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Operator: Good morning, ladies and gentlemen, and welcome to the Emera Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] This call is being recorded on Monday, February 23, 2026. I would now like to turn the conference call over to Dave Bezanson. Please go ahead.
David Bezanson: Thank you, Jenny, and thank you all for joining us this morning for Emera's Fourth Quarter 2025 Conference Call and Live Webcast. Emera's fourth 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; Jared Green, 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 reconciliations of historical non-GAAP measures to the closest GAAP financial measure. Unless otherwise specified, all financial information referenced is in Canadian dollars. And now I will turn the call over to Scott.
Scott Balfour: Thank you, Dave, and good morning, everyone. Before I begin, I want to introduce Jared Green. Today is Jared's first earnings call as CFO since joining us in December. We're excited about the value his expertise and leadership will bring going forward. Jared, welcome to Emera and your first earnings call. Emera is entering 2026 with strong momentum, building on record performance in 2025. Our 2025 results are evidence of both the strength of our strategy and the quality of our portfolio. Our team safely deployed a record $3.6 billion in capital investment, resulting in approximately 8% rate base growth over 2024. In addition, we delivered significant adjusted earnings growth, achieving more than $1 billion in annual adjusted net income for the first time in Emera's history. This performance is the outcome of disciplined customer-focused operational management and execution of our capital plan with investments centered on safely delivering the energy needs of our customers. As we enter 2026, we're confident in our ability to continue to deliver sustainable value for customers and shareholders alike. This morning, we reported annual adjusted earnings per share of $3.49, representing an increase of $0.55 or 19% over 2024. This performance significantly exceeds the upper end of our stated annual EPS -- adjusted EPS growth target of 5% to 7%. We also delivered a 19% increase to operating cash flow, further underscoring the strength of our financial results. By almost every measure, 2025 was our strongest year in the company's history. This exceptional performance positions us to continue making the critical investments required to strengthen our systems and ensure the safe, reliable delivery of energy that our customers depend on every day. Looking back in 2025, our continued financial and operational success highlights the effectiveness of our strategy, the quality of our premium portfolio of regulated utilities and the unwavering commitment of our highly skilled teams. I am deeply proud of our people and of what we continue to achieve together. Much of our success in 2025 can be attributed to strong performance at Tampa Electric. Emera Energy's record first quarter was also a contributor to our performance due to cold weather in the Northeast, which drove higher pricing and market volatility and where market conditions were strong again in the fourth quarter. In both instances, the team did an excellent job of responding to these favorable market conditions. We've made meaningful progress on disciplined operating and management cost management. By sharply -- by staying sharply focused on efficiency, we are helping offset upward pressure on customer bills while continuing to invest where it matters. Technology is a key enabler of this work. At Nova Scotia Power, more modern technologies, including AI tools are being deployed across a number of customer-facing and operational functions from the contact center to generation. This will make it easier for customers to do business with us while improving reliability through earlier detection of equipment issues, fewer unplanned outages and a safer, more efficient system. At Peoples Gas, we're similarly applying AI-enabled technology to improve crew dispatch efficiency, strengthen damage prevention and location practices and reduce outage risk. We're also optimizing upstream pipeline capacity through off-system sales with benefits flowing directly back to customers through a lower purchased gas adjustment. At Tampa Electric, drone and AI technology are being deployed to support inspections at solar sites. This approach reduces manual effort and inspection time, enhances safety and helps optimize asset performance. The result is a more efficient, cost-effective inspection process. In 2025, our operating companies safely deployed $3.6 billion of capital, representing the largest annual investment in Emera's history. These essential investments advance our reliability and resiliency initiatives and support the safe, reliable delivery of energy our customers expect. Importantly, we continue to carefully pace these investments, aligning project timing and execution to balance system needs with affordability impacts helping to ease rate pressure for customers while positioning our systems for long-term value. At Tampa Electric, the team installed an additional 150 megawatts of solar generation in 2025, bringing their total installed solar in service to 1,505 megawatts. These solar investments continue to reduce exposure to volatile fuel costs and deliver real savings for customers. The Tampa Electric team also made meaningful progress on grid resilience, undergrounding 77 miles of overhead distribution circuits in 2025 as part of its Storm Hardening Program. With more than 54% of the system now underground, the grid is better protected from severe weather and supporting improved reliability. 