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Good day, and thank you for standing by. Welcome to the Emera First Quarter 2021 Earnings Call. [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, Erin Power, Director of Investor Relations. Thank you. Please go ahead.
Thank you, Chris, and thank you all for joining us this morning. Emera's first quarter earnings release was distributed this morning via newswire, and the financial statements, management's discussion and analysis and the presentation being reference on this call are available at our website at emera.com.Joining me for this morning for the 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, Erin, and good morning, everyone. This morning we released our first quarter financial results, and I'm pleased to say we're off to a solid start this year. Our business continued to perform well and delivered quarterly adjusted earnings per share of $0.96, an increase of $0.17. We continued to execute on our capital program and we're on track to invest over $2 billion this year. And on the regulatory front, following important rate case settlements for Peoples Gas and for New Mexico Gas last year. We've now filed a base rate application for Tampa Electric. Our financial results and the underlying drivers of our growth this quarter highlight the overall strength of our business. We continue to see stronger earnings growth from our U.S.-based utilities and our reduced corporate interest costs reflect the steps we've taken to strengthen our balance sheet. And our marketing and trading business continues to provide low-risk opportunity for us to earn strong returns when market conditions present, as they did this quarter. All of our major capital projects remain on-time and on-budget, while our teams continue to follow the enhanced health and safety protocols we put in place last spring as part of our pandemic response plans. We remain committed to investing between $7.4 billion and $8.6 billion through the end of 2023 in renewable and cleaner generation, system reliability and integrity, infrastructure modernization and customer-focused technologies such as smart meters. Our investments are expected to drive robust rate-based growth of 7.5% to 8.5% on an average annualized basis over the period. Carbon reduction has been core to Emera's strategy for more than 15 years. It's been a key driver of our growth and it's what inspires our culture of innovation. In February, we announced our climate commitment, a set of clear, future-focused decarbonization goals. And we also shared our vision to achieve net-zero emissions by 2050. This commitment builds on our successful track record of meaningful carbon reductions already achieved and highlights our dedication to eliminating coal and advancing decarbonization.We're encouraged by the alignment with customers and policymakers who are also driving towards a lower-carbon future. Our proven strategy and successful track record positions Emera well to help lead the energy transition, but critically, in doing so in a way that never loses sight of affordability and reliability. We fully expect that opportunities for continued and incremental investment will present themselves as a result of our dedication to reducing our emissions and the global shift to a cleaner economy. And this in turn will also continue to drive long-term value creation for shareholders.The Atlantic Loop is an incremental opportunity we are pursuing, and while this remains a complex idea with many partners and stakeholders, we continue to be encouraged by the momentum and the engagement from the federal government, provincial governments and our utility partners. We hope to have more to say about this project initiative later this year. Our ESG commitments are core to our strategy, and while our environmental commitments are driving our capital investment program, our social and governance commitments shape our culture of doing the right thing for our customers, communities, investor and each other. Whether it's our commitments to inclusion and diversity across the business, continuing to advance our best-in-class corporate governance or being an employer of choice everywhere we work; our ESG efforts speak to the core of who we are. At Emera, our top priority is always safety. We're committed to an Emera where no one gets hurt ever. This means fostering a safety culture where team members are personally responsible for their own safety and safety of others and are empowered to speak up and act when they see potentially unsafe conditions or behaviors. Over the last number of years, we've seen our safety record improve and in 2020, we achieved our best ever safety results with the fewest number of injuries ever recorded in our business. This is a significant accomplishment in any year, but especially so given how we adapted and added new protocols in response to the global pandemic. However, recent contractor fatalities and serious safety incidents across our business tragically highlight that the work in this important area is never done. But I'm encouraged by the team's commitment and I can tell you that we are more resolved than ever to achieve an Emera where no one gets hurts.Before I pass the call over to Greg to take you through the financial results, I want to briefly update you on the Tampa Electric rate case. Early last month we took the next step in the regulatory process and filed our petition with the Florida Public Service Commission. Our request includes an increase of base rates of USD 295 million in 2022 and an incremental USD 130 million over 2023 and 2024. If approved, these