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Ladies and gentlemen, thank you for standing by, and welcome to the Emera Q2 2020 Analyst call. [Operator Instructions] Please be advised that today's conference is being recorded today, Wednesday, August 12, 2020, at 9:30 Atlantic Time. I would now like to hand the conference over to your speaker today, Scott Hastings, Emera's Senior Director, Capital Markets. Please go ahead.
Thank you, Chris, and thank you all for joining us this morning for Emera's Second Quarter 2020 Conference Call and Live Webcast. Emera's second quarter earnings release was distributed this morning via Newswire and the financial statements, management's discussion and analysis, and the presentation being referenced on this call are available on our website at emera.com. Joining me for this morning's call are Scott Balfour, Emera's President and Chief Executive Officer; Greg Blunden, Emera's Chief Financial Officer; and other members of the Emera management team. Before I begin -- before we begin, I'll 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. And 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. As the global COVID-19 pandemic continues, our team remains focused on safely delivering the essential energy our customers are relying on in all of our service areas. The rates of infection of the virus in the communities we serve have varied significantly. For example, in Atlantic Canada, we experienced very little community spread of COVID-19 and in parts of the Caribbean and New Mexico, spread has also been relatively contained. Clearly, it's a much different situation in the state of Florida, where they're facing much higher spread and infection rates. However, no matter where we operate, our #1 priority is the health and safety of our team, our customers and our communities. Our teams have adapted in every jurisdiction to new procedures and protocols to continue to deliver despite the impacts and challenges of COVID-19. While we have never stopped working, many of our employees have been productively operating from home since mid-March. As public health officials lift restrictions, we've been focused on our responsible reentry plans to phase our employees safely back to the tuition workplaces. Our reentry will be measured and will be reflective of the rates of transmission and public health guidelines in each of our service territories. We understand that the pandemic continues to drive financial pressure on our customers and our local communities. From the beginning, our utilities have been working with customers on relief initiatives and donating to organizations to help the vulnerable in our communities. In addition to corporate donations, our employees recently mobilized to support food banks in their communities and to assist local organizations and businesses, illustrating the compassion and community spirit of our employees above and beyond their unwavering commitment to delivering for customers during this pandemic. I've shared with our team many times that a response to this pandemic is more like a marathon than a sprint. They've continued to adapt and deliver for our customers and our communities that have returned. I'm proud of them and grateful for their contributions to Emera's strength and resiliency. As expected, while the COVID-19 pandemic has, of course, had many impacts, our business is nonetheless continuing to perform very well. We're generally experiencing lower commercial and industrial sales because of the economic impacts of the pandemic. But this has been partially offset by increased sales to residential customers, where the contribution to recovery of fixed costs are structurally higher. We expect this trend to continue throughout 2020 and as we continue to manage the impacts of the pandemic. Our balance sheet has also been strengthened with benefit of the proceeds from the sale of Emera Maine. And as Greg will discuss in a moment, our businesses have been able to grow cash flow from operations on a year-to-date basis. These actions, combined with our reaffirmed credit ratings from Moody's and Fitch, reflect our strong and stable financial position. With additional health and safety procedures in place, Emera's capital program continues to advance. And as I reported on our first quarter call, we are pleased that our major projects are continuing without any significant supply disruptions or delays. This includes both the Big Bend modernization project and the solar developments in Florida. We expect to continue to fully deliver on our capital program. We remain confident in our long-term value proposition to shareholders, which is supported by the strength and resiliency of our strategy and our team. Across the business, our teams continued to work with regulatory agencies to ensure customer affordability, reliable service and maintaining financially healthy utilities. This includes a number of important regulatory filings in our service territories. Throughout the pandemic, our teams have been working with regulators to advance these filings without any major delays. This includes rate cases at New Mexico Gas and Peoples Gas. These regulatory actions are important for the business, and we are pleased with the progress to date. In addition, just this week, the Florida Public Service Commission approved Tampa Electric stipulation agreement related to the storm protection plan, which allows for the implementation of