Emera Incorporated (EMA) Q4 2021 Earnings Report, Transcript and Summary

Good day and thank you for standing by. Welcome to the Emera Q4 2021 Analyst Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, David Bezanson. Please go ahead.

Thank you, Don, and thank you all for joining us this morning for Emera’s fourth quarter 2021 conference call and live webcast. Emera’s fourth quarter earnings release was distributed this morning via Newswire and the financial statements, management’s discussion and analysis, and the presentation being referenced on this call are available at our website at emera.com. Joining me this morning’s call are Scott Balfour, Emera’s President and Chief Executive Officer; Greg Blunden, Emera’s Chief Financial Officer; and other members of Emera’s management team. Before we begin, I will take a moment to advise you that this morning’s discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide. Today’s discussion and presentation will also include references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. And now I will turn things over to Scott.

Thank you, Dave, and good morning, everyone. This morning we reported annual adjusted earnings of $723 million and I’m pleased to say that thanks in large part to record earnings and Peoples Gas and Emera Energy’s exceptional year, this represents our highest annual adjusted earnings to date. Our fourth quarter adjusted earnings per share was $0.74 and annual adjusted earnings per share was $2.81. When you further adjust for illegal settlement, we received in the fourth quarter of last year, adjusted earnings per share increased 7% over the fourth quarter of last year and 11% year-over-year. This is a continuation of our established record providing predictable sustainable growth in earnings and shareholder value. Since 2017, we’ve delivered 8% compound annual growth in adjusted earnings and in 2021, we raised our dividend by 4%, representing 15 continuous years of dividend growth. Our continued financial and operational success highlights the strength of our strategy and the dedication of our team, as they continue to focus on delivering value to our customers. As we advance our strategy to reduce the carbon intensity of our portfolio and invest in a stronger, more reliable grid, all at a pace that is cost effective for customers, we are well-positioned to continue to deliver long-term growth for our shareholders. Nova Scotia Power achieved an important milestone in their decarbonization journey in the third quarter of last year, when hydro energy for Muskrat Falls began flowing to Nova Scotia through the Maritime Link. Access to this clean energy is the major contributor to enabling Nova Scotia to reach 60% renewable energy by the end of 2022. I’m pleased to report that last week, the Utility and Review Board approved the $1.8 billion final cost assessment for the Maritime Link. This represents a significant achievement for the business and a testament to the transparent and disciplined approach taken on large capital projects. In fact, the UARB called it a commendable achievement that we were able to complete this extraordinary project on time and on budget. Well, seeing the Nova Scotia block fully flowing as it is now is an important step in our decarbonization journey. We know there’s more to do. With mandates from both the federal and provincial governments to eliminate coal-fired generation in Nova Scotia, we will have to continue to find innovative ways to achieve these goals in a way that is the most cost effective for customers. We also continue to be committed to strengthening and modernizing the grid and in 2021, we saw a meaningful improvement in reliability at both Tampa Electric and Nova Scotia Power. With the increasing intensity of storms like we’ve seen over the last two months in Nova Scotia, we need to continue to invest in strengthening the grid. In 2021, Nova Scotia Power invested $65 million in projects specifically focused on improving grid reliability. Continued investments in these types of projects has enabled Nova Scotia Power to achieve a 29% reduction in frequency of outages this past year compared to the previous five year average. This follows a 16% improvement in 2020 compared to that previous five year average. Continued investment in both targeted equipment replacements and upgrades, vegetation management, and new technologies will enable ongoing achievement of these kinds of improvements. Tampa Electric also achieved a second consecutive year of best ever reliability performance. Through their continued investment and focus on improving the customer experience, performance metrics like outage duration and frequency have improved by more than 20% since 2019 and momentary outages have been reduced by as much as 55%. Continued investment in their storm protection plan and their continued commitment to their customer position to them well to continue this positive momentum into 2022. Growth across the business has been driven by the effective execution of our strategy. This has been the driver of our growth for the last decade, and we’re well-positioned to continue delivering this profile of organic growth, as demand for cleaner energy continues to grow. Our capital program, as a whole, really reflects our strategy in action, making carbon reducing