base rate increases support and enable the significant investments in cleaner, greener and smarter energy solutions all while keeping rates among the lowest in Florida and below the national average. As I've noted in the past, our rate request is relatively straightforward. About half the revenue ask is related to major capital items: smart meters, Big Bend modernization and solar investments. Another 40% relates to depreciation expense to increase depreciation rates in line with the depreciation study filed last December and to recover accelerated depreciation and dismantlement costs associated with the early retirement of coal units 1, 2 and 3 at the Big Bend station. The remainder of the increase is for other smaller items. We expect the decision from the Public Service Commission later this year to allow for new base rates to be effective January 1, 2022. Finally, before I turn it over to Greg to take you through the financial results, I'd like to take a moment to thank and congratulate Nancy Tower, who officially retired as President and CEO of Tampa Electric last week. As you know, Nancy had an impressive career at Emera. She's been a key part of our growth story, too. Her accomplishments are many, and we're very grateful to have benefited from her leadership over the years. On behalf of the entire team, thank you, Nancy, you will be missed. With Nancy's Retirement, Archie Collins, who's with us on this call, officially assumes the role of President and CEO of Tampa Electric. Archie also has a long history with Emera, and most recently, has been part of the Tampa Electric leadership team. He's a natural successor to continue the positive momentum of the Tampa Electric team as they continue to deliver value for customers, cultivate a strong safety culture, reducing carbon emissions and driving growth at the utility. Overall, I'm pleased with our solid start to 2021, and I'm incredibly proud of the team and how they continued to respond to the challenges of the global COVID-19 pandemic. Despite being asked to change the way they work to keep themselves and each other safe, the team hasn't missed a beat. Our businesses continue to perform well, and our teams continue to deliver the energy our customers need. Looking forward to the rest of 2021 and beyond, I remain confident that Emera is well-positioned to continue to advance our strategy and deliver on our financial commitments. And now I'll turn it over to Greg to take you through the financial results. Greg?
Thank you, Scott, and thank you all for joining us today. This morning, we reported first quarter adjusted earnings of $243 million and adjusted earnings per share of $0.96 compared to $193 million and $0.79 in the same period last year. As I'll take you through in a moment, growth in adjusted earnings per share was primarily driven by our U.S.-based utilities, lower corporate costs and improved earnings in our marketing and trading business, partially offset by a stronger Canadian dollar and a higher share count. Our utility operations and the corporate services that support them are the driver of Emera's growth. Since 2017, the first full year with TECO in our portfolio, these operations have been generating predictable and consistently increasing adjusted earnings per share, driven by investments in rate base, disciplined O&M management and working constructively with our regulators and customer groups. Between 2017 and 2020, regulated and corporate EPS grew by 5%. Over the same period, we saw our corporate interest costs trend lower, largely due to our strengthened balance sheet and in 2020, we're seeing these trends continue. With over 95% of our earnings coming from regulated operations on an annual basis, the overall quality and predictability of our earnings and cash flow is high. And the continued execution of our strategy, making investments to safely provide cleaner and more reliable energy to our customers while ensuring that energy remains affordable, will continue to drive growth in earnings, cash flow and dividends. Most of our unregulated earnings are attributed to Emera Energy. Emera Energy's earnings have historically been positive on an annual basis, but they will vary both quarter-to-quarter and year-to-year, depending on market conditions, causing volatility in our consolidated results. While their financial results are not as predictable as those from our regulated business, Emera Energy's low-risk operations provide us with the opportunity to generate earnings and cash flow upside when there is market opportunity. And in this quarter, our unregulated earnings per share grew by $0.07, primarily due to improved earnings from our marketing and trading business. It hasn't been an easy time for this business over the past few years, but the February winter storm event in the Midwest drove pricing volatility across the U.S. Emera energy was well-positioned to benefit from this volatility while maintaining supply to their customers. And now I'd like to turn our attention to the details of the regulated and corporate earnings. Growth in the first quarter was largely driven by lower corporate interest and long-term compensation costs, new base rates and customer growth at Peoples Gas and higher AFUDC earnings and customer growth at Tampa Electric, partially offset by a stronger Canadian dollar and a higher share count. Pretax corporate interest costs were lower in the quarter by $13 million, primarily due to the retirement of the debt from the proceeds of the sale of Emera Maine last year. Lower short-term interest rates and a stronger Canadian dollar also contributed to the