Emera Inc

TSX:EMA

Earnings Call Transcript 2024-Q1

[Operator]

Good morning, ladies and gentlemen, and welcome to the Emera Q1 2024 Earnings Conference Call. [Operator Instructions] Also note that this call is being recorded on Monday, May 13, 2024. And now I would like to turn the conference over to Dave Bezancon. Please go ahead, sir.

[Dave Bezanson, executive]

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 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 will 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'll turn things over to Scott.

[Scott Balfour, executive]

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 compared 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% 3-year rate base 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 the 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. 3/4 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 store protection plan, where we expect to spend $185 million this year to continue to increase the resiliency and thus reliability of Tampa Electric Systems. This capital program will see Tampa Electric underground approximately 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 at 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 time. This project will strengthen the transmission connection between the 2 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 3-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 $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 Scotians 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 $30 million to take effect October 1 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 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.

[Gregory Blunden, executive]

Thank you, Scott, and good morning. This morning, we reported first quarter adjusted earnings of $216 million and 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 Tempa 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 a 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 on Peoples Gas resulting from the 2023 rate case and a solid start of 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 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 it has been experiencing over the last 3 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 2/3 of Tampa Electric's $22 million or $0.08 earnings decrease. The balance was due to higher costs 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 experienced 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 largest driver of this would be the hedges, which negatively impacted pretax earnings by $18 million or $0.07. On our fourth quarter call, I outlined 3 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 3 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 maintenance 2,025 base rate applications. Given the outcome of the Peoples 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 base 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 of 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 filings that will drive predictable cash flow growth over time. Executing in these 3 areas will ultimately result in a stronger balance sheet and return to stable investment-grade metrics in the near future. And with that, I'll turn it back over to Scott.

[Scott Balfour, executive]

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 3-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.

[Dave Bezanson, executive]

Thanks, Scott. We would now like to open the call for questions from analysts.

[Operator]

Thank you, gentlemen. [Operator Instructions] And your first question will be from Maurice Choy at RBC.

[Maurice Choy, analyst]

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

[Scott Balfour, executive]

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

[Archibald Collins, executive]

Sure. Great. 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 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 -- towards the last 9 months of the year, we just have every confidence that we'll see stronger weather and increased discipline on O&M management and some of the other costs that dragged us down in Q1.

[Maurice Choy, analyst]

Just so I'm clear. I understand the management bit, but you mentioned weather. Are you expecting the 9 months to have stronger weather than in the past to offset the weaker weather in Q1?

[Archibald Collins, executive]

Yes. Yes. Again, Maurice, the -- like the earnings contribution from Q1 is disproportionately -- it tends to be our weakest quarter, our smallest quarter, I should -- I should rephrase that, our smallest quarter from an earnings contribution perspective. So ample opportunity over the remaining 9 months to more than make up for our shortfall in revenue in Q1.

[Maurice Choy, analyst]

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

[Archibald Collins, executive]

The -- I think the biggest ones would be -- in the first quarter, we saw higher bad debt 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.

[Maurice Choy, analyst]

Understood. And if I could finish off with the assets 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 Balfour, executive]

Yes. Maurice, is Scott again. So as we chatted about in our Q4 call, we shared that we're running 2 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 programs as you described. But to the extent that we can be successful with both and achieve value expectations that we would execute on both. And we hope to have, as I say, clarity on all of that by the end of June.

[Maurice Choy, analyst]

Just to be clear, you expect to have clarity on both processes by the end of June.

[Scott Balfour, executive]

That's right.

[Operator]

Next question will be from Rob Hope at Scotiabank.

[Robert Hope, analyst]

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

[Gregory Blunden, executive]

Yes, Rob, it's Greg. Yes, I wouldn't -- if you think of what we experienced in the first quarter, despite the disappointing annual results, a large portion of that is noncash 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 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 derisk 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.

[Robert Hope, analyst]

And then -- maybe we can revisit the Atlantic Loop. I 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?

[Gregory Blunden, executive]

Rob, so 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 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 that set up, Peter.

[Peter Gregg, executive]

Thanks, Greg. Yes, so we're focused on the Nova Scotia to Brunswick Taiwan. So 345 kV transmission project connecting Nova Scotia to New Brunswick primarily for reliability purposes that will run from on slow 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 at this point, we're just focused on that Thailand. I think your question was around the risks. The risk 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 to 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.

[Operator]

Next question will be from Ben Pham at BMO.

[Benjamin Pham, analyst]

Maybe on that contain the last question on the tie in. You mentioned the Canada Infrastructure Bank earlier. Was that a reference to the debt component of it? Or is it -- are they investing alongside differently?