this class starting January 1, 2021. Lastly, both Peoples Gas and New Mexico Gas have filed for regulatory relief related to the deferral of COVID-related financial impacts, including increased bad debt expense. The New Mexico regulator approved this filing in the second quarter. And the Peoples Gas filing is expected to be reviewed by the Florida Public Service Commission in the third quarter. As of the end of Q2 2020, no COVID-19 related deferral accounts have been recorded. The impacts of COVID-19 have been devastating to many communities, economies, industries and individuals around the world. And it's clear that it is far from over. While we have employees who have tested positive, I'm relieved to say that we've had very little workplace spread and our employees that have been impacted are doing well. We also feel fortunate that we have such a strong portfolio of businesses that continue to benefit from diversification. Although some of our utilities have experienced larger COVID-19 impacts than others, overall, the pandemic has not had a material financial impact to date. We know there are more challenges ahead as governments look towards economic recovery, and we remain committed to doing our part, not only in continuing to provide the cleaner, affordable and reliable energy our customers and communities rely on, but to help with community support and the economic restarts in all of our jurisdictions. 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 have remained strong and performed very well, delivering adjusted earnings growth of 4% for the year-to-date, despite dealing with the impacts of the pandemic. We are pleased with this result, which was primarily driven by strong earnings from Tampa Electric. Our regulated utilities are in premium jurisdictions with supportive regulatory relationships, and Emera continues to see its earnings quality improve. Now let's get into the details about the results. Earlier today, we reported second quarter adjusted earnings of $118 million and adjusted earnings per share of $0.48. For the 6 months year-to-date, adjusted earnings were $311 million and adjusted earnings per share was $1.27. Emera's adjusted earnings per share increased for the quarter and year-to-date when normalized for the impacts of asset sales and the timing difference related to the declaration of preferred dividends. These increases were driven by favorable results of Tampa Electric, partially offset by reduced earnings at Nova Scotia Power and Emera's gas and Caribbean utilities. With the sale of the unregulated gas plant at Emera Maine, we expected there to be a fluctuation in our results due to lost earnings contribution from these businesses. By normalizing the earnings contributions from asset sales, there's more transparency on the performance of our ongoing businesses. For the second quarter 2019 results when normalized for the sale of Emera Maine would have been $0.49, and for year-to-date 2019, the reported adjusted earnings per share was $1.49, which included $0.22 from assets that have been subsequently sold. These assets included the unregulated gas plants at Emera Maine and the sale of a Florida property. Therefore, the normalized earnings per share for the year-to-date 2019 would have been $1.27. Growth from the normalized Q2 2019 base of $0.49 was largely driven by the strong performance of Tampa Electric. During the quarter, Tampa Electric contributed $146 million of earnings, an increase of $21 million over the second quarter of 2019. Tampa Electric's growth was driven by increased sales to residential customers, higher AFUDC earnings from the Big Bend modernization and solar projects, lower operating expenses and lower depreciation and amortization expense as a result of a regulatory settlement. Second quarter earnings from Emera Energy's Marketing and Trading business contributed approximately $0.05 more earnings per share than in Q2 of 2019. This increase was due to lower fixed commitments for gas transportation and storage assets and more favorable market conditions, specifically increased volatility as compared to Q2 2019. Emera's other utilities experienced lower earnings for the quarter. The earnings in the Canadian Utilities segment were lower than Q2 2019 due to impacts of COVID-19 on sales volume, increased income taxes and higher storm costs, partially offset by the timing of a regulatory deferral. In the Caribbean, earnings were negatively impacted by COVID-19 and the ongoing impact of Hurricane Dorian and Grand Bahama Power Company. The gas utilities and infrastructure segment experienced lower earnings in Q2 of 2020 as compared to the same period in 2019. The second quarter of 2019 included the regulatory decision in New Mexico that contributed $0.05 in EPS and was onetime in nature. Excluding this regulatory adjustment, the gas LDCs were basically flat quarter-over-quarter. So on a normalized basis, Emera's earnings per share for the second quarter of 2020 was $0.53 versus $0.49 in 2019 Q2, representing a growth rate of 8%. Lastly, for the quarter, there was a change in the timing of the declaration of preferred share dividends in Q2 2020, causing a $0.05 impact in the quarter. In 2019, this amount was recorded in Q3 and this is simply a timing difference, and there will be no impact on the annual amount of preferred dividends paid. Similar to the quarter, year-to-date growth from the normalized 2019 base of $1.27 was largely driven