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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by, and welcome to the Emera Q3 2020 Analyst call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Scott Hastings. Please go ahead.
Thank you, Marcella, and thank you all for joining us this morning for Emera's third quarter 2020 conference call and live webcast. Emera's third quarter earnings release was distributed this morning via Newswire and the financial statements, management discussion and analysis and the presentation being referenced on this call are available on our website at emera.com. Joining me this morning for this call is Scott Balfour, Emera's Chief Executive Officer; Greg Blunden, Emera's Chief Financial Officer; and other members of the Emera management team. Before we begin, I'd like to take a moment to advise you that this morning's discussion will include forward-looking information, which is subject to the cautionary statement contained on the supporting slide. Today's discussion and presentation will also include references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. And now I'll turn things over to Scott Balfour.
Thank you, Scott, and good morning, everyone. We're pleased to report that overall, our business remains strong despite the impacts of the global COVID-19 pandemic. Our teams continue to deliver the essential energy our customers count on every day. And as the pandemic continues, we understand the increasing financial pressure many are facing. And so in addition to our significant community investments and rate relief programs, our employees continue to work with customers on payment plans to connect them to financial aid programs available to help reduce the financial pressure. In these ways and many others, our teams that are gas and electric utilities continue to be customer-centric. In this quarter, we saw strong customer satisfaction scores at our electric and gas utilities. Peoples Gas for the 8th consecutive year was named the top-rated utility in customer satisfaction among midsized natural gas companies in the South region by J.D. Power. In doing so, they received the highest customer satisfaction scores in the nation. Our teams have also been advancing our 2020 capital program which focuses on investments in cleaner and reliable energy. Even with the additional COVID-19 driven health and safety measures in place, I'm pleased to say again this quarter that our large capital projects, including the Big Bend modernization and our solar projects in Florida continue to be on time and on budget. These projects and our capital program as a whole reflect our strategy in action, facilitating our transition to lower carbon and improving reliability, all the while never losing sight of customer affordability. With that, I'm pleased to share that our updated capital plan anticipates the investment of between $7.4 billion and $8.6 billion over the next 3 years. As in the past, the baseline capital plan only contains committed projects that we are highly confident will proceed over the forecast period. Our baseline capital forecast includes previously announced projects like the Big Bend modernization project, investments in solar, storm hardening in Florida and hydro refurbishments in Nova Scotia. In addition to the baseline forecast, we do see incremental upside that could provide an additional $1.2 billion of investment opportunity in development. I will speak about one of those development opportunities in a few moments. Our capital program is directed towards regulated investments that support our strategy and growth in earnings. Over the next 3 years, almost 80% of our capital will be deployed in our electric utilities, while -- where our investments in renewable and cleaner generation, grid resiliency and smart meters. The remaining 20% will be invested in our gas utilities, where the focus is on system expansion to support customer growth and investments that enhance reliability. Notably, about 70% of our capital is expected to be invested in the state of Florida, optimizing our capital allocation to a jurisdiction with favorable equity thickness and returns. And notably, on a combined basis, over 60% of our $7.4 billion baseline capital program will be invested in projects that promote cleaner and more reliable energy. This robust capital program will drive rate base growth between 7.5% and 8.5% from 2019 to 2023. We will continue to update both the baseline and development opportunity forecast in the future, to keep the market up-to-date on significant advancements. We're very proud of the growth that Emera has demonstrated, and we'd look -- and as we look to the future, we're excited about the opportunities that we see for your company. Our strategy, team and focused capital plan are driving real and meaningful contributions to national, provincial and state level responses to climate change, reducing greenhouse emissions from our operations and strengthening the resiliency of our energy systems. As compared to a 2005 base period, our 2 largest utilities, Tampa Electric and Nova Scotia Power have reduced their greenhouse gas emissions by over 35% in 2019 and are forecasting an overall 50% reduction in 2023. While we're proud of our track record, we know we still have work to do as we continue to transition to a lower carbon economy. The reality is that when it comes to emission reductions and our sustainability efforts and positioning, overall, we have a very good story to tell, and we're working hard to tell it better. In October, we published our annual sustainability update, which provides a complete picture of our performance on environmental, social and governance matters. This year, we added 2 new disclosure frameworks, SASB and TCFD, and we look forward to continuing to build on our ESG disclosures in future reports. The integration of renewables and natural gas has significantly transformed Emera's generation fleet. With our committed capital program in place, it is anticipated that in 2023, Tampa Electric and Nova Scotia Power will have reduced their percentage of coal generation by combining more than 20 -- more than 80%, excuse me, as compared to a base period of 2005, an 80% reduction compared to 2005. Our service territories are unique, which, of