decrease. This is a continuation of a trend that we have seen since the second quarter of 2020 and reflects the steps we've taken to strengthen our balance sheet. Pretax corporate OM&G was $16 million lower in the quarter. Of this variance, $12 million relates to lower long-term compensation costs. This decrease was driven by differences between Emera's 50-day average share price leading into the quarter end and our share price at quarter end. Because these gains are driven by the timing and trend of share price movements, they are likely to reverse over the balance of the year. Excluding the impact of a stronger Canadian dollar, earnings from our gas and infrastructure segment increased by $14 million over the first quarter of 2020. Growth was primarily driven by new higher base rates at Peoples Gas and New Mexico Gas and strong customer growth of 5% in Peoples Gas. First quarter earnings from Tampa Electric were also solid. Excluding the impact of a stronger Canadian dollar, their quarterly earnings contribution increased by $9 million, driven by continued investment in the Big Bend modernization and [ non-sulfur ] solar projects, partially asset by less favorable weather. Compared to the first quarter of 2020, milder weather reduced earnings by USD 8 million. Earnings from our remaining utilities were relatively consistent quarter-over-quarter. However, I will pause to mention the results at Nova Scotia Power. Here in Nova Scotia, we experienced an incredibly mild winter. Between November and March, weather conditions were some of the mildest we've seen in the past 50 years. Unfortunately, for Nova Scotia Power, this created an earnings headwind. Because Nova Scotia Power is a winter peaking utility, it will be very challenging for them to make up the earnings lost in this quarter over the balance of the year. As a result, we have updated our earnings guidance to reflect the expectation that they will earn in the low end of their ROE band this year. And finally, both foreign exchange and a higher share count provided headwinds. Fortunately, we are partially hedged against FX movements this year. And at the end of the first quarter, we had $75 million of U.S. hedges remaining at a rate of $1.42. As these hedges roll off, the realized gains or losses will mute the impact of FX movements, such that $0.01 change in the FX rate will move annual adjusted EPS by about $0.01 through 2021. On a unhedged basis, that same $0.01 change in FX rates would move EPS by approximately $0.02. Before we open the line for questions, I would like to take the opportunity to highlight the expected upcoming step changes in our operating cash flow. As you know, over the past couple of years, we have been focused on strengthening our balance sheet. Since 2018, we have retired over $1 billion of holding company debt, reduced our holdco debt to total debt ratio to below 40% and returned to our target capital structure, all while maintaining sufficient liquidity. We've also become more regulated, which has improved the quality of our cash flows. And while the select asset sales we effected temporarily paused our cash flow growth, we always knew there were significant cash flow events on the horizon. Over the past 12 months, our business has generated $1.4 billion of normalized operating cash flow. And while the results this quarter include the cash flow impacts of the USD 110 million of incremental gas costs incurred at New Mexico Gas, these prudently incurred costs will be recovered from customers over a time frame to be finalized with the New Mexico Public Regulation Commission. By the end of 2022, we will see our operating cash flow increasing significantly to over $2 billion, driven by a few events. If as approved, the Tampa electric rate case will generate an incremental USD 295 million of base revenues and an expected incremental USD 280 million of operating cash flow. In the second half of this year, we expect the Labrador Island Link will be commissioned. Once commissioned, our current noncash earnings will convert to cash, increasing our operating cash flow by approximately $75 million. And new base rates that Peoples Gas and New Mexico Gas came into effect at the beginning of the year. We've seen incremental benefit of these rates in the first quarter of this year, and we'll see further upside over the balance of the year. And finally, we expect to continue to see natural growth in our operating cash flow. With this stronger operating cash flow profile, we have a clear path to achieve the target credit metrics set by the rating agencies. Our continued execution of our funding plan will support achieving our credit objectives. Last quarter, we issued $110 million of equity through our dividend reinvestment and at-the-market equity program and raised $200 million through preferred share financing. Our base shelf has an additional $300 million of capacity remaining. And as I've noted in the past, we have the balance sheet capacity to issue approximately $500 million of hybrid capital over the forecast period. Our solid start to 2021 sets us up well for the balance of the year. And while a quarter does not make the year, I believe we are well-positioned to deliver earnings growth and drive investment for our investors, while delivering cleaner, reliable, affordable energy for our customers. And before I turn the presentation back over to Erin, I would like to welcome Dave Bezanson back to our finance team. Effective May 1, Dave has assumed the role of Vice President, Investor Relations and Pensions, and I know you will all enjoy the opportunity to get to know Dave. Erin?