by the strong performance of Tampa Electric. For the year-to-date 2020, Tampa Electric contributed $225 million of earnings, an increase of $39 million over year-to-date 2019. Again, Tampa Electric's growth was largely driven by higher base revenues related to favorable weather in Q1, higher AFUDC, lower operating cost, customer growth and the lower depreciation and amortization expense as a result of the regulatory settlement. Emera's other utilities experienced lower earnings for the year-to-date 2020, mainly because of the same drivers I mentioned earlier for the quarter, including the regulatory decision in New Mexico. So on a normalized basis, Emera's 2020 year-to-date EPS was up marginally to $1.30 as compared to $1.27 from 2019. And as I previously mentioned, the timing of the preferred share dividend declaration caused a $0.05 timing difference that will reverse in Q3. And finally, Emera Maine's contribution to Emera EPS in Q1 2020 has been highlighted for transparency purposes. Moving to adjusted EBITDA and cash flow. Year-over-year EBITDA, that's earnings before interest, taxes, depreciation and amortization, was lower, decreasing by $63 million or 5%. Most of this decline was related to the sale of the gas plants in Emera Maine. Operating cash flow for year-to-date 2020 was up $41 million or 5% compared to 2019. This growth was led by Tampa Electric, which experienced an increase of $77 million or 18%. This increase in regulated cash flows is a further signal of Emera's improving cash flow quality, which is a priority for our team. In closing, the quality and diversification of Emera's portfolio produced strong results for Q2 2020, despite dealing with the impacts of COVID-19. Our businesses continue to be resilient and are committed to both the safety of our employees and customers as we work through the pandemic. Our strong year-to-date operating cash flows and available liquidity have the company well positioned for possible future COVID-19-related challenges to the business. Our major capital projects continue to progress without any significant disruptions and are on time and on budget, including the Big Bend modernization and solar projects in Tampa. And lastly, the regulatory teams across our businesses are advancing important initiatives, including rate cases at our gas LDCs in Florida and New Mexico. Our business is strong and well positioned for future growth. And with that, I'll turn the presentation back over to Scott.
Thank you, Greg. This concludes the presentation, and we'd now like to open the call for questions from analysts.
[Operator Instructions] And your first question comes from Ben Pham of BMO.
Okay. On -- my first question is on COVID-19. I know you mentioned the impact isn't material year-to-date. You're not booking deferral accounts and whatnot, but can you provide a sense of any sort of quantification or directional impact that you experienced? Is it a couple of million here and there in each segments? Or is it something else? Any context would be appreciated.
Yes. Ben, it's Greg. I think probably the easiest way or the way that we think about it is probably kind of in 3 buckets. So from an operating cost perspective, incremental PP&E, those types of things, we really -- it's really been, for the most part, probably offset by savings that we're experiencing because of the work environment we're in right now. So effectively, no impact at all. Obviously, we've seen some load impacts, if I think of the second category across our businesses, some a little bit more higher than others. But then in some cases, more than offset by weather or a mix of sales by customer class where some customer classes obviously contribute more to fixed costs than others. And third is bad debt expense. And I think it's too early to tell where that will end up. Obviously, like everybody else, we're anticipating that we will have an increased bad debt expense this year. Across the business, it would be single digits of millions of dollars that we would anticipate at this point in time.
All right. And then you mentioned a couple of rate cases that are ongoing or didn't go on track. My question more is that beyond the bonds you have. What's the plan around Tampa Electric in terms of filings? And can you remind us with Nova Scotia Power, when do you have to address or let the regulatory know your thoughts around cost of service or just any sort of expansion to the rate agreement?
So Nancy, you want to start with Tampa Electric? And then, Rick, you can respond for Nova Scotia Power?
Sure.
Yes. Sure, Scott. I didn't quite catch the -- the sound was a little muffled on my end, I apologize. So maybe just if you could clarify the Tampa Electric piece, that would be appreciated.
Yes. Not a problem. My question was really the timing on the next rate case, if that's the plan?
Okay. Sorry. Yes. So -- and in terms of regulatory filings, generally, things have been moving along quite well in the state. We had the approval of the SPP on Monday, which was great. We had other settlements and other agreements. And so the business of the Florida Public Service Commission is continuing on really without disruption. In terms of next rate case, we would anticipate to -- we're in a stay-out until 2021. We can't have new rates before 2022. We've been doing a lot of building, as you know. And so we would anticipate going in as soon as we can to get new rates for all the capital we've put in place.