course, drives our approach to achieving these reductions in each jurisdiction. In 2023, Tampa Electric will have over 1,250 megawatts of solar connected to their system as compared to just 4 megawatts when Emera acquired the utility in 2016. Our Big Bend modernization project is also contributing to the significant reduction in GHG emissions in our Florida operations. Nova Scotia Power is a leader in wind generation, with 18% of its energy coming from the wind. One of the highest penetrations of wind energy in North America. In 2019, 30% of Nova Scotia's energy came from renewable sources, and we're on track to increase that to almost 60% in 2023. Nova Scotia Power has already exceeded the commitments made by Canada at the COP21 forum. Investments in renewable and cleaner generation and transmission to bring renewables to market will remain a central part of our strategy for years to come, while never losing sight of the costs for our customers. On that note, as I mentioned earlier, Emera's capital program includes both baseline capital and development opportunities. These development opportunities are projects that our teams are currently working on that are not committed to the point of being considered baseline. One such opportunity is the potential development of a new large-scale transmission project that would enable the movement of clean energy and firm capacity through the Atlantic region. This project was referenced recently in the federal government's Throne speech as the Atlantic Loop. Emera has been working with our partners to advance this exciting idea, and we're encouraged by their recent progress, but it's important to note that it's still very early days. And the number of provinces and utilities potentially involved makes for a very complex project. However, we see tremendous benefits for the whole region with this transformative initiative. Before I pass the call to Greg, I'd like to recognize Peter Gregg, who has recently joined the Emera team as President and CEO of Nova Scotia Power. Peter brings deep experience in the Canadian energy sector with a focus on energy efficiency, renewables and innovation. Welcome, Peter. And with that, I'll turn it over to Greg to take you through our financial results for the quarter.
Thank you, Scott, and thank you all for joining us this morning. Our portfolio of regulated utilities has remained strong and performed very well, delivering adjusted earnings growth of 10% year-to-date. We are very pleased with these results, which was primarily driven by strong earnings from Tampa Electric, which I will discuss in a moment. Our regulated utilities are in premium jurisdictions with supportive regulatory relationships. This point is further supported by the recent constructive settlement agreements filed by our gas utilities related to their general rate cases. These settlements include a number of rate design improvements and will provide clarity around the earnings and cash flow growth of these utilities. Earlier today, we reported third quarter adjusted earnings of $166 million and adjusted earnings per share of $0.67. For the 9 months year-to-date, adjusted earnings were $477 million and adjusted earnings per share $1.93. Emera's adjusted earnings per share increased for the quarter and year-to-date when normalized from the asset sales and the timing of preferred dividends. These increases were mostly driven by favorable results of Tampa Electric and the other segment. Now let's get into details about the results. With the sale of the unregulated gas plant in Emera Maine, we expected there to be a fluctuation in our results due to the lost earnings contributions from these businesses. By normalizing the earnings impact of the asset sales, there's greater transparency of the performing of our ongoing business. For the third quarter 2019 results, when normalizing for the sale of Emera Maine would have been $0.44. And for the year-to-date 2019, the adjusted earnings per share was $1.99, which included $0.29 from assets that have been subsequently sold. These assets include the unregulated gas plants, Emera Maine and the sale of property in Florida in 2019. Therefore, the normalized earnings per share year-to-date 2019 would have been $1.70. These normalized results, $0.44 for Q3 2019 and $1.70 for 2019 year-to-date become the starting point to compare our results for the third quarter and year-to-date 2020. Growth from the normalized Q3 2019 base of $0.44 was largely driven by strong performance by Tampa Electric and our other segments. During the quarter, Tampa Electric contributed $175 million of earnings, an increase of $22 million over the third quarter of 2019. Tampa Electric's growth was driven by increased sales to residential customers, higher SoBRA revenues, higher AFUDC earnings from the Big Bend modernization and other nonsolar project -- other non-SoBRA solar projects and lower depreciation and amortization expense. Third quarter earnings from our other segment improved when excluding the timing of the preferred dividend, which is shown separately on the slide. This increase in earnings was mostly due to lower interest costs and the fact that in Q3 2019 results included a onetime expense related to the impact of Hurricane Dorian on Grand Bahama Power Company. In addition, Emera Energy's marketing trading business improved results by $8 million in Q3 2020 due to lower fixed cost commitments for gas transportation and storage assets. The remaining Emera utilities combined for a $0.02 decrease in EPS for the quarter. The Caribbean earnings were lower because of the pandemic's impact on the tourism industry and the economy, in particular, in Barbados. In addition at Grand Bahama Power Company, the company continues to recover from the effects of Hurricane Dorian. We don't expect this trend to continue over the long term, but short-term results for this segment are expected to underperform on a full year basis as compared to 2019. The gas utilities and infrastructure segment experienced lower earnings in the third quarter of 2020 as compared to the same period in 2019. When excluding the $7 million impact of regulatory decision in New Mexico in Q3 2019, New Mexico Gas had higher earnings, driven primarily by lower operating costs. At Peoples