Emera (EMA) Q3 2026 Earnings Call Transcript

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DATE

Friday, Nov. 6, 2026

CALL PARTICIPANTS

• President and Chief Executive Officer - Scott Balfour
• Chief Financial Officer - Jared Green

TAKEAWAYS

• Adjusted EPS -- $0.85 for the quarter and $2.90 year-to-date, reflecting performance that management characterized as modestly below the previous year's figures.
• Adjusted Earnings -- $260 million, representing a 3% decrease compared to the third quarter of last year.
• Five-Year Capital Plan -- $21.5 billion through 2031, which is $1.1 billion or 5% higher than the previous plan shared by the company.
• Consolidated Rate Base Growth -- 7.5% to 8.5% through 2031, an increase from the previous target of 8%.
• Florida Capital Allocation -- 82% of the five-year capital plan is directed to Florida, driven by a growing economy and population.
• Florida Rate Base Growth -- Approximately 9% through 2031, reflecting significant investment in grid modernization and storm hardening.
• Operating Cash Flow -- Increased 7% year-to-date, excluding changes in working capital, as the company strengthens its balance sheet.
• Nova Scotia Securitization -- $1 billion in proposed financing for retired thermal assets, which is expected to save customers $265 million over 30 years.
• Peoples Gas Capital Investment -- $1 billion through 2031 to support residential and commercial growth in the Florida gas utility segment.
• Data Center Demand -- 1,300 megawatts of potential load studied in Florida, with each 100 megawatts representing approximately 2% growth in system demand.
• Auburndale Technology Center -- 350 megawatts of initial capacity expected under a contract signed by year-end, with long-term potential for 700 megawatts to 1,000 megawatts.
• Big Bend Unit 4 Modernization -- 720 megawatts of highly efficient generation capacity planned, with construction starting in 2027 and operation in 2032.
• Dividend Increase -- 1% annually, marking the 20th consecutive year of annual dividend growth.
• Equity Funding Target -- $600 million annually through DRIP and ATM programs, representing 10% to 15% of total capital requirements.
• Moody’s Credit Threshold -- 11% downgrade threshold, lowered from 12% following the sale of New Mexico gas assets and improved business risk profiles.
• Fitch Leverage Threshold -- 6.4x, revised from 6.0x reflecting the anticipated lower business risk of the combined company after the Canadian Utilities merger.
• Tampa Electric Utility Rates -- 25% below the national average following rate reductions of 12% in August and 1.4% in Jan. 2026.
• Cash Flow Funding Ratio -- 45% to 50% of the total capital program, sourced from internal operating cash flows.
• Hybrid Capital Contribution -- 5% to 7% of funding requirements, utilizing 50-50 debt-equity treatment from credit rating agencies.

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RISKS

• Balfour stated, "We need to support growth in the province, strengthen the system against increasingly severe weather and help advance the province's transition away from coal," while outlining infrastructure challenges in Nova Scotia.
• Green noted that results were partially offset by "lower earnings at New Mexico Gas, primarily due to higher operating expenses prior to the transaction closing mid-quarter."

SUMMARY

Emera Incorporated (NYSE:EMA) reported adjusted earnings of $260 million for the third quarter and introduced an expanded five-year capital investment program totaling $21.5 billion. Management stated that the company remains on track to achieve compound annual adjusted earnings per share growth within its 5% to 7% target range through 2030. The company reported significant focus on its proposed merger with Canadian Utilities, which is intended to consolidate growth platforms in Florida and Alberta. Management indicated that regulatory filings for the transaction are progressing toward a targeted close in the second half of 2027.

• CEO Balfour stated that the merger with Canadian Utilities positions the company to compete for more infrastructure investment by bringing two strong growth platforms together.
• Management indicated that Tampa Electric filed a large load tariff designed to ensure new customers pay the costs required to serve them while protecting existing rate payers.
• Balfour noted that Alberta is a primary driver of the Canadian economy due to industrial development, energy production, and strong population growth.
• The company reported that the Nova Scotia government is exploring performance-based regulation to link utility financial performance to operational outcomes.
• Management indicated that a decision from the Nova Scotia Energy Board regarding the $1 billion securitization application is expected by Dec. 9, 2026.
• The company announced that Chris Smith officially assumed the role of President and CEO of Nova Scotia Power during the quarter.