[Scott Balfour, executive]

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

[Benjamin Pham, analyst]

Okay. Got it. And then maybe as you think about your payout for the year, you've reaffirmed the dividend growth of 4% to 5%. Have you lost that internally, do you -- does Emera 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?

[Scott Balfour, executive]

Ben, we don't generally look to sort of normalize weather for purpose of calculating our payout ratio. 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. And -- but no, we don't get into the fine tuning at in terms of pro forma calculating that on a weather-adjusted basis.

[Benjamin Pham, analyst]

And then maybe the -- just how you think of the payout, then you have some of the directional earnings drivers that you mentioned, Tampa Gas is up flat? I mean, is that -- do you think with the puts and takes the payout ratio, do you think in directionally then, it's -- it could probably be improving versus '23 or you potentially see going the other side?

[Scott Balfour, executive]

Yes. So 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 payout ratio is higher than where we would like it to be. It's higher than where our target is. But I'd 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 obviously, that will take some time, but we continue to be confident that our payout 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 certainly heard that input. Looking at dividend growth and the setting of dividend, of course, 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.

[Operator]

Next question will be from Mark Jarvi at CIBC Capital Markets.

[Mark Jarvi, analyst]

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

[Scott Balfour, executive]

Yes. I'm not going to get too fine tuned in terms of where we're at in the process, given the end of June is only 6 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 time frame between now and the end of June.

[Mark Jarvi, analyst]

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

[Gregory Blunden, executive]

Yes. It is, Mark. And well, it's 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 have seen some of our peers in the U.S. to 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.

[Mark Jarvi, analyst]

Okay. And then obviously, a lot of chatter about low growth, particularly in the U.S. data centers, reshoring all that kind of stuff. The thing with 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 in 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 in your service territory?

[Scott Balfour, executive]

Let me start, then Archie can come back. 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 1, but 2 utilities, of course, based in that state. 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 RT 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 creates incremental opportunity for growth for Tampa Electric. Archie, anything else you'd want to add to that?

[Archibald Collins, executive]

Well, I think you answered that well, Scott. I think Mark was asking the question because as a cost of service utility, there is 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 meaningfully grow revenues through data center growth and push down residential rate increases or commercial industrial rate increases, we're very, very interested in pursuing that on behalf of our customers.

[Mark Jarvi, analyst]

So if I just kind of summarize that, the view would be that the loan growth that you've seen in the last couple of years persists not inflecting higher yet than inflection bogos higher would be beyond the current rate case that you're foreseeing right now?

[Archibald Collins, executive]

Definitely.

[Operator]

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

[Patrick Kenny, analyst]

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's -- 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 time frame?

[Scott Balfour, executive]

Over to you, Archie.

[Archibald Collins, executive]

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 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 we've 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 2 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. Big Bend 4 would have to retire in the year 2039. Our current expectation, what's on our books. We're depreciating Big Bend 4 out till 2040. So it's a pretty nominal impact in 1 year shorter life on Big Bend 4, should we not elect to invest in the best available technology in 2039.

[Patrick Kenny, analyst]

Okay. That's great. And then maybe just for Greg, it looks like there's still $176 million remaining under your existing ATM program. Just wondering, in light of the mid-course 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.

[Gregory Blunden, executive]

Yes, Patrick. Yes, I mean, the midyear 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. So 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 -- a normal course business outside of asset sales, we had raised somewhere around $250 million to $300 million a year on our ATM program that 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.

[Operator]

Next question will be from Linda Ezergailis at TD Cowen.

[Linda Ezergailis, analyst]

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?

[Gregory Blunden, executive]

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 on credit metrics and EPS. I think it's premature to do that, 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.

[Linda Ezergailis, analyst]

Okay. And maybe you can help me understand one of the shifts in your outlook, Symantecs 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?

[Scott Balfour, executive]

Ryan, maybe you could respond to that?

[Ryan Shell, executive]

Yes, I'm happy to. Yes, we had higher costs 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 would see that increase not covered in revenues.

[Linda Ezergailis, analyst]

Okay. 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?

[Ryan Shell, executive]

Yes. I don't think so, Linda. I mean, we've had a little bit higher operating cost 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. We would have provided the outlook in our year-end results that would have contemplated that kind of run rate, we would maybe not at the same pace but continue to some degree over the balance of the year. And then, of course, from a consolidated basis on the corporate side, the mark-to-market and the hedge is effectively a timing difference.

[Linda Ezergailis, analyst]

Yes. Okay. 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?

[Ryan Shell, executive]

Yes. 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's actually -- it's been unseasonably cool which too early to tell, but we suspect that, that will probably be slightly constructive for load in the second quarter as most of us haven't turned the heat off in our hose.

[Operator]

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

[Dave Bezanson, executive]

Okay. 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.

[Operator]

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 that you please disconnect your lines.