and reliability enhancing investments of value to our customers. And I’m pleased to say that over 60% of our 2022 to 2024 capital plan is specifically focused on delivering cleaner and more reliable energy. At our Investor Day in December, we shared our updated capital plan of $8.4 billion to $9.4 billion, a plan that is $1 billion higher than our previous forecast. And beyond 2024, we see this growth extending well into the future. To deliver on our climate goals, we will continue to make investments to decarbonize our portfolio, including investments in renewable generation, energy storage, and transmission. We’ll also continue to make significant investments that continue to improve reliability and provide better customer experience. Our ongoing investments in digitalization and decentralization initiatives like smart meters, give customers more choice and control, and are also an important part of building a cleaner, more reliable, and sustainable energy future. Our forecast includes $500 million to be invested in the Eastern Clean Energy Initiative at Nova Scotia Power. This project includes investments in new wind generation, transmission infrastructure upgrades, and battery storage to help facilitate the transition away from coal-fired generation. It’s our responsibility. In fact, it’s our legal obligation to implement the policies that are legislated by provincial and federal governments to phase out coal and reach 80% renewables by 2030. But under the oversight of the regulator’s transparent processes, we are also obligated to ensure that we do that in the most cost efficient and affordable way possible for Nova Scotians. In addition to the planned investments discussed above, we are actively engaged in conversations with the provincial and federal government on how we can work together to fully achieve these climate goals. Approximately 70% of our three-year capital program will be invested in the state of Florida. We’ve seen strong customer growth in Tampa of approximately 2% per year. This growth helps us to manage the affordability for our customers to help offset the cost of the required investments to reduce the carbon intensity of the generation mix and to improve reliability. Our baseline capital forecast includes previously announced projects like the investments in solar, the Big Bend modernization and storm hardening, as well as new investments in battery storage to help provide the capacity needed to support renewable generation. It’s no surprise that Florida has a strong solar resource, which makes investing in solar generation at Tampa Electric both the right thing to do for our customers and for the environment. Since we acquired Tampa Electric just over five years ago, solar has increased from less than 1% to approximately 12% of our generating generation capacity, representing an increase of over 700 megawatts of generation. Our continued investment in solar will increase that to approximately 19% by the end of 2023. Solar continues to be in the best interest of our customers in Tampa, both economically and environmentally. In 2021, we also reached an important milestone in the Big Bend modernization project, achieving simple cycle commercial operation on December 1, right on schedule. Combined cycle commercial operation is on track to be delivered by the end of this year. Last quarter, I highlighted some of the key regulatory outcomes we achieved over the last 12 to 16 months that have supported the growth of our business. We’ve reached settlements at all over US affiliates, including Tampa Electric’s uncontested and unanimously supported settlement that was approved by the Florida Public Service Commission. More recently, the regulator in Grand Bahamas has issued its decision on the GBPC rate application, approving an increase of $3.5 million effective April 1 of this year. And as mentioned, last week, the regulator in Nova Scotia approved the final cost application for the Maritime Link. As I look forward, we continue to have a very active regulatory calendar in front of us. In December, the New Mexico Gas team filed a rate case with the regulator which, if approved, will see new rates effective January of 2023. The requested $41 million increase in revenues is principally to support continued investment in the reliability of the system. We expect to have a decision on this application by the end of 2022. In Barbados, we expect a decision from the regulatory process on Barbados Light & Power general rate application in the second half of that year. I’d also like to take a few minutes to talk about the general rate application that we filed last month here in Nova Scotia. The request includes an annual increase to non-fuel revenues of 2.9% and a fuel revenue increase of 0.8% in each of the next three years. This is the first general rate application filed by Nova Scotia Power since 2012. We see the GRA as an essential step on the path to a greener Nova Scotia and achieving the government’s 2030 carbon goals and we also understand that rate increases are never easy or popular, especially as we know that Nova Scotians are feeling pressure in all fronts, as the costs of food, housing, fuel and electricity all continue to rise. Our application to the UARB is in large part based on the need to make significant investments of as part of