Gas, lower base revenues due to the impact of COVID-19 on commercial sales were offset by higher customer growth, increased AFUDC earnings and higher return on investments in our cast iron/bare steel replacement rider. The earnings in the Canadian utility segments were up compared to Q3 2019 due to an increase in equity earnings from the Maritime Link and Labrador Island Link investments. This increase was partially offset by a decrease in Nova Scotia Power's earnings due to the impact of COVID-19 on sales volume, increased income taxes and the reversal of fixed cost deferrals in 2019. So on a normalized basis, Emera's earnings per share for the third quarter of 2020 was $0.58 versus $0.44 from Q3 2019, representing a growth rate of 32%. Lastly, for the quarter, the timing of preferred share dividend declaration in Q3 2019 versus Q3 2020 caused a $0.09 impact for the quarter. This is simply a timing difference, and there will be no impact on the annual amount of preferred dividends. Similar to the quarter, year-to-date growth for the normalized 2019 base of $1.70 was largely driven by the strong performance of Tampa Electric. For the year-to-date 2020, Tampa Electric contributed $400 million of earnings, an increase of $61 million or 15% growth over the 2019 year-to-date. Tampa Electric growth was driven by higher base revenues related to favorable weather, customer growth and a greater mix of residential sales. In addition, Tampa Electric's earnings benefited from higher AFUDC from the Big Bend modernization, and non-SoBRA solar projects and lower depreciation and amortization expense. The other segment had increased earnings from Emera Energy from higher marketing trading margin. As I mentioned, for the quarter, the 2019 results included onetime corporate costs related to Hurricane Dorian's impact on Grand Bahama. Adding to the positives from Emera Energy and the corporate costs, foreign exchange has been a tailwind for the year contributing $0.03 per share. And lastly, share dilution for the year-to-date was approximately $0.07. The 2019 results included the result -- the 2019 results included the results of 2 separate regulatory rulings in New Mexico that had a positive impact on earnings. The recognition of tax benefits related to a change in treatment of net operating loss carryforwards. And secondly, the recognition of tax reform benefits from 2018, collectively totaling $19 million or $0.08 per share. And lastly, our remaining utilities in total were slightly lower than the year-to-date 2019. Similar to the quarterly results, the other electric utilities, excluding Emera Maine had lower earnings in 2020 due to the ongoing impact of COVID on the tourism industry in the Caribbean and the continued recovery from Hurricane Dorian in Grand Bahama's Power Company. Canadian Electric Utilities has had lower earnings year-to-date. Nova Scotia Power has had lower earnings from increasing of income tax expense, unfavorable weather and decreased commercial, other and industrial sales volumes, primarily related to the impact of COVID-19. These negative impacts on Nova Scotia Power partially offset -- partially offset higher equity earnings, a gain from the Maritime Link and Labrador Island link investments. Within the gas utilities and infrastructure segment, earnings increased from the year-to-date when excluding onetime regulatory adjustments at New Mexico Gas. This increase was due to higher customer growth, increased AFUDC earnings and higher returns from our cast iron/bare steel replacement investments at Peoples Gas and lower operating expenses at New Mexico Gas. And these positives were partially offset by lower base revenues at Peoples Gas due to the impact of COVID-19 on commercial sale. So on a normalized basis, Emera's 2020 year-to-date EPS was $1.85 compared to $1.70 from 2019, a growth rate of 9%. And as I previously mentioned, the timing of preferred dividend declaration caused a $0.05 timing difference year-to-date. And finally, Emera Maine contributed to Emera's EPS in Q1 2020. So in the interest of transparency, we have identified that separately. Moving to adjusted EBITDA and cash flow. Year-over-year EBITDA, earnings before interest, taxes, depreciation and amortization was lower, decreasing by $38 million or 2%. As expected, the majority of this decline was related to the sale of the gas plants and Emera Maine. Operating cash flow for the year-to-date 2020 was down $81 million or 7% compared to 2019. Again, as anticipated, most of this decline was due to the sale of Emera Maine in Q1 2020 and our unregulated gas plants in the first quarter of 2019. The quality and growth of Emera's regulated cash flows continues to be a priority for our team. As Scott highlighted, we are pleased with the $7.4 billion capital program and the growth that this will generate in rate based and future earnings for Emera. Consistent with the 3-year funding plan we outlined at our Investor Day in February, we view the current funding plan as a return to normal course business following the completion of our asset sales program earlier this year. We have always managed our funding program to maintain our targeted capital structure of 55% debt, 35% common equity and 10% hybrid preferred equity. To achieve this target, we climbed to the top of the capital ladder to minimize our equity requirements while maintaining a strong balance sheet. Our funding plan maximizes reinvesting operating cash flows and manages our businesses' regulatory capital structure through the issuance of operating company debt. And then finally, Emera issues common and hybrid equity capital to balance to our targeted capital structure. Our equity requirements over the next 3 years is expected to be raised through our dividend reinvestment plan, which is expected to raise $200 million to $250 million per year. And consistent with our previous funding plan, at the market program, a very efficient and cost-effective way to issue common equity will be used to complete common equity requirements. And finally, the company will continue to manage the hybrid and preferred capital portion of the capital structure at approximately 10%, which is consistent with our targeted capital structure. Thank you. And with that, I'll turn the presentation back over to Scott.