2025 also marked an important milestone for Tampa Electric with the opening of its new state-of-the-art energy control center. This facility brings teams together in a modern, centralized environment that strengthens day-to-day coordination and operational performance and which importantly is much more resilient to the impacts of severe weather, ensuring critical operational and system controls can be maintained. As part of its grid modernization and reliability improvement initiatives, Tampa Electric is also near complete in the deployment of a private LTE network, a progressive and industry-leading means to strengthen system-wide communications, enabling real-time connectivity to increasingly modern system devices to better support critical grid and field operations. At Peoples Gas, the 2025 capital program was supported by a steady residential and commercial growth, requiring continued reliability and distribution expansion investment across the state. Florida is still leading the nation in residential and commercial customer growth rates and signings for future residential business were strong in 2025 as builders and developers remain optimistic about the long-term growth outlook in the state. I'd also like to highlight that Peoples Gas was ranked #1 in the nation in J.D. Power's 2025 residential customer satisfaction study, a distinction that reflects the team's unwavering focus on customers and service excellence. We are extremely proud of this achievement and of the people who made it possible. At Nova Scotia Power, the team brought 250-megawatt 4-hour battery storage facilities into service, delivering immediate customer value by supporting the system during peak demand, including 2 cold snaps already this winter. A third battery facility is on track to come online this summer. The company also executed more than $200 million in the first year of its $1.3 billion 5-year Reliability Plan, consistent with the capital profile supported by all customer representatives as part of Nova Scotia Power's general rate application. In 2026, we plan to execute a record $4 billion of capital across our regulated utilities, part of our 5-year, $20 billion capital plan, supporting the 7% to 8% rate base growth outlined on our Q3 call. This plan is centered on essential investments that strengthen resiliency and reliability while meeting customers' evolving needs. More than half of our 5-year program is directed towards transmission, distribution and gas infrastructure expansion, enabling customer growth while enhancing system resilience through storm hardening, vegetation management and grid modernization. Notably, our capital plan does not reflect any data center-driven growth. While we do not have any data center signings to announce today, we remain actively engaged in discussions and are optimistic about future opportunities. From a regulatory perspective, 2025 delivered steady and constructive progress. We achieved a favorable rate case outcome at Peoples Gas. And in the fourth quarter, the Florida Commission approved an USD 88 million rate base adjustment for Tampa Electric for 2026, consistent with the company's 2024 rate case decision. These outcomes provide important regulatory clarity and reinforce our confidence in deploying the capital needed to support Florida's growth, strengthen system reliability and continue delivering stable long-term value for customers and shareholders. Supported by this strong growth environment and regulatory framework and through a disciplined focus on cost effectiveness and operational excellence, Tampa Electric continues to maintain customer rates that are below the national average. In Nova Scotia, the general rate application continues to progress. The hearing concluded in mid-January, and we are awaiting a final decision from the Nova Scotia Energy Board. This GRA supports critical reliability and infrastructure investments needed to serve homes, businesses and communities across the province while also carefully considering and balancing affordability pressures for customers. The consensus solution brought forward by Nova Scotia Power, which limits the average rate increases to an average of 2% per year across all customer classes over the 2026 to 2027 period is the result of extensive collaboration with all customer representatives and a shared focus on enabling essential investment while minimizing customer impacts. All parties agreed this application strikes the right balance. The consensus filing also reflects a proposal to securitize approximately $700 million of Nova Scotia Power's retiring thermal assets, providing significant customer savings. Together, the GRA and securitization demonstrate Nova Scotia Power's disciplined, thoughtful approach to managing affordability for customers. In keeping with the independent regulatory process in Nova Scotia, the Energy Board will now review the full record and set customer rates. We believe the evidentiary record is very strong, and we expect the decision will be rendered in the next month or 2. If approved as filed, the settlement provides Nova Scotia Power with a clear path to returning to its approved ROE band in 2026 and 2027. And finally, at New Mexico Gas, the sales process is proceeding. The hearing concluded in mid-November, and we're currently awaiting the hearing examiner's recommendation. We continue to expect a positive decision and a closing of the sale transaction in the first half of 2026. I'm also pleased to note that we're extending our average adjusted EPS growth target of 5% to 7% through 2030, while continuing to anchor the outlook to our 2024 results. Extending our growth rate out to 2030 shows our commitment to driving shareholder value over the long term and our confidence in the growth we continue to see in our company. Given that 2025 represented a step change for Emera's earnings with a 19% increase over 2024, we believe maintaining 2024 as the base year remains the most appropriate measure for the long-term growth of our company. With Tampa Electric now representing approximately 59% of our total operating company earnings, new rates in that business drive meaningful increases in our consolidated earnings as we experienced in 2025, but that we would not expect to replicate every year. By moving to a 5-year growth target from our previous 3-year outlook, we are providing greater long-term visibility into our adjusted earnings trajectory that is more closely aligned with our projected rate base growth of 7% to 8% through 2030. This longer horizon better reflects the multiyear nature of our capital planning and regulatory cycles and aligns our disclosure with evolving practices across the North American utility sector where the 5-year forecast periods are increasingly standard. Before handing the call over to Jared, I want to take a moment to acknowledge Peter Gregg, who will soon conclude his tenure as President and CEO of Nova Scotia Power and take on the new role of EVP of Strategy and Policy at Emera. On behalf of the entire team, I want to thank Peter for his leadership, integrity and commitment to serving customers in the province. And we extend a warm welcome to Vivek Sood, who will join us next week as the new President and CEO of Nova Scotia Power. And with that, I'll turn the call over to Jared to discuss our financial results.