INDUSTRY GLOSSARY

• ATM: At-the-market equity program used to issue new shares at prevailing market prices.
• AUC: Alberta Utilities Commission, the regulatory body governing utilities in Alberta, Canada.
• DRIP: Dividend Reinvestment Plan, allowing shareholders to reinvest cash dividends into additional shares.
• FPSC: Florida Public Service Commission, the regulatory body governing utilities in Florida.
• PBR: Performance-Based Regulation, a framework where utility financial rewards are tied to meeting specific performance targets.
• Rate Base: The value of property and assets on which a regulated utility is permitted to earn a specified rate of return.
• Securitization: A financing method that uses low-cost bonds backed by a dedicated charge on customer bills to recover specific costs.

Full Conference Call Transcript

Operator: Good morning, ladies and gentlemen and welcome to the Emera Third Quarter 2026 Earnings Conference Call [Operator Instructions] I would now like to turn the conference call over to Dave Bezanson, please go ahead.

Dave Bezanson: Thank you, Jenny, and thank you all for joining us this morning for Emera's Third Quarter 2026 Conference Call and Live Webcast. Emera's third 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; 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 things over to Scott.

Scott Balfour: Thank you, Dave, and good morning, everyone. This morning, we reported third quarter adjusted earnings per share of $0.85, bringing year-to-date adjusted EPS to $2.90. That is modestly below last year's very strong performance. But importantly, we remain on track to deliver compound adjusted EPS growth above our 5% to 7% growth target range in 2026, and we remain committed to our longer-term EPS guidance through 2030. In the quarter, our Board of Directors approved a onetime -- a 1% dividend increase, marking our 20th consecutive year of annual increases.

That track record reflects the strength of our business, but also the discipline and expertise we've built in allocating capital, investing where we see the best opportunities and recycling capital when that makes sense. That approach has supported consistent earnings and cash flow growth and continue to create value for both customers and shareholders. In addition to our financial results today, we're introducing a 5-year $21.5 billion capital plan, approximately $1.1 billion or 5% higher than the plan we shared last year. This is Emera's stand-alone capital plan and does not include the proposed merger with Canadian Utilities announced last month.

Our $21.5 billion plan reflects the significant opportunities that we continue to see across our regulated utilities and our confidence in our ability to execute. We expect the plan to drive rate base growth of 7.5% to 8.5% through 2031, up from the 8% rate base growth in our previous plan. At its core, this is a plan focused on customers. About 3/4 of our investment plan is directed to reliability and resiliency, strengthening and modernizing the systems our customers depend on every day. We're also investing to support customer growth and in renewable generation that can help provide greater predictability in customer costs over the long term.

Florida continues to be the largest driver of our capital plan, where approximately 82% of our planned capital will be invested. We continue to see strong fundamentals in the state, including a strong and growing economy and population. Our investments are responding directly to that growth while strengthening and modernizing the grid, hardening the system against storms and ensuring we continue to deliver safe and reliable service. And as we invest, affordability remains front and center. We need to make the investments required to support growth and maintain safe and reliable systems while being thoughtful about what these investments mean for customer bills.

That means prioritizing the investments that matter most, pacing them appropriately and delivering them as efficiently as we can. Tampa Electric is a good example of this approach in action. Since we acquired the business in 2016, we've invested to serve a growing customer base and strengthen the system. At the same time, customer bill increases have remained below the national average. That doesn't happen by accident. It reflects disciplined investment choices and execution and a continued focus on finding ways to deliver more value for customers.

In fact, the combination of Tampa Electric's recent rate reduction of approximately 12% in August, combined with a further 1.4% reduction in January with benefit of lower-than-expected fuel costs, Tampa Electric's rates are now approximately 25% below the national average. The circumstances are different in Nova Scotia, but our focus on affordability is the same. We need to support growth in the province, strengthen the system against increasingly severe weather and help advance the province's transition away from coal. And as we do that, we continue to look for ways to reduce the cost impact to customers.

To that end, we're working to securitize approximately $1 billion of costs, including those associated with certain thermal assets being retired as part of the energy transition. By accessing lower-cost financing, if approved by the Nova Scotia Energy Board, we expect securitization to save customers approximately $265 million over the 30-year repayment period. These are different markets with different needs, but the approach is consistent, invest where it's needed, manage costs carefully and find innovative ways to deliver better outcomes for customers. Our updated capital plan gives us strong visibility into growth across the business. This new plan results in 7.5% to 8.5% consolidated rate base growth through 2031, with our Florida utilities expected to deliver closer to 9%.

We have a strong track record of delivering. This year alone, we're on pace to invest approximately $4 billion across the business, the largest annual capital plan in our history. We're excited about the investments we're making for the benefit of our customers across our portfolio of companies. At Tampa Electric, in addition to significant investments to strengthen the grid, the modernization of Big Bend Unit 4 will utilize -- will use existing infrastructure to add approximately 720 megawatts of highly efficient generation capacity. It's a practical, cost-effective way to add capacity and improve reliability as demand continues to grow. Construction is expected to begin in 2027 with the facility targeted to be fully operational in 2032.