Thank you, Greg. This concludes the presentation. We would now like to open the call to questions from analysts.
[Operator Instructions] Linda Ezergailis from TD Securities.
I'm wondering if you could help us understand this Atlantic Link opportunity for the region and for Emera. Can you give us a sense of what the bookends of possibilities of timing of development of this might be realizing it's in the very early stages, what the bookends of possibilities might be in terms of absolute size on a total basis as well as what the bookends of possibilities might be for Emera's equity participation in this?
Yes, Linda, it's Scott. And look, at this point, I'd say it's still a little early to get into sort of narrowing some of those items. But I will say this is a project -- multiples of the scale of the Maritime Link project for us. And as to the project overall. And I think as to timing, really the center point of this strategy and really the original impetus for this project as a whole is a recognition as we -- if we can think about Eastern Canada, Atlantic Canada, more as a region and think about the clean hydro resources that exist in Newfoundland and Labrador and in the province of Québec. Where at this juncture, there's more energy than they consume natively themselves. And so can we think about the region as a whole, and look at provinces of Nova Scotia and New Brunswick, where additional clean hydro energy can assist with the process of decarbonizing. And so for us, really, when you think about the coal generation that exists in Nova Scotia, as you know, pursuant to an equivalency agreement has a time line to 2040 for retirement. And this project is really about whether we can accelerate that timing. Can we find a path that would allow us to retire those coal plants earlier ideally by 2030? Which would align with the federal government's objectives around coal generation in the country broadly. And so as you think about timing, the aspects of this project, if we can make this all come together, would be leading to a very ambitious project that ideally would have us in service in 2030 or thereabouts. So it's possible that we could see some element of CapEx within the 3-year capital plan period, but a lot of it would follow between then and closer to a 2030 date spread over that period. So beyond that, it's tough to get into some of the details until we've got more clarity on the path that is ahead, but it is a project that albeit ambitious, I think we're excited about -- encouraged by some of the early progress, but a project we'll update you on as that progress continues to develop.
And I realize there's a lot of complexity and moving parts, but can you give us a sense of maybe what some of the initial risk factors to execution might be in terms of major milestones or sticking points that will be the most challenging to overcome to get this over the finish line? Or is that too early to even comment on that?
Yes. I think I made reference to it in my remarks. And this is -- when you start to talk about regional projects, it means there's a lot of stakeholders involved and that adds complexity. And so I think that really is the most significant aspect of this. Obviously, the federal government is engaged, and we're encouraged by the reference in the Throne speech, but there's also provincial governments. And of course, utilities engaged. And so at that front-end work, Linda, that really is the most complicated. And as that starts to take shape. And if we can line up the stars to see support broadly through the regions, then I think there'll be an ability to speak more clearly about what that means in terms of scale and timing and those aspects. So I think it's really that the multi-party nature of it and working our way through that over the next a little bit is what to watch for.
Well, hopefully, it remains a priority for everyone, and the momentum continues. Maybe moving more to a question, just a follow-up with respect to the Q4 outlook. How has the opportunities looked to date for the energy marketing and trading business? And beyond this year, any comment on the outlook regarding your fixed commitments for natural gas transmission and storage and how they might continue to step down or what the 2021 outlook looks like right now would be appreciated?