Thank you, Greg. This concludes the presentation. We would now like to open up the call to take questions from analysts.
[Operator Instructions] Your first question comes from Linda Ezergailis of TD Securities.
Congratulations to a strong start to the year. I'm wondering if you can give us a sense, some more context around your Tampa Electric rate filing. Specifically, as it relates to inflationary pressures, what are your embedded assumptions around there? And if inflationary pressures increase more than expected might there be any sort of relief? Or how are you thinking about that?
Linda, it's Scott. So thank you for the question. And let me start, and then, Greg, maybe you can help. And I know Archie Collins is on the line too. Certainly, Linda, as it relates to the rate filing, a lot of that capital that is a big driver of the rate requirement, the revenue requirement that's part of that rate case, is already well in motion. In a lot of cases actually, either the work is already complete or well advanced. And certainly, much of it has been cost controlled, not all of it, as some of the solar program continues to advance. But of course, smart meters, Big Bend modernization work is all well advanced with all major equipment and labor costs already committed and contracted or procured or in some cases, even in place. And of course, as I mentioned, the rest of the revenue ask really relates to depreciation, which doesn't impact things as much. Now as a broader sort of override lens on inflation, Greg, anything that you can add to Linda's question?
Linda, maybe just a couple of things. I mean, we kind of think of our inflation, I guess, exposure, if you will, in that particular business through a few different lenses. Obviously, to the extent that it resulted in higher commodity prices or fuel prices, in particular, that would flow through the fuel adjustment mechanism that we have. We've done a pretty good job of terming out our debt. So we don't have a lot of risk from an interest rate perspective. Obviously, we may see some on the capital side. And if that's the case, then obviously, the capital that we're investing could be slightly higher. But then really, the area that might -- more on a shorter-term basis impact us would be just on our day-to-day operating costs. But with the -- we can control the labor through our existing labor agreements and those kinds of things. So there's probably a relatively minor piece that we would have a little bit of exposure. We did build in an inflation assumption that we think is sufficient in the rate case filing. So at this point in time, I don't think there's anything that you should be overly concerned about.
And as a follow-up, I just wanted to also get some more of your thoughts on your financing plans, recognizing that you still have some room on your at-the-market program. Is it reasonable to assume that, that still is a lever that could be likely? And just maybe some more thoughts on how you might term out your -- potentially -- your drawn credit facilities and how any sort of thoughts of dividend policy past 2022 might inform how you approach your permanent financing plan?
So Linda, it's Greg. Let me start. So I think you accurately characterized it. We're happy with our ATM program as well as our DRIP. We're going to continue with those 2 mechanisms to raise common equity. We find it very cost-effective. It allows us to raise it when we need it, no earlier or no later. We've been kind of historically, over the last, I'd say, couple years, raising about $50 million a quarter on our at-the-market equity program. And I think that's kind of a run rate that you should probably assume and something relatively consistent with that on our DRIP as well. We're always looking at our credit facilities and is there an opportunity to term some of that out. You may have noticed in the quarter, we did exactly that at Tampa Electric with an $800 million bond issuance that effectively took their revolver down to 0 balance. So we'll continue to look at that, no immediate plan to do anything different over the near term. And then as far as dividend policy, I think that's ultimately a Board decision, and we would expect that our current guidance, there will be some updating of that in the fourth quarter of this year as we traditionally have done in the past.
Your next question comes from Rob Hope of Scotiabank.
First question is just on the opportunities under development. You continue to add, we'll call it, $170 million of potential opportunities in 2021. How are you seeing some of those shorter-term opportunities progressing? And then it looks like Atlantic Loop is more of a back-half kind of a next step for information there.