At Peoples Gas, we plan to invest approximately $1 billion to support customer growth, building the infrastructure needed to serve expanding residential and commercial opportunities across Florida through 2031. In Nova Scotia, we're making important reliability investments to prepare the grid for the province's clean energy transition. That includes the deployment of grid stabilizing synchronous condensers at 5 sites across the province, which will enable and critically support the significant new wind generation in service and plan in the province. None of these projects are, of course, possible without our people. Across Emera, our teams are planning, designing, building, and operating critical infrastructure every day safely and reliably.

Their expertise and execution are what gives us the confidence to take on a capital program of this scale. We're also making progress on several important regulatory matters across our business and seeing important economic growth drivers. In Florida, we continue to see significant momentum around data center demand. Tampa Electric filed its proposed large load tariff on September 30, designed to accommodate up to 1,000 megawatts of large load demand, along with a second proposed formula rate for demand beyond that initial 1,000 megawatts. Importantly, the framework is designed to ensure that these new customers pay the costs required to serve them while protecting existing customers.

The filing has been very well received by stakeholders to date, and we expect a decision early next year. At the same time, the data center pipeline continues to advance. Tampa Electric has now completed complex system impact studies for approximately 1,300 megawatts of potential demand with commercial discussions across these projects at various stages. We're encouraged by that progress. And with a number of other data center discussions underway, Tampa Electric is working towards signing a contract by year-end for the first 350 megawatts or the Auburndale Technology Center that was announced by Hillwood Corporation earlier this week. To put these opportunities into perspective, each additional 100 megawatts represents approximately 2% growth in system demand.

We're also seeing opportunities emerge in Nova Scotia. The recently announced potential data center development in Nova Scotia is a good example. It's still early, but the interest itself is encouraging and speaks to the potential for new economic growth in the province. While the ultimate impact to customers and to the utility will depend upon how the tariff is developed and approved by the regulator, which certainly will include ensuring these large load customers pay their own way, we believe this growth has the potential for it to deliver meaningful benefit to customers. Just as importantly, large load customers can help support investments in the system and spread costs across a broader customer base.

Our focus is on supporting the province in its efforts to grow and attract new investments by investing where necessary to provide the reliable energy projects like this proposed data center will need to succeed in the province. And finally, as I mentioned earlier, Nova Scotia Power filed its application on October 9 for a financing order to securitize approximately $1 billion of costs. The Nova Scotia Energy Board has 60 days from filing on October 9 to issue its decision. I'd like to take a moment to talk about the proposed merger between Emera and Canadian Utilities that was announced a month ago. At its core, this combination is about positioning us for the growth ahead.

Across North America, demand for energy is increasing and significant investment will be needed to strengthen and modernize infrastructure, improve resilience and support economic development while keeping affordability front and center for customers. These investments are becoming increasingly large and complex. Together, Emera and Canadian Utilities will be better positioned to meet that opportunity. We're bringing together 2 best-in-class teams with strong operating capabilities and a track record of investing and executing at scale. We'll be able to learn from each other, bring our combined expertise to a broader set of opportunities and have greater financial and operating capacity to invest in growth.

The combination is also expected to strengthen our financial position and support a stronger credit profile and lower cost of capital. All of that positions the combined company to compete for and deliver more of the infrastructure investment that we see ahead. One of the things that makes this combination so compelling is the strength of our 2 largest jurisdictions, Florida and Alberta. We've talked for years about what makes Florida such an attractive place to invest, strong population, and economic growth, constructive regulation, and significant infrastructure needs. Well, we see many of those same fundamentals in Alberta.

It has a constructive regulatory environment, equally strong economic growth, stronger population growth and significant investment opportunity ahead to support the province's expanding energy and industrial economy. This isn't about creating one growth story for another. It's about bringing 2 very strong growth platforms together, giving the combined company significant exposure to 2 of the most attractive utility growth markets in North America. Alberta is central to Canada's economy and particularly its energy future. Growth in energy production, industrial development, LNG, petrochemicals, large load customers and broader infrastructure modernization is creating significant demand for the utility infrastructure that supports that growth. When we acquired TECO in 2016, we saw strong fundamentals and significant opportunity for long-term investment.

Since then, we've invested alongside Florida's growth, strengthened the business and created meaningful value for customers and shareholders. We see a similar opportunity in bringing Canadian Utilities and Emera together, different businesses and different markets, but the same fundamental opportunity, strong jurisdictions, growing customer needs and the ability to invest and execute with discipline over the longer term. In terms of next steps, we expect the transaction to close in Q3 or Q4 2027 or earlier, given the strong progress and positive response we've seen since the deal was announced. The application for the most significant regulatory filing with the Alberta Utilities Commission was submitted on October 27, with a decision requested by the end of April 2027.