So Linda, it's Judy. So you can see from the MD&A that currently, we set our expectation that we think 2020 will be a better year than 2019, which was obviously particularly weak, but that we may -- there's a risk that we fall short of the low end of our earnings guidance. It's an unusual year, 2020, obviously. So there has been a little bit of dampening of demand as a result of various economic slowdown, and the weather has been unappealing. So the reality is, we do the best we can to provide those predictions, but 40% of our money often gets earned in November and December. So until the last day of the year, it's really hard to know where we'll wind up exactly. It has been a little bit warm for the first 1.5 weeks of November, which, of course, we don't love that. But the forwards are more robust than current pricing. So the market hasn't given up on the winter and neither have we. So that's kind of where we are. You'll remember in terms of the -- our fixed cost for transportation that there are things that we -- there are positions that we generally acquire kind of on a short-term basis in competitive bidding processes. And the reality is they kind of tend to reflect last year's market. So the reason we had a lower investment kind of in Q3 of 2020, was that we were able to acquire acquisitions at a lower rate. I don't see any kind of increase in the value of gas transportation looking out into the coming year. So where that kind of positions us is we kind of have the same opportunity set for days when there's real money to be made, but we have a lower cost of entry going in, which is a limit on the downside risk. So I would never say anything a year in advance other than we would generally expect to be able to earn within our earnings range for 2021 at this point.
Rob Hope from Scotiabank.
I appreciate the comments on the opportunities and development in regards to the Atlantic project. But if we take a look at Florida, can you just give us an understanding of how much additional capital could be put to work, I guess, in TECO related to storm hardening as well as incremental renewable generation?
Yes, Rob, I think as we look at that $1.2 billion of projects under development, I think it's fair to say that probably 30% to 40% of that would be projects that we're looking at in Tampa specifically, and storm hardening would be part of that. So it could be any number of that. So I'd say it's a relatively modest amount on their overall capital program over that 3 years, but some of those things are still being fine-tune.
All right. And then just turning over to kind of your existing Atlantic transmission lines. Saw that your equity contribution into LIL got pushed off. How do you view these assets longer term? Do you have an ability to optimize them? Or are they largely kind of government-backed bonds?
Yes. I'd just say, Rob, that they're core assets for us and an important part of asset base for Emera and obviously, an important part of the energy supply profile for Nova Scotia Power. So they're attractive financially, frankly, and important strategically.
And then just to clarify, on LIL, I guess you won't earn on that incremental equity investment until the front half of 2022?
Yes. Really, it's really -- yes, so it's really once Unit 3 from Muskrat Falls starts start spinning. It provides a Nova Scotia block and the Labrador Island Link is in service. We're expecting both of those milestones to occur in 2021. And so it would be in full-service for us in full year for 2022.
Ben Pham from BMO.
I wanted to follow up on Rob's question on Maritime Link. You mentioned it's core. It's obviously generating solid cash flows for you guys for a long time. And it's a carry of renewable energy to some extent. But how do you [ put it ] from more of a messaging standpoint for you, look at your rate base, CAGR tables, the rate base is declining over time, the earnings is presumably going to decline. So is there -- to Rob's point, is there ways to optimize that messaging because your rate base implied looks a lot higher if you strip out Maritime Link.
Yes. What you say is -- Greg and I are going to give the same answer, I'm sure. So go ahead, Greg.
No. I think that that's right, Ben. Once those projects are fully operational and 100% cash returns. It's certainly not going to have an incremental investment requirement going forward. And so yes, as we go over time, the rate base investment in those assets will just mathematically be smaller each and every year as they're continued to be amortized.
Okay. So there's no -- there's really no -- so you're comfortable with really the Maritime Link being a [ grind edge ] on your EPS and your rate base categories. Maybe comfortable is not the right word, but I can't think of a better word to use.
So look, I mean, what you say is right is that these -- the contributions from these assets will reduce over time. However, they -- Rob referred to it like a government bond. It would have -- it would have the same financial profile as something like that. However, as I said, these are critically strategic assets for us, for the province of Nova Scotia, for Nova Scotia Power. And so we can certainly think about how we're looking at our rate base growth and those kinds of things to make it clear that those things are a little different because you're right, those are -- those assets will not naturally grow. But as it relates to the coreness of those assets to the portfolio, not to suggest you were thinking we should monetize them in some way, that would not be on the table. These are core assets for us. They contribute positively, financially, they certainly contribute strategically. We can think about how we make sure that there's full transparency to investors as it relates to the profile that they result in as around things like rate base growth.
Okay. Makes a lot of sense. And then on your financing slide doesn't seem like really much change from before, same CapEx. And how do you think, though, about financing the additional development opportunity. Do you need external equity to fund that? And then there's a reference to, I believe, hybrids as a rebalancing mechanism. Can you clarify what you meant by that?
Yes, Ben, it's Greg. So obviously, all of the additional development opportunities, which in fairness to are a little bit back-end loaded are all regulated investments. So it would follow the traditional funding, approximately half of that would be funded with operating company debt and then the balance with common equity and preferred shares to the extent that we needed to and that there wasn't incremental cash flow coming at the same time. So all those things would get into the mix. But it would be a relatively modest incremental equity requirement towards the back end if those projects do, in fact, unfold the way we hope. On the preferred share side, I think the way to think of it is we probably have, certainly with the balance sheet growing, probably have room for call it $500 million worth of preferred shares or hybrid equity to do over this period, no rush to do it. That market has been kind of -- the pricing of that market doesn't really fit into our capital structure very well right now. It looks like it might be starting to open up. But I think at some point in time, over this 3-year period, you might see us do kind of in that range of preferred shares or hybrid equity.