Yes, Rob, it's Greg. I think the projects that we have under development really haven't changed, as you highlighted. About half of it is Atlantic Loop or something like that. Now the Atlantic Loop is a collection of projects, some of which will go forward irrespective of the Atlantic loop, for example, a stronger interconnection between us and New Brunswick. So those projects are progressing reasonably well. We have some modest projects, I would say, still under development for 2021. And whether they land in this year or the early part of next year, I still think it's a little premature to know that for sure.
Yes. And maybe if I just sort of speak to the -- I know the reference to Atlantic Loop is what catches some attention with media and the like. But the path to continue to decarbonize Nova Scotia, the path to retire the coal plants in Nova Scotia involves much more than the Atlantic Loop, the idea of a transmission interconnect. That's certainly an important backbone enabling component of that journey to continue to decarbonize and close those coal plants. But there's a lot of infrastructure that needs to be built and enhanced in Nova Scotia as well. And so we'll see some of those things happen probably irrespective of the sort of the technically defined Atlantic Loop transmission project as Nova Scotia Power continues its journey to decarbonize and progressively retire it coal plants.
Excellent. All right, second question, just taking a look at the TECO rate case once again, it's been out there for a little over a month now. What has the feedback been from stakeholders and any opportunity for a settlement here?
Archie, you want to take that one?
Sure. Rob, I would say to this point, feedback from stakeholders has been balanced. It's been fair. I think there's a recognition that the investments that we've made or that we are making are things that customers are interested in. It's what society is interested in. We're decarbonizing. We're driving down the use of coal, stabilizing our fuel cost over time, and so modernizing our grid, improving resiliency, reliability. So I think that there's an acknowledgment that these are investments that are in the social interest and that over the long term, they're good for our customers. And so we've been pleased that, for the most part, that the feedback has been fair and balanced. From the perspective of a settlement, a settlement is always a possibility. But at this point, we are preparing ourselves for a fully litigated rate case. We have every expectation that that we have been preparing ourselves for that eventuality. If a settlement presents itself, we will be willing to engage. But we wouldn't think that that would present itself until much later in the process, probably after we've completed discovery. So we're open to it, but preparing to go right to the end of a fully litigated rate case.
Your next question comes from Maurice Choy of RBC Capital Markets.
And my first question speaks about Slide 12, which is a great disclosure from an operating cash flow perspective. Any color on possible puts and takes if the various components there change, particularly if I look at the Tampa Electric rate case of CAD 375, that's USD 280 million. And you mentioned that, that's in line with what you've asked. In the potential event that we don't get everything that we ask, where would you see the potential tailwinds to be to make up for your targeted operating cash flow?
Maurice, it's Greg. Yes, good question. I mean if you look at Slide 12 and the buildup of the various cycles, I mean, a couple of them have already been executed or it's a question of timing, in particular, ENL and our gas LDCs rate cases, which we've had settlements late last year. Obviously, the biggest piece is the Tampa Electric rate case. I will say that the combination of those 4 items identified on that page, probably increase our credit metrics, our CFO to debt or FFO to debt by somewhere is around 300 to 400 basis points. And so to the extent that 1 or 2 of these numbers turns out to be less than what we have illustrated here, we'll still be comfortably where we need to be from a credit rating agency perspective. So that's kind of the way to think about it. I think if you think of a rate case at Tampa Electric, I think the average in the U.S. is generally around a 60% to 70% success rate in terms of getting what you ask for. I think Florida probably traditionally has been at either the higher end of that or slightly above that. So I think it's fair that you could probably handicap that number by some amount, if you so choose. But even so, we'll still be comfortably where we need to be from a credit metric perspective.
Great. And just a follow-up to that, obviously, the first component only comes in 2022, whereas the rest of it, bits and bobs of it, come in this year. Any update on your discussions for this year's review, specifically 202,1 rather than 2022?
With the rating agencies, Maurice?
That is correct.