And Ben, it's Rick Janega with Nova Scotia Power. So Nova Scotia is operating under another Rate Stability Plan that was negotiated with customers and the regulators. So that will cover us out till 2022 as well. The intent of it would be to work with the customers to look for other opportunities to continue those types of creative approaches to managing rates. Knowing that we're heading into investments that are aimed at increasing renewable content and looking at the future state of coal generation in Nova Scotia, that will probably be the biggest driver to what we're doing next on rates and filings for a general rate application in Nova Scotia. So nothing in the imminent term, and we'll be able to keep you updated as things progress, but quite stable and in a good state in Nova Scotia.
Okay. So it sounds like, Rick, the bias now and I haven't decided is more the similar sort of mechanisms like the existing one containing inflation versus more of a full-blown cost of service application?
Yes. We, Ben -- and Ben, we do look at rates and potential for GRAs, but we do that review on a regular basis as a part of our ongoing financial management both for rate classes to make sure they're balanced between the customer classes and for the recoveries. But right now, things are in pretty good state, and we'll monitor that. We usually do that with lots of lead time for the regulator to be able to prepare for filing dates and so on, but there's nothing in the works right now for that. But we -- that's a regular part of our business to do the assessment of it and bring that planning forward, kind of with 6 to 12 months advance notice of the type of work that's required to get geared up with the regulator and customers.
Your next question comes from Mark Jarvi of CIBC Capital Markets.
Obviously, with the potential of a change in administration in the U.S. and chatter both reversal corporate tax rates. Greg, is there any thought to maybe pause on the reduction of holding company debt? Or just wait to see how that plays out over the next 6 months?
Yes. Mark, it's a good question. And clearly, 1 that's coming up more often, and I don't have any better crystal ball as to what's going to happen in the U.S. than anybody else. And of course, there would be a process that any new administration would have to go through. I think, we'll clearly get some increased visibility on that over the next 6 months, but -- so we're going to continue on the path that we're on, on the reduction of holding company debt and reevaluate if circumstances change.
Okay. And then can you just walk us through the lower depreciation, amortization at Tampa Electric and that I think it's an intangible software asset adjustment, just whether it's sort of onetime in nature and how that plays through in the back half of the year as well, I think there's still another $8 million to being recognized?
Yes. Yes. It was like in all regulatory environments, you find yourself periodically in situations where some of your specific assets because of the pool depreciation methodology get over depreciated, that's not uncommon, and it was something that we were working through in Tampa. And got resolution to take that excess depreciation that we had on our books and bringing in income this year. And so you're right. So it was a $16 million settlement, half of which was booked in Q2 and then the rest will just flow through the balance of the year on a quarterly basis.
Okay. And then just one other question, just following up on -- it sounds like that's not an issue. But in terms of the aging receivables, is there certain areas that you're seeing more of that or something we should be mindful of in terms of geographic concentration?
That's a good question. I don't think so. It's -- we made a deliberate decision not to disconnect people for nonpayment or delayed payments in the current environment, and we'll start to move away from that as we get into Q3 and the economies open up. So as a result of that, not surprisingly, maybe a little bit more on the residential side, you're seeing that customers are -- have been a little bit slower to pay. Some of it also gets clouded by seasonality. So in Nova Scotia, of course, we're at a period of time now where bills are lower than they normally would be. And so we're not seeing as much of an impact. Percentage-wise, we may be seeing an impact, but not as much on the dollar side. So it's kind of mixed across, Mark, but I wouldn't say that there's one particular area that is more concerning than another. And as we've started to do an outreach and let people know about the plans towards the end of the year, there's been a tremendous response from customers looking for payment plans or starting to true-up their accounts. So we're optimistic there will be some kind of incremental net bad debt expense this year. But fortunately, we're in an industry where we're starting from a really, really low point to begin with.
Our next question comes from Robert Kwan of RBC Capital Markets.