Jared Green: Thank you, Scott, and thank you all for joining us this morning. I am glad to be here with you for my very first Emera's earning call. So turning over to our financial highlights. This morning, we reported full year 2025 adjusted earnings of $1.45 billion and adjusted earnings per share of $3.49 compared to $849 million and $2.94 per share in 2024. This reflects a 19% or $0.55 increase in adjusted earnings per share over 2024. In addition, we reported fourth quarter adjusted earnings of $167 million and adjusted earnings per share of $0.55 compared to $246 million and $0.84 in the fourth quarter of 2024. Let me spend a few minutes walking through the key drivers of our full year results. Starting with Tampa Electric, we saw a strong performance in 2025, driven by new rates and continued customer growth. That said, some of this benefit was offset by higher O&M, increased depreciation, interest expense and income tax of the growing business. Emera Energy also had a very strong year. Results were supported by favorable market conditions, and the team did an excellent job of capitalizing on those opportunities. At our gas utilities, earnings at New Mexico Gas increased, reflecting the first full year of new rates in the business. Earnings at Peoples Gas were flat year-over-year. So across the segment, results were partially offset by higher O&M and increased depreciation at both of the growing utilities. At our Canadian electric utilities, earnings were lower compared to last year. This was primarily due to higher O&M and depreciation driving lower earnings at Nova Scotia Power as well as the sale of our equity interest in the Labrador Island Link in early 2024. These impacts were partially offset by stronger residential and commercial sales, along with modestly favorable weather in Nova Scotia. Corporate costs were largely in line with 2024. We did see higher interest expense as a result of increased corporate debt outstanding, although this was partially offset by lower interest rates. During the year, a higher share count reduced adjusted earnings by $0.13. And finally, foreign exchange had a meaningful impact on the year. A weaker Canadian dollar in 2025 benefited earnings from our U.S. utilities. Looking ahead to 2026, based on our current hedge adjusted position, we expect that every $0.01 change in the Canadian U.S. dollar foreign exchange rate will have an approximate $0.02 impact on our adjusted earnings per share. Now turning over to the drivers of our fourth quarter results. Many of the factors were consistent with what we discussed for the full year, but there are a few items worth calling out specifically for the quarter. Starting with our Canadian -- our Canadian electric utilities, contributions were lower year-over-year. This was largely driven by higher O&M costs as well as a tax recovery that was recognized at Nova Scotia Power in the fourth quarter of last year. That tax item had a meaningful impact to the utilities adjusted earnings. At the corporate level, costs were higher than the fourth quarter of last year. This is primarily because Q4 2024 benefited from the recognition of a deferred tax asset that did not repeat itself to the same extent in 2025. Corporate results also reflected higher operating expenses and modestly higher interest expense year-over-year. For our gas and other electric utilities, Peoples Gas delivered a strong quarter with earnings up 11%, supported by higher off-system sales. This performance was more than offset by softer results at New Mexico Gas, driven by higher labor and benefit costs as well as lower earnings at BLPC. At Tampa Electric, quarter-over-quarter earnings were essentially flat. Higher O&M, increased depreciation and less favorable weather were largely offset by the benefit of new rates compared to the fourth quarter of last year. And finally, foreign exchange had a modest impact on the quarter. A slightly stronger Canadian dollar compared to Q4 2024 resulted in a modest reduction to adjusted earnings. Our robust earnings growth drove a 19% or $386 million year-over-year increase in operating cash flow after normalizing for fuel and storm deferrals. This momentum translated into strong key credit metrics, including a 130 basis point improvement in the Moody's CFO preworking capital to debt. This improvement reflects significant and meaningful progress towards target metrics. And pro forma the announced New Mexico gas sale, we would have exceeded Moody's 12% threshold. Additionally, our