the provinces energy transition, the scope and scale of investment required to meet the government’s 2030 climate goals should not be understated and we will continue to do our part. When it comes to greening the grid, we’re proud of our track record. The GRA is an essential step that allows us to make the investments required to help the government hit its ambitious target. As we know, regulatory processes are complex and comprehensive. They can and, quite frankly, should include many strong voices and differing opinions from customers, consumer advocates, community groups, and government. We welcome that accountability and we believe that a rigorous regulatory process will result in a balanced outcome. We respect the role that Nova Scotia has expert independent regulator, the UARB plays in ensuring that rate applications are clearly and transparently justified and that rate decisions are based on the facts with benefit of input from all stakeholders. Since we filed our GRA on January 27, there has been significant discussion around the proposal we submitted to address the net metering program in the province. The reaction from the solar industry, customers and government was strong. We listened. We understand the concerns we heard and we have since withdrawn the proposal. As you know, we are seeing the debate over net metering play out in many jurisdictions. It’s a complicated issue and we recognize that we could have engaged more and communicated better on this. Our initial proposal tried to solve an issue of imbalance in the current rate design between customers. We were trying to do the right thing for our customers. It was certainly not our intention to hurt businesses in Nova Scotia with this proposal. We’re sorry for not working harder to address the impact this change would have had on those businesses. So let me explain what we were trying to achieve. First, let me talk about our commitment to solar power. Solar is absolutely part of helping Nova Scotia reach its 2030 climate goals. At Emera, we see solar as an exciting and important part of our clean energy future. At Emera, we have invested $1.4 billion in solar in Florida as part of the energy transition in that state but we have to recognize some basic facts. Solar is more valuable in southern climates because the energy is generated when it’s needed on hot summer days when air conditioning drives fatigue load. Unfortunately, in Nova Scotia, solar alone will not close the coal plants that today are required to supply energy to Nova Scotians’ peak load, which happens on cold winter nights. We need to continue to invest in wind, batteries, and transmission to import clean hydro from our neighboring provinces because these are the most cost effective solutions that offer the most reliability for customers in Nova Scotia. Next, let me talk about the challenges of net metering design. This is not unique to Nova Scotia. Utilities, regulators, governments and customer groups in many jurisdictions across North America have raised concern with net metering tariff design structures like that currently in place here in Nova Scotia. Many jurisdictions are trying to balance these programs to benefit all customers, not just for today, but into the future too. And we look forward to working with governments and stakeholders to find the right solution to this challenge for Nova Scotia. On behalf of the thousands of employees who work at Emera and Nova Scotia Power, I’d like to reiterate that we are 100% committed to building a cleaner and greener Nova Scotia. As you’ve heard me say many times, the greening of the grid and reducing the carbon intensity of the energy we deliver to our customers has been at the core of our strategy for over 15 years. But it’s more than that. It’s part of our culture. It’s what drives our team every day, and we are delivering. Nova Scotia Power has led one of the fastest energy transitions in Canada. This year 60% of our energy will be from renewable sources. It’s real progress, but it’s not easy. Over the last 10 years, we’ve accomplished this progress while keeping total rate increases including fuel in line with inflation. Decarbonizing our electrical grid is a complex endeavor, ensuring that the reliability of the grid as a whole is not put at risk. It also requires significant investment, which is why all jurisdictions that are working to reduce the carbon intensity of their energy, in Canada and around the globe, are seeing the cost of that energy increase. The fact is that Canada’s and Nova Scotia’s climate goals are very ambitious and to achieve them, we will need to transform how we make, deliver, and store electricity in less than 10 years, and to do that, we’ll need to work together constructively with governments, regulators, and all stakeholders. Before I pass the call to Greg, I’d like to take the opportunity to highlight two new board appointments. I’d like to welcome Paula Gold-Williams and Ian Robertson to Emera’s Board of Directors. Paul is the former President and CEO of CPS Energy and Ian is the former CEO of Algonquin Power utilities. Each bring more than 30 years of leadership experience in the energy industry, and will be tremendous assets to our Board of Directors. And with that, I’ll turn it over to Greg to take you through our financial results. Greg?