If I can just come back to tax and potential U.S. election outcomes. More so related to your disclosure back in 2018, you highlighted that tax reform was going to have a 3% to 5% negative EPS impact and somewhere in the range of $50 million to $200 million negative cash flow impact before mitigation. I'm just wondering what has actually played out? And if you can maybe just talk about now, like it took a while for New Mexico to ticking through, what's actually playing out in the current period relative to your original guidance?
So I'll give a -- provide somewhat directional, I'd say it's probably been kind of in the midpoint of those ranges, Robert. I mean, we had a pretty good sense because it's somewhat of a mathematical exercise in terms of what the EPS impact would be as a result of the after-tax cost of the U.S. debt, obviously, became higher with the 2017 tax reform. So there wasn't too much complicated about that. From a cash flow perspective, we had a reasonable view on what the refund to customers would be at Tampa Electric, and we've now worked through the other states that have transpired. So I think upon reflection, I would expect that we're probably in and around the midpoint of that range that we provided.
Got it. And that midpoint, that includes, I think there was some AMT credits that were going to flow through. And I believe that also included anything in the cross-border structures. Is that correct?
Correct.
Okay. If I can just understand with the PGS rate filing, outside of normal rate base growth, is any of the -- I think it was USD 62 million that you're looking for in terms of an increased revenue requirement. Is any of that for anticipated costs that you're not currently incurring? Or is this really to get you back into the ROE range?
I might get T.J. to help with that. T.J.?
Sure. So the $62 million includes to get us back within the range, but also anticipated additional costs to maintain and operate the system in 2021.
Okay. Do you have a sense as to how much increased costs that you're not incurring right now is kind of built into that?
Yes. Sorry, I don't have that in front of me. A lot of it is due -- really, a lot of our rate case is due to the investment that we're making in the system. And then so the return of that investment -- and the return on that investment on the rate base side. That's the bulk of it.
Perfect. And then just to be clear, the $62 million is net of other items that are moving just within rate riders?
That's correct. We're moving around $20 million from one of the riders into -- for cast iron and bare steel replacement into base rates.
Yes. Just to add on to that, sorry, this is Scott again. I think it's -- T.J., it's something like $1 billion, $1.6 billion, something like that, of rate-based investment that has been made and is still in the process of being made in Peoples Gas system to respond to system expansion and system integrity investments and those kinds of things since the last rate case. And so it's really -- it's almost substantially all that capital investment in the system to deal with that growth that is really driving the revenue requirement.
Yes, that's correct.
Your next question comes from Rob Hope of Scotiabank.
I want to follow-up on one of the U.S. tax reform questions. As we look out to your rate filing schedule, could we see you pause planning something like a TECO rate application in 2021, just to see if there is a change in tax legislation as well as to see if the regulator will look at it on a stand-alone basis? Or like -- or if it will have to be addressed in the GRA?
Yes. We -- it's Greg, I mean, we haven't made those decisions yet. I mean, clearly, the first step of your hypothesis would be election result in November, which will obviously take place well in advance of us filing. And then it will be subsequent to that. Obviously, I think most people on the call are referring to the potential of Senator Biden being successful in leading a partial reversal of the 2017 tax reform. I think we'll have lots of visibility around that in terms of what -- who's successful in the election, what their likely path is as well as the timing of that. I think we'll have all of those data points before we actually file anything in Tampa Electric. So obviously, that will be taken into consideration at that time.
All right. I appreciate that. And then just secondly, just given government's potentially looking to stimulus measures, could we see or are you interfacing with some government with the potential to help with some infrastructure investments in your various geographies?
I think, largely, Rob, we continue to invest in the business and drive investment in system and upgrades and the like in a way that we normally have. Of course, if there are stimulus package initiatives that are fit that can help to reduce the cost of a system investment for customers. And for sure, we'll be taking advantage of that. But there's nothing that's currently on the near-term radar at the moment that would fit into that category.
And your final question today comes from Linda Ezergailis of TD Securities.
I realize there's a lot of moving parts on a number of fronts, but I'm wondering if you could help us understand your recent thoughts on your funding plans for the next year, kind of a plan A and what might change that over time? Might there be some incremental asset sales? How are you looking at the relative attractiveness of various funding options on the equity side, et cetera?