All additional regulatory requirements have either been filed already or expected to be submitted by the end of 2026. A joint information circular is expected late this year or in early January, followed by a special meeting of each company's shareholders expected to be held in early 2027. We're very pleased with the progress made to date and excited to see this transformative transaction advance. And with that, I'll turn it over to Jared.

Jared Green: Thank you, Scott, and thank you to all of you for joining us here. This morning, we reported year-to-date adjusted earnings of $887 million, up $9 million over last year. And as Scott noted, adjusted earnings per share of $2.90. Third quarter adjusted earnings were $260 million or $0.85 per share, representing a modest 3% decrease year-over-year. Earnings through the first 9 months of the year also contributed to a 7% increase in operating cash flows, excluding working capital, compared to the same period last year. We continue to make meaningful progress in strengthening our credit profile.

Moody's recently lowered our downgrade threshold from 12% to 11%, reflecting their view of the better business risk profile post the New Mexico gas sale and on a pro forma basis, once we close the Canadian Utilities transaction. We remain on track to achieve a 12% CFO to debt metric by the end of the year as a result of the progress we've made growing cash flow, reducing leverage, and strengthening our balance sheet. Fitch has indicated that following the close of the Canadian Utilities transaction, they will revise their leverage threshold from 6.0 to 6.4x, reflecting its view of the combined company's lower business risk.

Taken together, these developments reinforce the progress we've made and continue to make on the balance sheet and give us greater financial flexibility as we execute our growth plans. Turning to the highlights of our individual operating companies' third quarter results. At Tampa Electric, earnings were largely in line with the third quarter of last year. Higher revenues from new base rates and customer growth were offset by the impact of the FPSC approved settlement for changes to depreciation rates at Bayside Power Station, along with the fuel cost recovery reduction. The revised depreciation rates are expected to reduce annual depreciation expense by approximately USD 20 million.

As a part of the settlement agreement, Tampa Electric agreed to reduce 2026 fuel cost recovery by USD 10 million, which was recognized in Q3 of 2026. Peoples Gas delivered strong results in the third quarter, reflecting new rates that took effect on January 1, favorable market conditions that drove higher off-system sales. These gains were partially offset by lower earnings at New Mexico Gas, primarily due to higher operating expenses prior to the transaction closing mid-quarter. In the Canadian Electric segment, Nova Scotia Power delivered higher earnings, reflecting new base rates that went into effect earlier this year as well as higher residential sales volumes and lower interest expenses. This was partially offset by higher operating costs.

From a financing perspective, Q3 was a quieter quarter with much of our financing needs wrapped up in the first half of the year. The focus for the rest of 2026 will be on the securitization process in Nova Scotia Power and a financing at Tampa Electric to support their ongoing capital plan investment needs. As Scott mentioned, we are still on track for a solid year and to achieve our compound annual EPS growth of 5% to 7% through 2030. We will be rolling forward our EPS guidance when we release our annual results on the Q4 call in February.

Also, as Scott mentioned earlier, our updated 5-year capital plan includes more than $1 billion of incremental investment compared to the plan we shared last year. Importantly, despite the increase in capital, our funding strategy remains largely unchanged. Cash flow from operations will continue to be our largest source of funding, and we expect it to fund 45% to 50% of our capital requirements over the planning period. Our operating companies will continue to access debt markets consistent with their approved regulatory capital structures, representing approximately 30% to 35% of our total funding requirements. Equity will continue to play a small role in our funding plan.

We expect our DRIP and ATM programs to fund 10% to 15% of capital requirements, averaging approximately $600 million annually with issuances weighted towards the 2027 through 2029 period as capital investment increases. We are no longer forecasting proceeds from asset sales in this plan as once the securitization process is complete by the end of 2026, we will have completed this component of our funding strategy. We also continue to see value in hybrid capital as part of our balanced funding strategy. Following successful hybrid issuances in 2025 and 2026, we expect hybrids to fund 5% to 7% of our requirements, reflecting their efficient 50-50 debt equity treatment from the rating agencies.

Overall, we have a balanced and diversified funding plan that supports our increased capital investment while maintaining our focus on balance sheet strength and credit quality. With that, I'll turn the call back over to Scott for closing remarks.