strong financial results contributed to an improved payout ratio of 83% in 2025. This puts us on track to reach our 80% goal by 2027. Before I hand it over to Scott for closing remarks, I want to briefly touch on 2026. With roughly USD 2 billion of the TECO acquisition-related call dates and maturities approaching midyear, we do expect to return to the hybrid and bond markets over the next few months. Debt market conditions remain constructive as we enter 2026, supporting our plan to refinance our June bond maturities. As we continue the process of refinancing the hybrids, which we started in Q4 2025, we'd like to highlight additional capacity in our capital structure for hybrids over and above the USD 1.2 billion issued in 2016. And now I'll hand things back to Scott for his closing remarks.
Scott Balfour: Thank you, Jared. As we reflect on 2025, I'm proud of the strong execution and discipline our teams demonstrated across the organization. That performance has created meaningful momentum as we enter 2026, supported by a clear strategy, a strong balance sheet trajectory and a portfolio of high-quality regulated assets. Looking ahead, our focus remains on executing our $20 billion capital plan, completing the New Mexico Gas transaction and continuing to work constructively with stakeholders, particularly in Nova Scotia to reliably deliver the energy our customers expect. This year also marks the 10th anniversary of our TECO acquisition, and it's notable that we have now invested more capital in our Florida utilities than the entirety of the original purchase price, a milestone that underscores how that transaction transformed Emera and created long-term value for customers and shareholders alike. With a solid foundation in place and strong visibility into our growth outlook, we are well positioned to continue delivering sustainable value for customers and shareholders in 2026 and beyond. With that, I'll be happy to answer your questions.
Operator: [Operator Instructions] And your first question is from Maurice Choy from RBC Capital Markets.
Maurice Choy: Just wanted to start with a question about the extension of growth rates. So obviously, you are doing this for EPS all the way through to the end of the decade. And I wonder whether or not you could indulge us in what your outlook is for the dividend? Obviously, you've got 1% to 2% through to 2027. Is that also something that you think the Board may consider extending? Or put differently, what do you see the payout ratio being at the end of the decade.
Jared Green: Maurice, as far as the dividend, we do like the 1% to 2% dividend growth that the organization is working within. We like seeing the trajectory of the payout ratio starting to decrease. If we were to look back a couple of years, we would have had a target of looking kind of 70%, 75% as a good payout ratio for the organization. We still have that belief. And as we do progress towards kind of that level, I think that you'll see that moving along.
Maurice Choy: And if you could just finish off with a question on the data center discussion that you had in your prepared remarks. Given your optimism of future data center opportunities arriving, what are some of the early stakeholder engagements that you're doing right now and also perhaps power generation requisitions that you think you might do in the very near term to facilitate some of this power load coming on?
Scott Balfour: Yes. Thanks for the question, Maurice. I'd say that Tampa Electric is involved in a number of discussions with potential data center developers and operators is in advanced system planning work with a number of them and continues to be optimistic that we're going to see some element of that kind of large load activity within its service territory. As it relates to generation, the current plans are similar to what we've shared before. We continue to invest in solar in the 150 megawatts to 200 megawatts a year range. As I said, we put in place 150 megawatts in '26 and expect another 170 megawatts in '27 -- sorry, I got myself advanced the year, 150 megawatts in '25 and another 170 megawatts in '26. And as you know, we are in the queue for 2 H-class machines from GE that would continue to provide generation support for the growing generation needs in Tampa Electric service territory, potentially including data center-driven load. So those would be the sort of the key aspects. And as I say, we're hoping that we'll see some of those things firm up as this year progresses.