Thank you, Scott, and thank you all for joining us today. This morning, we reported fourth quarter adjusted earnings of $168 million and adjusted earnings per share of $0.64. For the year, adjusted earnings were $723 million and adjusted earnings per share was $2.81. Before we continue, I want to remind everyone that in Q4 2020, we recognized a $36 million award related to outstanding litigation, which represented $0.15 on adjusted earnings per share. Normalizing for the impact of this one-time award better highlights the performance of our ongoing business. Excluding the impact of the one-time award, Emera’s adjusted earnings per share increased 7% for the quarter and 11% year-over-year. Growth in adjusted earnings per share was primarily driven by continued growth at Peoples Gas and improvement at Nova Scotia Power as compared to the weaker 2020, lower corporate costs and higher earnings in our marketing and trading business. These were partially offset by stronger Canadian dollar and a higher share count. The stronger Canadian dollar has been a headwind throughout 2021, decreasing adjusted earnings for the year by $0.11. But despite these headwinds, the strong performance of our underlying business continues to drive earnings growth for shareholders, which I’ll take you through now. When you adjust for the impact of the legal award previously discussed, adjusted earnings per share has increased by $0.04 over Q4 2020, largely driven by strong operating results in our gas and Canadian utilities and lower corporate costs. Corporate costs decreased primarily due to lower operating costs, primarily long-term compensation costs, and corporate interest expense, partially offset by higher preferred dividend expense as a result of our issuances last year. Our gas utilities led by Peoples Gas continued to benefit from new rates and the 4% to 5% growth in its customer base. Excluding the impact of a stronger Canadian dollar, our gas utilities delivered $11 million of growth in earnings representing a 30% increase compared to Q4 of 2020. Weather is always a factor in the energy business but one of the strengths of our portfolio of utilities is geographic diversity, which played out well in 2021. In Nova Scotia, favorable weather conditions increased Nova Scotia Power’s earnings contribution for the quarter, and we saw a modest increase in contributions from our investments in the Maritime Link in Labrador Island Link. In Florida, we experienced less favorable weather than Q4 2020, which had benefited from colder than normal conditions. Tampa Electric also saw higher depreciation and amortization expense reflecting increased capital investment and the effect of the 2020 amortization settlement. These factors drove a decrease in earnings from that business this quarter. These were partially offset by higher AFUDC earnings, as we continue to invest in our solar and Big Bend projects and continued growth in Tampa Electric’s customer base. Similar to the previous quarters, the growth from regulated utilities was partially offset by a higher share count. Year-to-date adjusted earnings per share increased by $0.13 to $2.81. Excluding the impact of the legal award, adjusted earnings per share has increased by $0.28 or 11% year-over-year, driven by strong earnings growth at our gas and Canadian utilities, lower corporate costs, and a strong natural gas market that Emera Energy was able to capitalize on. Similar to the quarter, higher earnings in our gas utilities are driven by new base rates at both Peoples Gas and New Mexico Gas and continued customer growth at Peoples Gas. Peoples Gas delivered $77 million earnings representing a 48% increase over 2020 and the highest earnings in the company’s history. Given the strong performance of the business in 2021, we did not recognize any of the $34 million of accumulated depreciation reserve that was allowed for through the Peoples Gas settlement last year. We therefore continue to have access to this reserve through 2022 and 2023. Our corporate segment benefited from $35 million of lower interest expense primarily due to the retirement of corporate debt, lower interest rates and the strengthening Canadian dollar as well as $30 million in lower operating expenses. These increases were partially offset by higher preferred dividend expense as a result of the issuances during the year. For the year-to-date period, Emera Energy’s marketing and trading business delivered an impressive 37 million US dollars of earnings. While, this is outside of our $15 million to $30 million earnings guidance range, we believe the range remains appropriate over the long term. The February storm event in the Midwest sharply increased prices and drove volatility across the US, which the business was able to capitalize on in the first quarter. In the third and fourth quarters, we saw a surge in global LNG pricing, which enhanced the gas market pricing, the volatility in key geographies where Emera Energy operates. This is a good example of the upside potential in this business that we often talk about. The increase in the Canadian Electric segment is consistent with the factors that impacted the quarter as discussed a moment ago and contributions from our other electric utility saw a modest increase over prior year. US dollar earnings at Tampa Electric are relatively flat year-over-year, a strong performance in advance of new rates being in effect on January 1. In 2021, Tampa Electric were near the bottom of their earlier range, a shift in the trend that we’ve seen since the acquisition of Tampa of earning at or above the midpoint of the range. This type of ROV degradation is driven by regulatory like that is expected in the year of a general rate application as continued investment in rate base compresses ROEs. With new rates in effect on January 1 of this year, we expect earnings from Tampa Electric to be higher than 2021 and anticipate earning within the allowed ROE range. And finally, both FX and a higher share count provided headwinds for the year. Operating cash flow year-to-date is down at $3 million or 6% compared to 2020 primarily as a result of incremental fuel costs associated with Winter Storm Uri at New Mexico gas at New Mexico Gas and fuel under recoveries and across the portfolio. To show the cash flow changes in the underlying business, we’ve broken out the change in cash flow driven by the under recovery of fuel costs at New Mexico, Nova Scotia Power, and Tampa Electric. Excluding these under recoveries, cash from operations increased 8% over 2021 reflecting the strong underlying growth in our utility operations and lower corporate costs. Increasing commodity prices have been a headwind for our cash flow through 2021, beginning with Winter Storm Uri and the trickle down impacts on natural gas pricing that persisted in 2021. As I mentioned last quarter, we have regulatory mechanisms in place to recover these prudently incurred cost from customers. Tampa Electric filed a mid-course fuel adjustment in January in response to the continued high in natural gas prices. If approved, we will begin recovery of the $169 million in April, of which $70 million relates to the under recovered position at December 31. Recovery costs from Winter Storm Uri began in July of last year and are being recovered over 30 months. Nova Scotia Power is in a fuel stability period until December 31, 2022, so while the recovery of the $55 million won’t begin until 2023, the regulatory mechanism will allow for the full recovery of prudently incurred fuel costs over the longer term and while it remains a regulatory asset until that time. Access to these regulatory mechanisms allows us to reduce rate pressure and rate volatility for our customers, while ensuring our shareholders’ interests are protected. Our experience in 2021 did not change our views on our operating cash profile going forward, and we have a clear path to achieve our cash flow objectives. We are well-positioned heading into this year to deliver both earnings and cash flow growth, to continue investing in our rate base and growing our business or $8.4 billion capital plan, all while providing value to our shareholders and maintaining our investment grade credit ratings.