Scott Balfour: Thank you, Jared. And before closing, I want to take a moment to thank Vivek Sood for his leadership of NSP, Nova Scotia Power over the past year and to recognize Chris Smith, who officially stepped into the role of President and CEO of Nova Scotia Power earlier this week. Chris knows the business extremely well, having been part of the Nova Scotia Power leadership team since 2017, and he brings deep utility and energy experience to the role. I have a great deal of confidence in Chris and the broader leadership team as they continue the important work underway to strengthen reliability, manage costs for customers and position the business for the future.

As we look ahead, we're in a strong position. We're delivering strong results, executing a $21.5 billion capital plan with clear visibility to long-term growth and continuing to invest in the needs of customers. We believe the combination with Canadian Utilities positions us even better for that opportunity ahead. It brings together 2 strong businesses anchored in Florida and Alberta with the scale, expertise and financial strength to invest and grow over the long term. Most importantly, we have experienced teams with a proven ability to execute. That gives us confidence in our ability to continue delivering for customers and creating long-term value for our shareholders. Thank you. And we'll now open the call for questions.

Operator: [Operator Instructions] And your first question is from Maurice Choy from RBC Capital Markets.

Maurice Choy: Scott, I appreciate your comments and sharing the similar elements in Alberta and Florida. Obviously, the market is well versed in terms of the attractiveness of Florida. So I wonder if you could just dive a little bit deeper into this and share where you think there are elements where Alberta may perhaps be superior to Florida.

Scott Balfour: Yes. Thanks for the question, Maurice. And it's interesting. And we thought it was important to share that sort of side-by-side contrast of the 2 jurisdictions. And you're right, there is a lot of similarities. Of course, I think the unique advantage in Alberta, and you heard me say it in my comments, that I mean, it really is the driver in many ways of the economy in Canada, particularly today with an energy-focused agenda that is obviously important to the national agenda, but certainly to the provincial one. And so we're just seeing a significant amount of industrial-driven growth in that, of course, connected to the oil and gas economy there.

But that growth and the infrastructure that is needed to support it, some of which falls directly into the line of sight and opportunity for Canadian utilities with its important gas and electric businesses there. But because of that growth, we're also seeing, as you saw, a very strong population growth, which is also driving and expected to continue to drive strong growth from a residential perspective for those utilities.

So we really are quite excited about this and the opportunity for Canadian Utilities to be very additive to the strong growth profile that we've enjoyed and continue to demonstrate and look forward to continue to supporting and investing in the growth in Florida, but now as I said in the remarks, now we can add to that with a growth opportunity -- significant growth opportunity with the business in this strong economy in Alberta.

Maurice Choy: And my second question is a two-pronged question, which thematically is meant to surround the theme about de-risking. In your CapEx plan, CapEx obviously goes up by about 5%, I think. But the percentage in terms of the funding from DRIP and ATM has gone to $600 million a year versus $400 million in the past plan. So just curious what is driving that? And -- another element of de-risking here is the PBR framework that's been proposed in Nova Scotia. Your thoughts on whether or not that helps de-risk you, what do you think is driving that suggestion from the government?

Scott Balfour: Sure. So let me start with the second question, and then Jared can get back to your first one. So I think PBR is being looked at by the province as an opportunity to connect performance of the utility to its financial performance to connect operating performance and financial performance. And it was -- there's many PBR jurisdictions that were just fine, including, frankly, in Alberta and other places. So the regulator is now going to go through and review this. That doesn't mean that the province is committed to putting this into place, but they're committed to understanding it better and seeing what it would look like.

And importantly, within the legislation that the regulator is now responding to, it recognizes and to anchor this point, it really is important. It recognizes the importance of the utility earning a fair return and the financial health of the utility, which, of course, is fundamental within regulatory compacts, including the one in Nova Scotia. And that latter aspect has admittedly been a little more challenging for Nova Scotia Power over the last few years.

So we're looking forward to working with the regulator and the intervenors to explore PBR to see as to whether that does create a better framework moving forward to manage the cost aspects of energy for its customers, which, of course, is a challenge in Nova Scotia as much as anywhere, but also one that provides the opportunity for the utility to maintain its financial health and earn a fair return on its capital. Jared, do you want to address the first question?

Jared Green: Sounds good, Scott. And so for the first question, Maurice, probably the most direct largest piece of that would be this plan doesn't have any asset sales in it. So while the percentage for equity being slightly higher, we are not having almost equity anyways from the asset sales going out. So as you did note, the increase in the dollar amount of the equity is funding a portion of this incremental growth. But then with the plan, we don't require asset sales as we're going forward.

And -- the last part I'd say for here is, like always, we do have great respect for our investment-grade ratings and the strength of the ratios and the maintenance of those ratios is also a very core fundament to the strategy as we look at it.

Operator: Your next question is from John Mould from TD Cowen.