Maurice Choy: Just as a quick follow-up. I think in your prepared remarks, you mentioned that the CapEx plan that you have in front of you doesn't materially include much by way of data center investments. When we think about this extension of 5% to 7% EPS growth, would you say that the data center growth when it does come, is incremental to this 5% to 7% EPS growth target? Or has it all been baked in already?
Scott Balfour: Well, no, I would not -- and it's not baked in already as to -- I mean, from our perspective, one of the biggest advantages and opportunities we see with large load additions into the Tampa service territory is the impact that it can have on broader customer affordability, helping to reduce rate pressure for other customers. And yes, depending on how this activity unfolds, it could drive the need for incremental investment in order to support those needs over time. And yes, that could contribute positively to earnings over time. But we have not assumed any of that within our current rate base forecast or within our continued 5% to 7% EPS guidance. And as I say, we see the primary benefits of attracting that kind of customer load is reducing rate pressure for customers.
Maurice Choy: And my congrats and welcome to Jared and also to Vivek and Peter for the upcoming transition.
Operator: Your next question is from Rob Hope from Scotiabank.
Robert Hope: Just regarding the extension of the EPS outlook out to 2030, how should we think about the growth range in the context of Tampa Electric returns and rate filings? Which could move you to the top end of the range? And what could move you to the bottom end of the range, especially given the fact that you do have a step-up in earnings when you do have new rates at Tampa?
Scott Balfour: Yes, Rob, thanks for the question. I think nothing new here in terms of the profile. I think for Tampa Electric, similar to most utilities, certainly those within our portfolio, generally, when new rates are secured as part of a regulatory application, often, we're able to earn in the upper half of the band if we're prudent in terms of our capital allocation and execution and the management of costs. And then as we get closer to the need for rates, typically every 2 to 3 years, depending on the capital investment profile, then, of course, the ROE profile starts to reduce. And we might see in the lower half of the range in the year of regulatory filing to secure new rates, which is really an indicator that the business requires those new rates to support the continued investment of capital. So that's the profile we expect with Tampa Electric. And of course, the other big driver is weather. And if we have favorable weather, then that can contribute positively. If we have less favorable weather, of course, that can drive ROE profiles lower a little bit. And generally, we've been pretty fortunate over the last few years, but you saw a bit of that impact in the fourth quarter, of course, with less favorable weather impacting results in a couple of our operations.
Robert Hope: The 2026 outlook has Nova Scotia Power earning at the lower end of the band, even with the partial year of new rates. If the regulatory or political situation in Nova Scotia worsens. Could we see you materially cut capital and reallocate those funds to Florida, which the market views as more favorable?
Scott Balfour: Yes, I'll pass it over to Peter in a second. But yes, there's always -- if there isn't regulatory support or the capital investment profile that's been put forward, then, of course, that capital won't be able to be invested. And so that could have an impact. But we continue to believe the evidentiary record and the capital profile that's been put forward and supported by all customers represents the right balance between the investments needed and the impact on affordability. But maybe I'll pass it over to Peter to take it from there.
Peter Gregg: Thanks, Scott. Rob. Yes, I'd just underline our confidence in what we put before the regulator and our reliance on the independent regulatory process as well. It's important to remember that we did work with all of the customer representatives to put together a consensus agreement. So we've got support from all of the customer representatives. As Scott said, we think the evidentiary record is strong. So we do have confidence that we'll get a good decision from our regulator.
Operator: Your next question is from Mark Jarvi from CIBC Capital Markets.
Mark Jarvi: Just sticking with Nova Scotia, just there was some pushback around some of the terms of securitization. Just wondering where those conversations are, anything you've provided and sort of feedback to the government and when we might get clarity on that?
Peter Gregg: Mark, it's Peter. So we continue to work with the province and are committed to continuing to work with the province to demonstrate the benefits to our customers through the proposed securitization. I guess all I can say is continue to address questions that come in from that, but confident that what we put forward is in the best interest of customers and look forward to what the Energy Board has to say on that as well.
Mark Jarvi: Can you remind us again in terms of what cash has been provided and when the next sort of payments were expected?
Scott Balfour: Sorry, not sure I follow your question, Rob (sic) [ Mark ] one more time.
Mark Jarvi: No. I just can't remember, was all the securitization paid upfront? Or was there installments and when sort of what the next planned installment if there was?