Thank you, Greg. This concludes the presentation. We would now like to open the call for questions from analysts.

[Operator Instructions] And we have a question for the line of Ben Pham with BMO.

Hi. Thanks. Good morning. I had a couple questions on the NSPA rate case. And I want to first off, how does the Atlantic Loop project feed into the rate case? You need some visibility on that before clearing the hearings and getting the decision like how it may flows to the rate case outcome?

Yeah, thanks. Thanks, Ben. It’s Scott. So look within the GRA, certainly, there’s important investments that are proposed as part of the journey to close coal plants. It would not specifically, at this point, include anything in relation to the Atlantic Loop but rather would focus on investments required in Nova Scotia. At the same time, obviously, we continue to advance our discussions on the Atlantic Loop, which is also an important part of the ability to transition off coal-generation at Nova Scotia over time.

Okay. And then also what’s the thought process around the ROE and if you get the midpoint the same with interest and earnings sharing mechanism, they also provide potential for a much, much lower downside potential or maybe not much lower, but slightly lower on the downside. Like what’s -- is there a number that you can pick up, that you are thinking about? I love just a rationale around that early change.

I think really, Ben, it’s just a reflection that the 25 basis points up and down, as has been the case of Nova Scotia for some time, is actually unusually very narrow. And with the amount of investments and the journey in front for Nova Scotia, it’s really just looking at that very narrow band and saying what’s appropriate, we believe appropriate for customers appropriate for the regulator to look at that band in the context of the volatility of a potential earnings for Nova Scotia Power and to make sure that it’s consistent with market practice. And right now, that 25% band seems inconsistent with market practice, but ultimately something that the regulator will determine as appropriate.

Okay. [indiscernible] and everything, and maybe one last one on the Caribbean, are you sure that the realized ROEs you’re generating in those businesses and just gives a sense of that earnings is a slight negative?

Yeah, I think -- Ben, it’s Greg. I mean, really, our Caribbean businesses is two businesses, it’s Grand Bahamas and Barbados. I’d say we’ve been tracking kind of at the allowed ROE at Grand Bahamas. The economy is coming back fairly well during COVID and particularly from an industrial side. We’re still seeing some challenges in Barbados, primarily because of lack of tourism and a lack of rebound in the economy, so the returns there have been a little bit softer. But again on hold, in total, the businesses are performing reasonably well in light of the circumstances.

Okay. Thank you.

Welcome.

And your question comes from Maurice Choy with RBC Capital Markets.

Thank you and good morning. If I could continue with the ECEI or the Atlantic Loop, you previously mentioned that you expected an update on this initiative in early 2022. Has there been any change in your view of timing be it in terms of months or quarters? And what is the top reason that could move this timing either earlier or later?

Yeah, Maurice, I think we’re still hopeful for more clarity on that mid-year. Certainly, I think, fair to say we need clarity on that this year and look, as I said before, we continue to be encouraged by the ongoing discussions and engagement with the federal government, with and by the provincial government, and also with our provincial partners. It’s a really complex project and hence working through those complexities and of course, is, as you would understand, governments in Canada, also challenged by a number of other active files and so it’s really just a matter of working through those complexities, but really focused on seeking clarity this year, we’re hoping a mid-year but certainly need clarity sometime in ‘22 in order to move this project forward.

Thanks. And just as a follow up, you mentioned the government’s have other active files going on. Do you see a material change in their view or their priorities in terms of energy transition versus those active files over the recent weeks?

No. No, I don’t think so at all. I am thinking about things like COVID and trucker protests and those kinds of things that are obviously very, very active. But no, I don’t see any shift on that one you asked.

Great. And if I could just finish off with a question on capital allocation. Greg, you mentioned that there’s a good runway of any transition investments ahead, including after 2024. And like many of your peers, you probably have a lot of tools at your disposal to raise funds, including your trip and ATM. Equally, you do have a number of assets that aren’t will be -- are viewed as non-core by the market. In your view, when would it be a suitable time to consider selling these assets to improve your liquidity, especially ahead of some of these large scale investments and potentially reduce EPS dilution?