John Mould: Maybe I'd like to start with the updated rate base growth, 7.5% to 8.5% under the new capital plan from 7% to 8% under last years. What would need to happen for you to get to the high end of that new rate base growth range? And I appreciate we're not updating EPS guidance today. We can wait until Q4 for that. But how should we think philosophically about the conversion of incremental rate base growth into EPS growth?

Scott Balfour: Jared?

Jared Green: Thank you, Scott. So as we look within that range, and obviously, we're rolling this range out for the upcoming 5-year period. So to be into the higher end of that range is a lot around the execution of the projects as well and being able to design, deliver them on time and on budget, which is a track record that Emera is very good at and has a very long path towards that. The kind of the second part of being able to transition the rate base growth into EPS growth, that is also something that we put a lot of care and attention into.

And the pace of how we execute and grow our programs is an important thing of rolling your growth into EPS. The key on this is your regulatory strategies and your success in front of the regulators. So your ability to show the value to customers, your ability to reduce the potential regulatory lags that can come from these investments as you're putting them forward to your regulators. And I'd say, again on this, John, we have very good track records of our teams being able to work with our regulators and with our customers to be able to kind of have as close of a band between your rate base growth and your EPS growth.

I think that's something that we've been very proud of through time as well of our ability to keep a pretty tight band on that. So as we kind of wrap on there, a lot of it is on execution to be able to move into the higher end and transition that into earnings.

Scott Balfour: I guess I could add to that, John, sorry, is we're in an environment right now. I mean, obviously, we're not increasing our growth guidance or rate base growth guidance lightly, but we're in an environment where there's a need to invest more. And so we're -- really what we're doing is trying to make sure that we're managing the pace of that investment in a way that isn't challenging affordability. Frankly, if anything, the investment opportunities are outpacing that kind of growth, at least in the short term.

And so that decision to guide our rate base growth up a little bit is reflecting -- trying to find that balance between addressing the significant investment opportunity with navigating the rate impacts for customers.

John Mould: That's a good dovetail. I'm going to try a 2-part question here on large loads. Firstly, how much, if any, incremental investment associated with potential large loads? Have you got in that plan today? And how should we think about what the range of incremental investment could be if you do secure some load that's -- and I know this is a bit nebulous, but consistent with what the opportunity set you're seeing right now? And then secondly, on the 350-megawatt Auburndale data center or initial 300 megawatts, I should say, any more insights you could provide on how large that opportunity could potentially be?

And how the timing of a contract there potentially dovetails with the large load process that you've got going in Florida?

Scott Balfour: Yes. So maybe, John, for that, maybe, Jared, why don't you start with the first part of that question, and then Archie can round that out and answer the second part of the question.

Jared Green: For the announcement for the 350 megawatts that came out earlier this week, there's actually a fairly minimal incremental capital investment required to be able to deliver to that load level. This is -- we're looking at -- it's in the tens of millions of dollars for the infrastructure tie-ins for it. So that's one that can be delivered kind of very smoothly and efficiently. For loads above 350, it would really depend on the circumstances of the customer and the timing for what that -- those load requirements would be. But as those do come to a little bit more clarity, then we could look at those in a little more detail.

Scott Balfour: Archie, do you want to add to that and answer the second part of John's question?

Archibald Collins: Yes, sure. I can do that. So to the first half of the question, so looking just exclusively at Tampa Electric's 5-year capital plan embedded within our capital plan was the contemplation that we would be serving 350 megawatts of large load. And we simply -- that's all that's reflected in the 5-year capital plan because that's sort of what's right in front of us at this 10 seconds and what was announced this week. It's not to say there isn't more in the hopper, but we just don't want to count our chickens before they hatch. I think the second half of your question was what's the timing of the contract.

First of all, this project that the Hillwood Corporation announced publicly on Wednesday, this is actually a project that we've been quietly working on in Pope County for about 10 months now. So it's not as though this is just a concept. This is -- the buildings are built. We've already made all of the distribution upgrades, substation upgrades, and we're working on the transmission interconnection now. So we're well along on this project. And all of the earthworks are happening around that site as well. So the contract with Hillwood for that first 350 megawatts to serve is expected to be executed before the end of the year.

I think the other part of your question, John, is what is the -- at that Auburndale Technology Center, what is the full capability of what could be delivered there? We're very confident that we could deliver up to 700 megawatts -- we're in discussions as to whether or not it could go to 1,000, but that's a bit premature at this point. But this is an area that is zoned industrial. It is a technology and innovation hub. It's adjacent to Florida Polytech Technology school. So it's an engineering school. And so far, the message has landed really well with the community. We haven't seen any pushback yet on Hillwood's announcement, which is positive.

Operator: Your next question is from Hannah Velasquez from JPMorgan.