Scott Balfour: So there's been 2 securitizations that have been completed. So there was $117 million and then another $500 million that was done both relating to unrecovered fuel costs, the FAM. The proposed securitization as part of the general rate application is an additional $700 million that relates to the retiring thermal assets, the coal plants that are required to be retired by 2030 under provincial and federal legislation.
Mark Jarvi: And then just going back to the EPS guidance. Anything else you guys can share in terms of any key assumptions, whether it's expected ATM usage or Jared, you brought up the refinancing in 2026 in terms of how much more you issue this year at the holdco and the rates you assume there?
Jared Green: So I don't know if there's a whole lot of difference in color to give you on the financing plan on that side. Obviously, we do have the shelf prospectus is outstanding for the ATM, and we would be looking to utilize that throughout the year. Also remind on there that we do have the DRIP program. So we'd be accessing the equity through both of those mechanisms. As far as the upcoming financings, so June 15 is the date that we're coming up to that anniversary date. And so just the ability to get out a little bit ahead of that. And as we noted, we do have some incremental capacity as Emera has grown since the original size. And so being able to utilize that just in the hybrid market is something that it has obviously good credit components on it. And we are seeing, as I said before, a strong market in that side. So we're seeing the spreads and the cost there is something that we are liking. But going back, the overall financing plan for the $20 billion program over the 5-year period is very similar to what we have been saying over this last year.
Mark Jarvi: And then you made a comment, Jared, about you would have been above the Moody's threshold. Can you just kind of outline where that would have been?
Jared Green: So that would be with the pro forma of the closing of the New Mexico Gas. So we see the Moody's metric with the adjustments through there. We're at about 11.6% is what we ended the year at. And then we do see on an annualized basis, there's probably about 50 basis points of credit related to the closing of the New Mexico Gas. So that's where we would see that.
Operator: Your next question is from Ben Pham from BMO Capital Markets.
Benjamin Pham: A couple of questions on the New Mexico transaction. Can you give a context on the timing? Again, I know you had initially pushed it out from late last year to early this year because of the hearing change. And I'm curious what's driving the recent timing delay, if I can put it like that? And then also, is this decision then linked to the pending Blackstone application as well that hearings in early February?
Scott Balfour: Yes. Ben, so as I mentioned, the hearing is complete. We believe the hearing went well. And now we're just awaiting the decision or the recommendation from the hearing examiner, which could be any day now. And then following that, the commission would meet and if the commission then approves the transaction, we could close almost immediately right after that. So we don't really have a good line of sight as to the exact timing of the hearing examiner decision. But as I said, it could literally be any day now. And no, we don't believe that there's any sort of knock-on impacts or connection of timing of this to the TXNM transaction with Blackstone.
Benjamin Pham: And maybe going back a second on the NSPI at the sub-security situation last year weighed on your earnings to some extent. So where are you with that now in terms of remediation and any potential costs this year? Is that some of that built in the ROE expectation for NSPI for 2026?
Jared Green: Sorry, Ben, could you repeat that again? I didn't think I caught the front end of that.
Benjamin Pham: Yes, absolutely. You had the cybersecurity incident at NSPI impacted your earnings in that franchise. And my question is, is that the -- what's the remediation of that now? Is it pretty much all rectified? Is there impact to 2026 -- related to that at all?
Peter Gregg: I missed that. We still remain confident that insurance will cover the costs -- largely cover the cost of this incident. We did expense the amounts in 2025, as you've seen in our financials. We're making really good progress. One of the biggest impacts we saw was the impact to the -- what we call the head-end system that connects the meters, AMI meters to our billing engine. We've made very good progress on that. We've got over 85% of our meters now communicating with our billing system and we'll have 100% of those meters communicating by the end of next month. So we continue to make very good progress. I don't expect to see any significant impact on 2026.
Operator: Your next question is from John Mould from TD Cowen.
John Mould: Just wanted to get a little more color on your coal assets. And I appreciate -- sorry, in Nova Scotia, and I appreciate you don't have responsibility for system operation anymore, but I'm just trying to get a sense of their importance to provincial reliability and how you're thinking about their actual operations through 2030 in the context of the phaseout timeline and maybe some color on the importance they've had for reliability in some of the recent periods of high demand and stormy weather. I think that would be helpful.