So Maurice, it is Greg. I mean, we always take a look at all of our portfolio to see what makes the most sense from a strategic and a financial perspective. We have no plans. We’re happy with our portfolio now and have no plans to divest or anything, but we’ll continue to look at it. I don’t know if there’s an optimal or perfect time and whether or not we need to do something. But as we get greater clarity in terms of the timing of some capital investments in some of these large projects, at that point in time, we’ll start to look at what our funding requirements are and what’s the most cost effective way to raise the capital is in support of that. And that would include maybe divesting of some smaller assets but it may not as well and but we’ll make that determination at that time.

And greater clarity on investments, presumably, the ECI/Atlantic Loop is your next biggest project to consider.

Yeah, that’s likely the next biggest project, but the large capital in that would be towards the end of this decade, not in the next couple of years.

Really, Maurice, we just -- we continue to expect, so we continue looking at the portfolio and if we see a transaction that’s compelling from a shareholder value perspective, we look at it heard and, obviously, you’ve seen our ability or willingness and ability to look at that and to think about the portfolio and recycle capital where it makes sense, and we’ll continue to do that look through that lens.

Understood. Thank you very much.

Thanks, Maurice.

I’m sorry. Your next question comes from the line of Rob Hope with Scotiabank.

Good morning, everyone. Two shorter term kind of questions in nature. First off, NSPI in 2022, it looks like you’re saying earnings are going to be consistent versus 2021 level, yet sales volumes will be higher and you could have the potential for new rates there. What are the puts and takes you’re seeing at NSPI in 2021? And are you assuming kind of a positive outcome on your rate fling?

Rob, it is Greg Blunden. I mean, it’s one month in the year, so I think it’s a little early to be much more specific in terms of what we expect the year to be but, in general, I mean, the two biggest things that would be in front of us, from an uncertainty perspective would be the outcome of the rate case, in particular, the timing of when those rates would be effective. And of course, as always, weather and weather can be positive or negative from a load perspective and also from a storm perspective. And so, it’s hard to be much more precise, I would say, at this point in time, for 2022.

All right. Thanks for that. And then another sort of term question, the volatility and strength in gas pricing has persisted into 2022. Would we be correct in assuming that the gas businesses or your marketing business has had a good start to the year but too soon to kind of point it to the upper end of the longer term guidance there?

Absolutely. Yeah.

All right. Thank you.

Do you agree?

I agree with that.

Your next question comes to the line of Linda Ezergailis with TD Securities.

Thank you. Good morning. Wondering if maybe we could look at your -- some of your other application components to NSPI, specifically, your equity thickness. Just wondering how you converged on that request, given my sense that some utilities in North America would have even a higher equity thickness?

Hi. Linda, it is Peter Gregg from NSPI. Really as part of the preparation of the rate case, obviously, we do engage experts and look at utilities with similar risk profiles to ours in considering what is an appropriate equity thickness and in doing that, that’s where we landed with the move to 45% equity thickness by the end of 2024.

Go ahead Greg.

Linda, this is Greg. I might just say so there’s probably a couple things happening, there’s a phase in was done largely to the extent of lens on affordability for customers and we’re very, very sensitive to that and so we felt as appropriate to phase in over time. The other lens to is, what do we think the required capital structure is to maintain really strong investment grade credit ratings and so that was part of it, as well. And ultimately, in addition to what Peter said, we believe 45 is the right number, but we believe it’s also prudent to get there over a couple of years as opposed to immediately.

Thank you. And just as a follow up, recognizing that affordability is something you always keep at the forefront, and all of your considerations of a balanced application. I’m just wondering what -- if you got everything that you asked for, what would that translate into as higher earnings and normal weather and volumes on load? What would that translate into higher earnings in 2022, 2023 and 2024? And second part of that question is if I didn’t get everything that was requested in terms of a rate increase, what sort of costs could be deferred mitigate the net negative effect of that?

Yeah, I wouldn’t necessarily think of it, Linda, through what would it create from an earnings capacity perspective. I mean the basic math is not going to change and it’ll be a function of the rate base investment, the equity thickness, and the ROE and we haven’t asked for an increase in the ROE and as we discussed, the equity thickness is going through, but to the extent that rate base grows over time, and yeah, earnings will grow with that as well. Some of the other components, like, I think you mentioned load, I mean, that load will be nothing specific in this rate case is going to cause us to have a different view on that side. And I think you might had another -- there might have been one other part of that question, Linda, that’s escaping me because there is just 10 seconds.