Hannah Velásquez: I just wanted to double tap back on to the equity component of your revised capital plan. I understand a good portion of that is replacing the asset sales that you no longer will need or use the form of proceeds. But just when we think about the composition of that, the $600 million to $1 billion of incremental compared to the $1.5 billion increase in CapEx, it just is meaningfully higher than your regulated structure and everyone else in your comp set. How do you think about that? And then I have a second question on the impact to your EPS CAGR, but I'll save that.

Jared Green: So the mix on those with the incremental $1.1 billion to the capital plan as we go forward, we don't color code kind of any individual financing with any increase. I'm looking at the overall financing plan for the entirety of the $21.5 billion capital program. And when we do incorporate those 2 pieces together and as we noted for here, we don't have any asset sales. So the combination of the DRIP and the ATM are the equity funding component for that incremental $21.5 billion program. We do also have that built to be able to look to, as I noted before, have strength within our credit metrics.

So we have talked about wanting to have our CFO to debt ratio for Moody's in the 12s and having some cushion room and strength within that for flexibility of the business as we move forward. That's one of the key tenets, and we look at the kind of the balance of the mix of the overall capital plan. So I look at it from the entirety of the plan and that the $600 million average. So it's $600 million kind of average a year for the 5-year period is what we have for the program.

Hannah Velásquez: And just as a follow-up there on the impact to your EPS CAGR. I don't want to front-load the update in 4Q, but just on my quick back of the envelope math, it would suggest that you would land towards the lower end of the 5% to 7% CAGR. Is that the right way to think about it? Or I don't know if I'm being too punitive, but just how do we think about the impact from equity dilution despite the rate base CAGR increase?

Jared Green: So Hannah, for that one, I'd say it'd be too early for us to be speaking to the earnings forecast that's coming through this plan. As I noted, that's one that we will be updating the forecast as we do come out of Q4, again, with an appropriate starting point and the earnings going forward. So we'll have that update for you at our next quarterly call.

Operator: Your next question is from Michael Lonegan from Barclays.

Michael Lonegan: So since we're waiting on the Nova Scotia Energy Board's decision on securitization, just wondering, are you in the meantime, keeping the thermal assets in your updated rate base growth forecast today until that is approved? And if so, can you say what's assumed in 2031? Just trying to get a sense of the rate base CAGR if those assets were out.

Jared Green: So Michael, so the forecast that we have in the rate base growth, that assumes that we have completed the securitization. So that would be -- have the thermal assets excluded from the rate base. So we're feeling very good about that process in calendar 2026.

Michael Lonegan: And then assuming the merger is approved, Moody's would lower your downgrade threshold, you'd have some more cushion and capacity to pay higher dividends. Just wondering if you would consider accelerating your dividend growth outlook.

Jared Green: Michael, on that one, actually. Sorry, Scott. So Michael, first off, I'd say for Moody's, we actually are already moved to the 11% downgrade threshold for Moody's. So I wanted to have that as the opening. And Scott, I'll pass over to you for the second part.

Scott Balfour: Yes. And you would find the answer too, of course, Jared. But Jared and I are in different rooms. That's one of the mix there. So yes, I think -- Michael, thank you for your question. But I think for the time being, we continue to be comfortable with the dividend growth rate that we've got. Of course, we've done that for a reason to bring the dividend payout ratio down. We've made some great progress on that, but it's too soon to be thinking about changing the dividend growth rate. We remain comfortable with that current range as evidenced, of course, by the decision and announcement last month to increase the dividend again this year within that range.

Operator: Your next question is from Patrick Kenny from National Bank Capital Markets.

Patrick Kenny: Just back on the Canadian Utilities platform. I know first things first in terms of closing the deal, but I just wanted to touch on some of the political developments since you announced the transaction. So we have a change in government in BC, U.S. midterms, the results there perhaps putting the data center spotlight on Alberta. So just curious, Scott, to get your thoughts on how this perhaps accelerated industrial activity up in Northern BC or within intra-Alberta, whether it be expanding interties or bringing forward new gas supply, which opportunities in Western Canada might have moved in your mind from more of the longer-term bucket to perhaps now thinking more of a near-term opportunity set?

Scott Balfour: Yes, it's really good framing, Patrick. And while it's too soon to have a clear view as to at a project level as to what we might see. But I think your premise is exactly right, is that what we've seen since announcement is only reinforcing the opportunity that we see and the political outcomes north and south of the border, I think, overall have actually been quite encouraging for our portfolio and our growth opportunities ahead. And that certainly includes the future that we think is really exciting in Alberta.