Yes. So as always, we have ongoing conversations on a regular basis with all 3 of the rating agencies: S&P, Moody's and Fitch. I don't know what the timing is of Moody's or Fitch to issue a report this year. But S&P just issued their annual report a few weeks ago and reconfirmed our rating and outlook, so there was no change in either. And we're just waiting to hear from the other 2 as to what their schedule is for the balance of the year.
Great. And if I could just finish up on the opportunity set beyond your base plan. You mentioned earlier that $1.2 billion haven't changed much this quarter. But I wonder if you could just elaborate a little bit more about recent developments, both in the U.S. and Canada, with regards to climate commitments. Have you seen an opportunity to increase that $1.2 billion, what kind of timing we should be looking at in terms of spend? And with that, any intent to take actions sooner around related to fund this potential increase?
Maurice, it's Scott. I think directionally, of course, what's happening, the focus, the intense focus that's on many stakeholders of pushing decarbonization and whether that's federally driven climate energy policy in Canada or the U.S. is, of course, directionally positive for a company like Emera. And obviously, our whole strategy is anchored, centered on, been delivering on decarbonization efforts and related investments for many years, almost 2 decades. So in that sense, for sure, it's directionally positive. And I think as we look for opportunities to accelerate decarbonization or to respond to the requirement to decarbonize faster if legislative impetus gets put into place, then obviously we're really well positioned to do that. And yes, I think that bodes well for what our CapEx profile and growth can continue to be maybe within the forecast period, but certainly beyond it. And so I think that's just why we are feeling confident about the positioning of the business and the appropriateness and the durability of our strategy right now, because it provides that opportunity as we continue to execute for customers to also be aligned with the accelerated pace that's being driven by many policymakers. Of course, one of the really important things in this, of course, is that as acceleration quickens, that does drive cost. And we're going to continue to work to ensure we're representing customers' interest as well as we can to ensure that it's also affordable and finding ways in order to accelerate the decarbonization, but still keep it affordable. And obviously, the Atlantic Loop project or more broadly, as we describe it, Eastern Clean energy Initiative for us at Atlantic Canada, is really born out of that idea of how do we do this faster, let's still keep our eyes on and manage the implication of costs for customers. So it keeps us encouraged about what the future holds. Nothing that will likely add much in a way of CapEx growth in 2021, but certainly, as we get out into the later part of the forecast period and beyond, I think these will be driving forces which should continue to drive Emera's growth for years to come.
And just a follow-up on that, you mentioned that legislation needs to be put in place. Do you view the ball be on the government side of the court in terms of putting next steps out? Or is it one for the industries such as participants like yourself to come up with solutions?
Well, I mean, for sure, we have to drive the solutions. But we also have to work within the parameters that get established for us within the range of legislation and regulation. And of course, most regulatory constructs require us to produce the lowest cost but compliant electron that we can. Not the cleanest. But the lowest cost and compliant electron. So to the extent that we can, as we are, the Big Bend modernization project in Florida, we're undertaking that because that cleaner energy, that transition from coal-to-gas at Big Bend station is more affordable for customers. It is less expensive. And therefore, that's a great self-driven initiative. The same with much of our solar investments right now. Those are all happening because they are cost-effective for customers. But at the same time, if there was, for example, a carbon pricing in Canada that the liberal government has, of course, proposed, higher carbon pricing means that that affordability lens looks different in 2030 to 2040, at $170 per ton of carbon, than it would if there was no price on carbon. And so that would require Nova Scotia Power to work with the provincial government to arrive at a solution within the parameters of that carbon tax or that change in legislation continues to produce the most affordable solution for customers while being compliant with the -- whether it's carbon tax or emission regulations or whatever the case may be.
Your next question comes from Mark Jarvi of CIBC Capital Markets.
Maybe just going back to the Tampa Electric rate case, is there anything that can be gleaned from the Duke Florida settlement in terms of their depreciation studies or anything relative to what you proposed so we can see whether or not staff might be on board with your proposal, just given that that's a substantial part of the step-up in rates?