Apologies. Yeah. Just in terms of if you don’t get everything you asked for, might there be some costs that you could potentially defer?

Yeah, no need to bother, Linda. I mean, it’s premature. And all these rate cases, it depends on how it’s structured. So as you’re very familiar, often rate decisions come out, for example, there’s certain costs that get deferred, there’s a change in depreciation rates, which means it has no effect on earnings. So it’s kind of premature at this point in time to determine what the outcome would be and what the likely impact of that would be.

Thank you.

You are welcome.

Your next question comes from Mark Jarvi with CIBC Capital Markets.

Thanks. Good morning, everyone. This one is for Greg. There used to be a slide where you guys talked in past of $2 billion, roughly, of operating cash flow, just with the fuel recovery item you flagged on slide 13, is there an ability to get to that level this year? Do you think that’s been pushed out a little bit in 2023?

No, I think just the opposite mark. I mean, nothing that happened in 2021 changes our view on what we’re going to generate from a cash flow in 20 -- sorry, 2021 changes our impact of what we think will have for cash flow in 2022. With the exception of any under recoveries, for example, on Tampa Electric that will get trued up in the mid-course correction. So if anything, our view on cash flow this year is probably even stronger than it was a month ago, just because of the timing of the fuel costs on a period-over-period basis.

Okay, great. And then can you give us a little more context in terms of the $2 million pullback per month in Nova Scotia blockade? Is there sort of a rolling average or I guess a binary and then maybe how you kind of come up with the access $2 million costs, if you’re shy on the Nova Scotia block?

See, Mark, the teams, obviously, are still going through the regulatory decision, but it is a $2 million per month calculation, and then gets factored against the cost of replacement energy and so -- and then that gets calculated at the end of the year. So, yeah, I think that’s the simplest way to describe it. And, as I say, though, the teams are still going through the details of the decision and getting more, more precise clarity on exactly the mechanics but the way I described it is in simplest terms how it out works.

But if you were, say, six months over and six months under but you still average 90, would there be penalties or would that kind of smooth it all out? Just trying to understand exactly how you get penalized for being short in a given month and whether or not there’s, sort of, again, like average over the whole year?

So the teams are still going through the details to make sure we understand the mechanics Mark but I think that the shortfall is calculated monthly, but the replacement energy, obviously, happens over a longer period of time. So that’s sort of the mechanics of the team still trying to -- we’re trying to try still to work through and make sure that we understand as part of the decision but the shortfall is calculated, yeah.

And, just going back to the question on your energy, you’re talking about the gas markets and how strong you are in ability to hit the upper end of rate expectation, anything in terms of transportation costs, you guys can comment on whether or not, sort of, relative levels versus -- like heading into 2022 versus where you were in 2021?

So we probably have a little bit less trend, of course, than we had in 2021. We’re not dissatisfied. As you know, that’s always a competitive bidding process and so it has gotten more expensive, because of the run up in gas prices, so we have to be very astute when we are bidding and it’s -- we’d rather lose it than overpay for it, to be honest. So we probably have a little bit less going into 2022 than we had in 2021. But again, as I said earlier, quickly, it is very much too early in the year to say anything other than we hope to be within our range, so that’s where we are.

Got it. Okay. Thanks for taking the question.

Your next question is the line of Andrew Kuske was Credit Suisse

Thank you. Good morning. I guess the question is really big picture and directed for Scott and it’s along the lines of the growth we’ve seen at Atlantic Canada in the last two years. We can pick any timeline you want but it’s been a pretty good news story in Atlantic Canada from population dynamics. How does that bake into your longer term outlooks for your core business?

So, hey, Andrew. So look, I think, obviously, being in a place where we’re starting to see some renewed strength of the economy is good news, on a bunch of levels, obviously, that’s certainly true for us in Florida and benefit from a strong and growing economy there. And so to the extent that the economy continued to strengthen, the population continues to increase, frankly, that helps to reduce rate pressure as we invest to make this transition towards cleaner energy. So I think it’s helpful and I think, as I say, it helps to reduce the cost on a per customer basis, the energy transition towards closing coal plants in Nova Scotia.

Okay, that’s helpful. And then maybe just related, with some of the issues that there have been with having transmission lines come from Canada into the US, does that one that being a better news story on a longer term basis for your decarbonization efforts is effectively hydro plants and whether they be Quebec or elsewhere in Canada, the easiest access route for them, may be places like Nova Scotia to effectively put clean power.