Robert Kwan from RBC.
If I can go back to the capital plan, I know you've given a little bit of color here in Florida. But just you had $200 million to $500 million of opportunities before. So the first part is just can you crystallize any of that into the '21 to '23 base plan, if you got some specifics on that. And then as you think about the $1.2 billion of ops, you've already carved out Florida, but are there kind of other, call it, a couple of hundred million kind of plus-type initiatives in that -- that would be in that number?
Yes. I think, Robert, I'd say probably, there's been a little bit of, let's call it, crystallization, I think was the word used in terms of things that were under development before they are in our base plan. Probably the most material of that over this period is over the next 2 years, I guess, trying to compare a plan to plan, would be about an additional $100 million for the storm protection plan investments in Tampa Electric. There would be other some smaller other items, but that would be probably the most significant one.
And then just in the $1.2 billion outside of Florida, what else would be kind of larger pieces making up that bucket?
Yes. So about 40% of it would be targeted towards the tail end of the forecast period for the Atlantic Loop or something like that as we look at various alternatives to accelerate the reduction of coal-fired generation even further in Nova Scotia. And then probably about 30% of that total is quite frankly, everything else across all of our other utilities in our portfolio.
Okay. That's great. I'll just finish with a question on the dividend. In past years, you extended the dividend growth guidance when you announced the dividend increase, which wasn't the case this year. And now you've rolled out capital plan out to 2023. So I'm just wondering is there some extra thought that's going on internally around that or valuation around dividend policy?
No, I wouldn't read that into it, Robert. We'll look probably with our more traditional schedule again next fall in timing with the dividend discussion and decision that directors will make then as to sort of extending out the time line? And really just a reflection right now that the environment that we're all living in right now is a little different, obviously, than all of us thought. And so I think the words that I've said before, I would repeat is that when we sent this dividend growth rate of 4% to 5%, while directors will make a decision around dividend increases at each moment in time where they're having those discussions. The reality is when we set that we were looking to set that at a rate that we believe was sustainable over time. And that continues to be true. So I wouldn't read anything into it. We'll look to think about the timing extension around the dividend guidance as directors go through that process with us on the annual basis as we do in the late summer next year.
Okay. So if you'd roll it out next year, would we be getting 2 more years? Are you just thinking about shortening out the timing?
Yes. I won't prejudge what the discussion and decision from that is Robert. But we understand that dividend growth and dividend growth guidance is helpful to our investors. And so that will be certainly front and center as we have our discussions with directors and make sure that we're providing the most helpful pieces of guidance to our investors as it relates to what our growth profile looks like. But as I say, the dividend growth rate that we established was one that we put in place thinking that was sustainable over a long period of time, and I would suggest to you that continues to be true in my view.
Mark Jarvi from CIBC.
I wanted to come back to the Atlantic Loop and I know there's a lot of work to be done there and a lot of unknowns. But when you talked about an earlier phaseout of coal and bringing in cheaper renewables and not creating undue bill pressure for your customers. Just curious, can you -- can you also create a little bit more buffer for further investments? I'm thinking if fuel costs coming down even more dramatically that you can even phase out coal earlier plus find room for further investments at Nova Scotia Power?
Yes. So certainly, Mark, I mean, that really has been our DNA for a long, long time is you would have heard us talk about fueled asset strategies. And so to the extent that we're able to take advantage of removing higher cost, higher carbon generation and replacing it with renewables that eliminates the fuel expense in that and effectively redirect that towards the cost of capital of renewables, absolutely, we'll do that. And look, just like more solar is absolutely part of the energy future for Tampa Electric. And more wind is also part of the energy future for Nova Scotia. Storage is going to be an important aspect in both utilities as we put more intermittent renewables onto the system. And in the Nova Scotia's case, as mentioned, the ability to enhance the existing transmission infrastructure in order to optimize the system, all those parts together is really what will allow and enable an earlier retirement of coal. And the trick and the challenge of that is, as an answer to Linda's question is getting all the stakeholders aligned in that, and that's complicated. And two, is making sure that it's not putting an incremental cost burden on Nova Scotia Power customers relative to a path to doing it to the existing 2040 time line. So that's really the work that we're doing and continuing to frame out, and we look forward to sharing more as that work advances.
Okay. Great. And then my last question maybe is for Greg. Just looks like a little bit of deferral in spending in Nova Scotia Power. Is there anything else that's moved from 2020 into 2021 or subsequent years in the 3-year CapEx plan?