Peter Gregg: Sure. John, it's Peter. I'll take a crack at that. So we do continue to make plans to have those coal assets shut down by 2030 as required. But we've seen electrification growth, and they do continue to contribute to reliability. The independent electricity system operator here in Nova Scotia has recently -- they just got the environmental assessment approved last week for 2 sites to put in some fast-acting gas generation. That's a really important step in terms of replacement energy and capacity for us to shut down those coal plants. We have had to make some tweaks to our plans. If you look at the most recent GRA, we've asked for the ability to spend up to $18 million to invest in our Lingan 2 generating assets because it continues to contribute meaningfully to reliability, especially during cold snaps. So that's $18 million to sort of keep it around until that 2030 phase out. So managing the system while new resources come online, but knowing that we have a legislative requirement to shut down the coal by 2030.
Scott Balfour: And the only thing I'd add to that, John, is what Peter spoke about is all part of a plan, executing an approach to achieving the 2030 goals that was announced by the province and supported by the utility that in order to close those coal plants, really 4 key components to be able to make that happen and achieve -- both the provincial and the federal legislation. Two of those things, the responsibility of Nova Scotia Power, which is the addition of 150 megawatts of batteries. And as mentioned, 2/3 of that is now in service. The other 1/3 will go in service this year. And then the other part that is Nova Scotia Power's responsibility is the tie line, the transmission line interconnection between Nova Scotia and New Brunswick. The independent system operator is managing the procurement of the additional renewable resources, wind resources and the gas generation that Peter mentioned. It's the combination of those 4 things that enables the achievement of those 2030 goals. And as I said, the portion that Nova Scotia Power is responsible for is in progress and well on hand and certainly no risk to be able to deliver on its commitments to achieve that 2030 goal.
John Mould: And then I'd just like to ask about potential new markets. You're on the list of eligible transmission bidders in Ontario's competitive transmission procurement. You do have underwater line development experience. Province is also running this PULSE Panel on its local distribution utilities. I'm just wondering if you could give us a sense of your appetite more broadly to deploy capital beyond your current markets and how Ontario might fit into that?
Scott Balfour: Yes. So we're certainly paying attention to opportunities in that market. And yes, the decision by the Province to look to procure transmission interconnection between Darlington and the Port Lands of Toronto, downtown Toronto by way of underwater high-voltage DC cable is definitely something that we know something about. Of course, having built and now operating the 2 longest subsea cables in North America and doing that, I think everyone would agree quite successfully. So that's certainly an opportunity we're paying attention to, and we'll await the procurement process that the Province decides upon and what's going on with the LDC market in Ontario, we pay attention to as well and looking forward to seeing what opportunities might get created in Ontario. But in the meantime, our focus continues principally to be on the execution of the organic growth that we've got in the portfolio, that $20 billion that I mentioned that continues to drive strong EPS growth guidance based upon that extension of that 3-year guidance to 5 years as we talked about.
Operator: Your next question is from Elias Jossen from JPMorgan.
Elias Jossen: Maybe just thinking about the overall generation mix shift down in Tampa. Can you guys just frame, one, how the discussions are evolving with regards to generation type? I know you have a lot of different options there. And then maybe secondly, just more broadly, what the outlook is for renewables in the state long term, recognizing that you continue to deploy a good mix shift of renewables annually.
Scott Balfour: Yes. Thanks for the question. So for Tampa Electric, pretty similar to other utilities in the state, natural gas is a really important part of the generation mix there. Over 70% of Tampa Electric's generation is natural gas. And as mentioned, we're looking at adding more of that in order to meet the growing needs and the growth in Tampa Electric service territory. But we also do continue to invest in solar and would expect to continue to do that for the next few years. Obviously, the impact of the One Big Beautiful Bill and the tax credits create some uncertainty in the long term. But certainly, over the profile of our capital investment -- 5-year capital investment forecast that's provided. You'll note there continues to be meaningful solar investment in Florida because we can continue to demonstrate that it saves customers money. And doing that on an economic basis continues to be an important part of how we meet the generation needs of customers in Tampa. So for the time being, continued investment in solar and some additional gas generation capacity that would be the primary generation sources for us in Tampa. The one remaining coal unit that we have is used very, very rarely, and the team is looking at what its retirement options might be in the near term.
Elias Jossen: And then maybe sticking with Tampa, I know there's been a lot of discussion about data center opportunities, but we've seen others in the state structure sort of large-load tariffs. Is there any color you can provide about the nature of the discussions you're having, whether that's regarding size of the opportunities or just overall structure, again, given the sort of the other contracting we've seen in the state?