Patrick Kenny: And I guess if those core T&D opportunities do -- are brought forward a little bit, maybe back to Jared's comments on asset sales, Scott, you can jump in here, too. But just wondering if you spent any more time thinking about some of the non-regulated assets within Canadian Utilities, either the power or the energy infrastructure assets, if you still view these as core to the pro forma platform or if there's been any change there in your thinking?

Scott Balfour: Yes, fair question. And no, I don't think there's been any change. Of course, those are assets that we're familiar with as class of assets. And -- but it's too soon to be sort of thinking about the portfolio from the perspective of where we'll sort of look to put foot on the accelerator and where our key focus will be. But the underlying nature of the asset, the strategy that Bob has been leading and driving for growth in Alberta, we're completely comfortable with that, of course, because the transaction announcement that we've made, and we'll have opportunities to -- once we get to closing and beyond to think about some of those things.

They have an unregulated portion of their portfolio. Of course, we have Emera Energy as well. And there's skills and experience and market positioning and relationships in both of those business. And we'll look to see how we can optimize that, how we can continue to support growth through both of those businesses. So I think that would be more of the perspective we're looking at, at the moment.

Patrick Kenny: And then last one for me, if I could. And I know we'll get more detail down in Tampa in a couple of weeks. But just given the general narrative or the stigma, I guess, that's out there regarding data centers and their impact on customer affordability. Just wondering if you could unpack your comments a little bit more with respect to Tampa Electric's ability to absorb the load, integrate any incremental generation required and create that win-win opportunity for both data center and residential customers?

Scott Balfour: Yes. So maybe I'll start and then Archie can add on. I mean I think what's really important and maybe there's times we're coming late to a party for lack of a better word in terms of a lack of -- we haven't really been engaged in sort of the data center activity before the time line that Archie laid out. We, of course, have been -- these have been things that have been on the radar for and in motion for a number of utilities across the country for a long time.

But I think there's the opportunity for Hillwood certainly has been demonstrating this and Archie and the team at Tampa Electric also have been made very clear that existing customers come first. And that if there's going to be data center type large load that is part of the customer base in Tampa, they have to pay their own way. They also have to deal with the other issues that are important to communities around minimizing any impact to water, ensuring that there's no noise levels that are above certain levels.

And if we get it all right, it is actually a rate profile that actually helps contribute to the to the system and helps to reduce the rate pressure for the balance of customers and certainly not the opposite. And I think that's reflective in the filing that Tampa Electric made that Archie and I mentioned, all those things as it relates to existing customers first, all the capital and cost of serving a new large load customer has to be paid for by that new large load customer and a tariff design that hopefully allows for a contribution to the broader system cost that helps to reduce rate pressure for customers.

And I think if you get all those things right, plus those other things around water and noise that are equally important, like Hillwood seems to have done and like Archie and the team at Tampa Electric, have insured is within their large load filing, then I think you create the conditions that this is a win-win for the new customer and for existing customers. But Archie, happy to let you add on to that and round anything out.

Archibald Collins: Well, I would just say -- so you used the word stigma. I think that so much of the stigma, if I use that word as well, has just simply been rooted in the fact that we've been in an election cycle here in the U.S. And so a narrative was propagated, and it was difficult in the midst of the midterm elections for a counter narrative to ever take root. I think now that we're through the election cycle, we have some certainty and certainly here in Florida, where we -- the governor elect campaigned on a platform of pro-growth, pro-infrastructure investment, done right.

And in fact, as it relates to data centers, he, Governor Byron Donalds repeatedly would have said, as it relates to data centers, there's a right way and there's a wrong way to invest in these important foundational investments. And in Florida, we're only going to do them the right way. When we designed our large load tariff, which, as was shared earlier, we filed with the FPSC on the 30th of September, we designed that in a manner which was -- certainly was consistent with what the law requires in Florida, but it was rooted in affordability. We were very intentional to try to strike that balance between supporting economic development, but protecting our existing group of customers.

And in fact, trying to design it in a manner that as we grow data center revenue, it's putting downward pressure on electricity rates for the balance of our customers. So I agree with you, there has been a stigma, but I think that now that we're through the election cycle, I think you're going to start to see that narrative change a bit. And I am very confident in the approach that we've taken at Tampa Electric that we are -- this is data centers done right.

And I think it's part of the reason why the large load tariff that we filed on the 30th of September has been so well received by the consumer parties, by the media, by elected officials because they can see how intentionally we design that to find that balance.

Operator: There are no further questions at this time. Please proceed with the closing remarks.

Dave Bezanson: Thank you all. That concludes the call. Appreciate the interest. If you have any questions, please follow up with the Investor Relations team. Have a great weekend.

Operator: Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may now disconnect your lines.

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