No, I don't think so, Mark, really it's just some of the projects at Nova Scotia Power and mostly because, as you're probably aware, Nova Scotia is one of the strictest I guess, public policies around people coming into our jurisdiction. And so at the beginning of the pandemic projects that were going to require resources from outside the area. It was determined, it was probably prudent to move those. Other than that, I can't really think of anything material in any other jurisdictions at this point. Everything else has been pretty much on plan.
David Quezada from Raymond James.
Question on Florida. And I guess, broadly, the topic of renewable natural gas. I'm wondering if that factors into your plans there part of that incremental CapEx opportunity or I guess even hydrogen as well, what kind of time frame do you think for that?
Yes. Well, certainly, on the first one, David, I'd say both Peoples Gas and New Mexico Gas are working on and looking at renewable natural gas. I'll pass it to T.J. in a second, and he can give you a sense as to his perspective on Florida. As to hydrogen, I'd say it's something that we're talking a lot about. We don't have any active projects on it at the moment. Obviously, hydrogen is one of those areas that has a lot of investor in capital market attention right now. The math is pretty tough. Today for hydrogen, but that could change in the future, which is obviously why we're spending a lot of time thinking about it and talking about it, but we don't have any active projects right now. And with that, T.J., you want to give a bit of color on RNG in Florida?
Sure. Happy to. Yes, we have several projects in the development stage now that where we're discussing the opportunity. We do see that as a really bright opportunity within Florida for Peoples Gas and for the environment, both. So we do have several projects on the drawing board that we're working through with potential suppliers currently. So we -- and I agree on the comments regarding the hydrogen, certainly further out on the hydrogen in Florida, but the renewable natural gas is a viable option for us right now, and we're working through several projects.
Excellent. Appreciate it. And then maybe just one question, I guess, on COVID-19, as we started to see -- it seems like cases are going higher again, especially in the U.S. and maybe this question is on Florida specifically. As the duration of the pandemic kind of drags out here and appreciate that it's been a minimal impact so far. As the duration drags out, do you expect that it will still be a minimal impact? Or is the longer time frame of it start to mean it's a more material impact?
Yes. You know I, I think, obviously, in 2020, David, all jurisdictions, including Florida went through periods of lockdowns. And that changed the way that our customers use energy. But it changed things more for some businesses than for others. And so for the T.J. -- the business that T.J. leads, for example, Peoples Gas had a more dramatic impact because an important customer base for him is -- are many commercial businesses that obviously weren't operating. And therefore, weren't consuming natural gas during that period. So I think there are pockets where if this continues, Caribbean would be another example that until there's a recovery of tourism, things are going to be a little tougher in Barbados as an example, until planes start flying again and tourism activity starts to return. For Tampa Electric, for sure, there are impacts, of course, and making sure that we're continuing to stay sensitive to our customers and supporting them through the period. But weather impacts, frankly, have been material in Florida, and that's been having on balance, a more material impact on changes of load for Tampa Electric, than has the way that our customers are using our energy. Does that make sense?
Yes, absolutely. That's great color. Appreciate it.
Andrew Kuske from Crédit Suisse.
I guess the question is maybe in the spirit of measure twice and cut once. But when you think about storm hardening, some of the existing infrastructure that you have. How do you think about that just on a regulatory mechanism, and clearly you have one in Florida, just more broadly from an NPV basis of building more resilient infrastructure that lasts through storm cycles, versus the build rebuilds on a more regular basis. Can you just maybe give us some color on that and how that varies through the franchises that you own?
Yes. So let me try this. I'm trying to get to the heart of your question, Andrew. And so let me know if I don't or Rick or Greg can help me. But you're right. The regulatory mechanisms as it relates to storm hardening or reliability investments are a little different jurisdiction by jurisdiction. Obviously, the most different right now is in Florida with Tampa Electric and the SPP, the storm protection plan, that is now in place there with something that arose as a result of underlying need in recognition of the impact of major hurricanes in past years, but also with significant government support and initiative to ensure that there was actions being taken in order to accelerate those efforts. In most other jurisdictions, storm hardening or reliability investments become part of the capital plan and the profiling that each business conducts and reviews with its regulator, in some cases, before the capital is spent. In other cases, after the capital is spent, depending on the jurisdiction, and there always needs to be a lens of -- regulators will apply a lens of prudency as it relates to those investments. And so you are right, is thinking about how those investments are made and the cost of rebuilding for storm damaged infrastructure versus making them harder so that you don't need to rebuild as often is a really important part of the analysis that the teams do and review as part of that work. And the environment that we're in is changing. And here in Nova Scotia, the instances of higher winds are more frequent than they have been in the past. And so the team works through that as well in order to make sure that they're planning for a system that is going to experience more frequent levels of higher wind. And that would be true in terms of the work and analysis that goes on across the system.
