean, I think what we experienced in the shoulder season in Florida, sort of continued through a good chunk of April that won't be a surprise to anybody. But summer has now hit in Tampa. And so we're certainly pleased to see that there's a lot of uncomfortable people because of the heat in Florida these days. So that's certainly helpful. It's been a little bit spottier here in Nova Scotia. It is actually it's been unseasonably cool, which too early to tell, but we suspect that that'll probably be slightly constructed for load in the second quarter as most of us haven't turned the heat off in our house yet.

Thank you. And at this time, Mr. Bezanson, we have no other questions registered. Please proceed.

Thank you very much. Thank you all for your interest in Emera and participating in our first quarter 2024 conference call. Please reach out to Investor Relations if you have any further questions. Thank you and have a great day.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending and at this time we ask you to please disconnect your lines.