That’s certainly the proposition we’re putting forward that it makes sense to try and interconnect the region so that we can move energy around and recognize that both Quebec and Newfoundland and Labrador are blessed with hydro resources, that are many times, if not most of the time, more than they need themselves. And rather than moving that energy down to two US markets, let’s share within the region and help provinces like Nova Scotia and New Brunswick that still have thermal emitting sources to retire those coal plants and that’s really the whole fundamental thesis of the value, we think, to the whole region of the Atlantic Loop and the Maritime Link projects, both.

And if I could sneak in one more, is there any longer term prospect of revisiting your transmission project that you had going from Nova Scotia and the Massachusetts?

So it’s not a focus for us today. I’d say, Andrew, obviously, we know that there’s been some challenges in dealing with some of those other proposed transmission lines, but our focus right now is really trying to address the off coal and renewable targets here in Nova Scotia and as part of that, a transmission interconnect ideally to Quebec as part of the Atlantic loop and broader Eastern Clean Energy Initiative. So that’s really where our focus is here right now.

Okay, that’s great. Thank you.

Your next question comes from the line of Dariusz Lozny with Bank of America.

Hi, good morning, and thank you for taking my questions. I just wanted to, at the outset, ask about, I think the timeline for the retirement of the Trenton, one of the units there got pushed back by one year. Can you maybe just discuss that decision a little bit? How the process is going to procure replacement energy and whether there’s any risk of the timeline potentially moving back again, whether it’s another year or any other amount of time? Thank you.

Hi, it’s Peter Gregg from NSPI. Really what drives that our ability to shut coal is that we need to have available capacity inside Nova Scotia to be able to shut those plants down. There has been a delay in receiving the Nova Scotia block over the past several months, it is flowing now and that’s a positive development. And consistent flows over the Maritime Link will certainly aid in our ability to commit to a coal shutdown. As we go further into the rest of the plants, we’ve got Nova Scotia, obviously the Atlantic Loop comes into play, things like grid scale batteries come into play as do coal to gas conversions for the whole story and how to shut down coal. But to your trend finds direct question that is part of ongoing analysis and discussions around the confirmed timing of that and when we have that nailed down, we’re happy to share that.

Okay, great. Thank you. Appreciate that. If I can pivot over to Tampa Electric, earlier in the call, you alluded to the pending fuel [Technical Difficulty] your level of confidence on being able to achieve the full ask on the recovery there, particularly given the bill impacts that I think are estimated at maybe low-double digits per month, given the current inflationary environment that we’re in today.

Hi, Dari. This is Greg, I mean, I don’t ever want to speculate what the commission will ultimately decide but certainly, if you look at the track record of the commission and the other investor-owned utilities in Florida, including ourselves last year, generally, these approval of these mid-year course corrections go through without a whole lot of controversy and we wouldn’t expect this to be any different this year.

Okay, great. Thank you for taking my question.

You’re welcome.

And your next question comes from the line of Matthew Weekes with iA Capital Markets.

Good morning. Thanks for taking my questions. The first is just kind of broad. Anything new to report on BlockEnergy?

Yeah, so BlockEnergy, we continue to be really excited about. I can share with you that the pilot project is that entails 37 homes in Florida. These are homes that have been built and are being lived in are now starting to be live connected. The block system is now live and active and is performing exactly as we expected and so that continues to build our excitement around what this idea can do, what this technology can do as part of a clean energy transition. And so one of those stories, we’ll continue to share more, as developments move along, but happy to share that we did achieve that milestone last few weeks now with that pilot now live and on stream.

Okay, thanks. I appreciate that. And then my second question is just relating to capital costs on projects, whether it be solar or other projects. In the inflationary environment we’re in right now, are you seeing any sort of pressure on the cost side or any sort of meaningful increases in project costs above prior estimates? And how do you see that impacting things going forward? Will that largely be passed on? In the end, is that the expectation?

Yeah, look, it’s a really good question. And certainly team and I, I’m sure like teams in all companies and all sectors right now are spending a lot of time talking about inflation and supply chain risks, and the like, and certainly, we’re not immune to those things. But, fortunately, I will say, all of our major active projects are in good shape. We’re not -- most of the important procurement has already happened for the way the solar that we’re executing now for the completion of the Big Bend monetization, those kinds of things. But we are seeing some cost pressures that’s part of the team’s planning in order to impact those things and could have an impact on the capital programs that are in front of us over the medium to longer term. And the team is working really hard to make sure that we minimize those impacts.

Okay. Thank you. I appreciate the answer on that. That’s everything for me. I’ll turn it back. Thanks.

Thanks, Greg Blunden.

And there are no further questions in queue.

Okay, thank you, Don. And thank you all for your participation and continued interest in Emera. This now concludes our call for today. Have a great day.

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