Well, I'll start with the first part of the question, Linda, and then Scott can jump in. So nothing has changed from our funding plan that we would have laid out to investors and analysts in February in Tampa. We're continuing down that path. We're starting to see -- as you know, we have a little bit of room in our capital structure for some preferred shares or hybrid equity, that market looks like it might be starting to open up. But again, a relatively modest transaction for us. Yes, the equity markets have remained constructive for our sector, and we're thankful for that. Equally so and maybe more so, the debt capital markets have also remained incredibly constructive for our sector. And so all to say is we're just going to continue on our path. Our cash flows are -- despite COVID are really where we expected them to be. And at this point, haven't really seen anything that would cause us to deviate from our original communication and commitment to investors. Scott, I don't know if you want to add anything on asset sales?
No. I mean, I think you covered it well, Greg. And look, we set the -- we set out a specific target as it relates to capital raise from asset sales as part of the funding of the capital plan that's in front of us today. And we've obviously fully delivered and been successful on that. That doesn't mean that we won't, as always, continue to exercise discipline in their allocation of capital and continue to review the portfolio from time to time. But as it relates to the funding plan, we were successful with achieving our targets. And so Greg's answer, I think, gives you the sort of the full perspective on how we're looking at it today.
Maybe as just an incremental follow-up. How might any sort of recent discussions with the debt rating agencies inform those plans? And can you give us some context around your sense of how the rating agencies are thinking both at an industry level as well as for your specific businesses? Anything that might be shifting or reinforced given the passage of time?
Yes. Linda, it's Greg. So let me start with ourselves. I mean, obviously, since I guess April through to the end of June, all 3 rating agencies have come out with their updated reports on Emera. We -- Scott referenced in the call, both Fitch and Moody's in June reaffirmed our ratings and outlook. So I think you can read into that they're quite comfortable that we're continuing on the path that we had committed to follow and have executed on our plans that we were doing. Obviously, if we go back to April, we were disappointed that S&P took us down a notch, but you'll recall they also at the same time broke apart from the Group Rating Methodology and reaffirmed the ratings at our regulated utilities, which, in the current environment [ of rate ] is actually a very constructive thing because we're not planning to raise any holding company debt in the immediate near term. So with all 3 of those behind us, it's -- we don't find ourselves in a situation where there's any kind of sense of urgency with the rating agencies. We -- they've all published their reports relatively recently. We're continuing to execute as we had previously done. And I think given where they're at and with all 3 of them now with stable outlooks, I think you can read into that what should be read into it. In terms of how they're looking at the sector, I think this is -- I hate to speak for them, but they are speaking a little bit more publicly about this in various conferences. I think as they've gone back and done some looking back through time, this industry has proven to be incredibly resilient, no matter if it's a financial crisis or COVID or some other things. And one of them, I can't remember which 1, recently did a report that found out that a BBB-rated utility defaulted at -- 20% of time that a BBB corporate would default there, non-utility. So I think they're reevaluating, I think how they look at the business risk overall for utilities. I will just say is there doesn't seem to be any anxiety for any of the rating agencies right now with our particular sector and specifically with us.
Okay. And just another incremental follow-up with regards to funding and capital expenditures. There was some mention in your MD&A that you're continuing to review the timing of capital expenditures in light of the evolving pandemic. And I'm wondering if that just refers to the need for social distancing, the potential for stimulus? Or might there be some other moving parts around renewable policy or mobile technologies or other things that might cause big changes in the composition of your capital expenditures or timing or size?
Yes, Linda, it's really just about the execution of those capital projects. For example, if I use Nova Scotia as an example, we probably have the most restrictive policies in Canada in terms of people entering the province have to self-isolate for 14 days, that's still in existence today. And so there are certain capital projects that we deliberately slowed down or deferred to next year. Just in the event that once they get started, we could find ourselves in a position where we couldn't get the resources in for meter province to complete them to the extent they were contracted. On a $2 billion to $2.5 billion capital program, we're talking probably less than 10% of the overall capital program. And these are projects that will not get done at -- which states they'll get done over the next year or 2 and some of them could actually be starting up this fall. So it's more related to the practicality of getting some of these projects done, in particular, in Nova Scotia.
And those were our final questions. I will now return the presentation to the speakers.
I'd like to thank everyone for joining the call this morning and your ongoing interest in Emera. Enjoy the rest of your day. Thank you.
This concludes today's conference call. You may now disconnect.