Got it. Maybe I could add just a bit of color to it, Andrew. As Scott mentioned, outside of Florida, each of the utilities have transmission distribution investments that include improvements in reliability, the rain debt storm hardening and ability for the system to stand up in those severe events. Each of the utilities have it within their normal investment programs, but also a key component of it is you're replenishing with newer technologies. They are slightly more expensive, but give you better reliability. So the investment profile, as an example, in Nova Scotia Power for T&D is about 40% of the overall capital program for 2021, captures significant portion of it, focusing on reliability and enhancements on the system.
I appreciate the color. And then maybe just a follow-up on that. What role do you see batteries play in within your utilities' footprints, and your Nova Scotia would probably be a good example with just long radio lines? Do you see opportunities to really put batteries much closer to load and maybe even on an individual house-to-house basis to improve reliability and then effectively buy you time to put the system back?
Scott, do you want me to address that?
Yes, please.
So it's Rick again, Andrew. Batteries, we have battery system in Barbados, in Nova Scotia as well on a feeder. Most of the development right now is focused on trying to figure out how to extract the highest benefit from battery systems we're deploying. So we know the technology, the costs are coming down. Technology is improving and within ETL, Emera Technologies. Also, they're developing the micro grid approach with the DC system that has battery components embedded. So a lot of work within Emera. Each of the utilities tackling different challenges within each of the utilities and how to deploy them, but will be a big part of it. We're just watching to make sure we're deploying the capital cost effectively.
Andrew, it's Nancy. I'll just add, if you look at our 10-year site plan here in Florida, and the work that we did last year on the IRP that served as the basis for it. And we'll -- and in our next 10-year site plan, you will see solar, of course, ongoing investment in solar, but with battery. We think that's key, and we think the prices will be such that, that will make sense for us.
[Operator Instructions] Elias Foscolos from Industrial Alliance.
Most of my questions have been asked, but probably one broad question. Probably initially directed towards maybe Ryan and T.J. Despite economics, some U.S. cities have been making headlines by banning natural gas in new buildings. I can't find anything sort of related to that in Florida, but maybe you can give an outlook on that. And then maybe a broader question to take back to Greg or Scott is -- do you consider yourself relatively hedged if that occurs?
Ryan, you want to give a New Mexico perspective?
Yes, sure, Scott. I think here in New Mexico, we have not had any cities or anybody come forth requesting those types of changes. So we feel pretty good here, but we also know that there's environmental groups out there pushing this all the time. So we're very aware of that. New Mexico is an interesting state because natural gas and oil are a big part of the state. So very important to the state's economy. So we don't see a huge push in that direction anytime soon. And with the abundance of natural gas here and the affordability, we think it's a good source of energy for our customers.
Yes. And on the Florida side, very similar. We do have environmental groups. Actually, in terms of cities, you mentioned, we actually have -- there are a handful of cities that, over the last several years have made proclamations or resolutions to be clean by 2050 in order to be carbon neutral, that type of thing. When you look at kind of the grassroots demand for natural gas across Florida, it's really strong, both residential and commercial. And so we -- as with Ryan, we see the demand for natural gas continuing in Florida. We do hear those voices across the state from Sierra Club and others that are promoting no fossil fuels. It's just -- that is not practical nor affordable at this point for customers and certainly, natural gas in Florida has been a -- one of the reasons that we've had reduced CO2 across the state over the last 15 years and the continued end-use of natural gas for the foreseeable future is really critical, I think, to having continued advancements in terms of the environment. And so we're certainly part of the answer there, not part of the issue and working closely with electrics to be a partner with renewables is where we see ourselves. And again, all of that, combined with a very strong end-use demand for natural gas by customers, I think we'll see natural gas in Florida for some time to come.
Yes. And look, I don't -- I mean I understand the point as to -- do we see it as a hedge, and I wouldn't say that's a driving force strategy. But I would say that I understand people are asking different questions about gas LDCs now within capital markets. From our perspective, we're happy with the gas LDCs that we have. I think New Mexico and Florida both, I'll use my own words in this. But I think broadly, both of those states see the natural gas LDC as an enabler of decarbonizing the electric side, and therefore, an important part, frankly, of that -- of that journey to carbon reduction. We agree with that premise, frankly. And so today, we're happy with the roles that those gas LDCs are playing in their jurisdictions. We're happy with the role that they're playing within the portfolio as well.
There are no further questions at this time. I'll turn the call back over to the presenters.
Well, I'd like to thank you for joining the call today and your interest in Emera, and I hope you enjoy the rest of your day.
This concludes today's conference call. You may now disconnect.