Scott Balfour: Yes. So thank you for the question. And yes, one of our -- one of the other large investor-owned utilities in the state, as you know, had a large-load tariff supported through its settlement -- approved settlement of a recent rate case. And without surprise, the kind of conversations that we're having, the approach that we've taken to large-load tariff is completely aligned to that, which is really ensuring that these new large loads, data center-driven large loads fully pay for the cost, the incremental cost that is required to serve them and contribute some portion to the broader system in order to, as I mentioned before, help reduce the rate pressure on the socialized system on other customers. So that's very much aligned with our approach. And I'm sorry, I've now forgotten the second part of your question. Size, yes. Really, what we've been articulating over the last year or so is we've got the capacity to serve in 300-ish megawatts in the near term and the ability to grow that modestly over the years ahead. So we're not talking about the kind of massive multi-gigawatt type opportunities that some are discussing, but very incrementally helpful to all stakeholders to the extent that we're able to attract some of this large load into the Tampa service territory and the team is very focused on ensuring it's positioned to be able to meet that need.
Operator: [Operator Instructions] And your next question is from Patrick Kenny from National Bank.
Patrick Kenny: I guess just on Emera Energy with the performance in '25 here exceeding even the previously revised guidance. Just wondering what you're expecting to change or, I guess, normalize here over the near term in terms of market dynamics? Or should we be thinking about 2026 as having a similar upside potential?
Judy Steele: It's Judy. Yes. So we've kind of provided the guidance that we think 2026 will be in line with 2025's results. We're still not changing what we consider our normal guidance. Clearly, the weather in the last -- especially over the winter and then the first quarter of last year has been a little abnormal, which has been good for us, but we keep the general guidance the same at 15% to 30%. And when we see conditions that tell us that we should update people for a little bit of a change, we'll do that -- deal with it that way. So again, I will reiterate though that we do think that 2026 will be closer in line to 2025.
Patrick Kenny: And then I guess just stepping back and looking at the $20 billion capital plan, can you just remind us maybe where you might have certain flexibilities in terms of pushing certain projects out if cost inflation or FX rates move against you along the way? I'm just wondering how much flex you might have to be able to manage any affordability pressures that might pop up if need be?
Scott Balfour: Yes. Let me start, and then Jared can add on. I think, Patrick, generally, our thinking and approach traditionally has been that 7% to 8% rate base growth guidance is kind of the right place to be and to the extent that we see inflationary pressures on projects start to drive costs up or as you mentioned, foreign exchange impacts or tariffs or whatever the case may be, then generally, yes, we would be reprofiling a little bit because we do want to make sure that we're not putting too much pressure on rates for customers. So I would not be expecting that we'd be sort of seeing those pressures drive our 7% to 8% guidance higher, but rather really just creating more durability, sort of a longer profile to continue to see that kind of rate base growth. But maybe Jared can give a little more color.
Jared Green: No. Just adding on, Scott, for that. From a financial perspective, probably very similar to what we have seen in the $20 billion side. The scope of what goes within that utilities do have some ability to adjust that through time. But with, as Scott noted, customer affordability being a key factor in there, safety, reliability, customer growth are all legs to the stool that come into factor when you're looking at these investment plans. So we see -- we have pretty good comfort in that $20 billion forecast. And as Scott said, programs that might get pushed out a little add more to the durability of that growth program. Final color, I'll just put on that is we do feel quite confident in the durability of this 7% to 8% growth range into rate base. It's one where again you can factor in all 3 legs to that stool of customer affordability, safe, reliable and the sustainability that goes within it. So we do see a lot of good longevity to that growth as well.
Patrick Kenny: And I know it's a relatively small investment for NSPI, but maybe just on the New Brunswick, intertie -- would you have an update there on where things are at from an engineering or construction standpoint and how things are progressing towards the 2028 in-service date?
Peter Gregg: Yes. Patrick, it's Peter. As you know, we got approval for that in the fall. We've been doing land preparation forestry work through the winter. So doing the tree clearing. We expect to be doing foundation pours in the spring. So everything well on track for that '28 in-service date.
Operator: Thank you. There are no further questions at this time. Please proceed.
David Bezanson: Thank you all for your interest today. That wraps the call. Have a great day.
Operator: Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.