I think I'd start this way and if Archie or Greg want to chime in, I would let them. But look, I mean, every rate case submission is different. So I think everyone would need to be careful. We need to be careful about interpreting the result of one rate case into another. Of course, we pay attention to that. We pay attention to the rate case filing that the Florida Power & Electric have done. But in our case needs to stand on its own and the merits of the capital that's been invested and the depreciation study, the independent depreciation study that has been done that helps to guide those discussions. And the team at Tampa Electric, I know, has put a huge amount of work in to ensure that as it's responding to the needs to invest that capital and address the appropriate requirements for depreciation and overall cost of the business that it's doing so prudently and with a lens on impact to affordability for customers. And so confident in that sense that the work that's been done and the rate case that has been filed with the support for that all stands on its own, very well thought through, very well-considered with benefit of expert opinions, and the team will work through process with stakeholders and the FPSC, as the year progresses.
Okay, and then for Greg, obviously, some proposals on tax changes in the U.S. but also in Canada, does that put you in a bit of a holding pattern in terms of positioning of corporate debt? Or any sort of updated thoughts in terms of how you might respond if there are some changes in taxation policies?
Yes. It's probably a little bit early to tell. I mean I think it certainly looks like if I start in the U.S., Mark, that the Biden Administration is looking to increase corporate tax rates. It really doesn't have any impact on our financing, other than our U.S.-denominated debt. The after-tax cost would be lower than it is today, but it doesn't really have any impact on us from that side of it. It looks like the discussions we're having around the thresholds for alternative minimum tax would be sufficiently above our taxable income in the U.S. So we shouldn't get caught by that at all. If I turn to Canada, really, it looks like a couple of themes that are emerging. One is the elimination of any kind of cross-border tax structures. We really don't have anything in place that is worth mentioning. So that's not something that we're very focused on at this point. And then I guess the last thing is, they're still working through the mechanics on, is there going to be any kind of interest deductibility limitation. which we have to be careful of, I think, in Canada because, obviously, Canadian utilities run at a much thinner capital structure. And I certainly wouldn't want to see us in a position where we couldn't raise incremental debt at the Canadian regulated utilities because of that kind of limitation. So I think there's some work to be done on that. It probably pushes us long-term, that means, which we really are effectively today, what it means is holding company debt is probably going to be raised in the United States as opposed to Canada is what I'd be speculating at this point.
That's great color. And my last thing, just going back to you, Scott, in terms of the balance of the legislation and regulation in terms of big initiatives like Atlantic Loop. Can you update us in terms of like, at this point, are you socializing what you're thinking with the regulators in Nova Scotia? Like how do you get to then come back to the table with your neighboring provinces and other people to discuss the Atlantic loop with enough confidence that you're putting us within the right boundaries of regulation and improving cost recovery?
Yes. Peter, are you comfortable to answer that?
I am, Scott. I guess what I'd say to that, is that it is a complex project involving multiple stakeholders, multiple provinces, utilities. And so we are having, I'd say, still early day discussions with all. And there's opportunity, I think, to bring more of those stakeholders into the discussions in the coming months. As both Scott and Greg said earlier, we hope we'd have something more to say toward the back half of this year. Scott, I don't know if you have anything you want to add to that?
No, I think that's exactly right, Peter. And Mark, I think the only other thing I'd say is, look, it's multiple stakeholders involved in anything like this around energy policy, and in our case, in Nova Scotia. As we work to ensure that as the changing landscape of energy policy federally, to the extent that impacts the province, the province is deeply engaged in that. And of course, Nova Scotia Power continues to work with, always works with its regulator and its stakeholders, and that process has started here now. Of course, there's not perfect clarity yet on any of these things, but keeping those stakeholders aware and involved and engaged through the piece, we're pleased that the province's awareness and support of something like the Atlantic Loop requirement, the federal engagement in helping to solve the challenge in Nova Scotia. But all of this is complex and multiple stakeholders involved, and Peter and the team at Nova Scotia Power are doing a great job in ensuring that engagement and alignment as best as possible.
Your next question comes from Ryan Greenwald, Bank of America.
In terms of further potential development opportunities, can you guys talk a bit about how you're thinking about any discrete opportunities coming out of the potential Infra bill in the U.S.?
Again, I think it's probably a similar answer, Ryan, is it feels a little premature. I mean, there's a couple of things happening. Obviously, there's the infrastructure bill, and we're looking at what that might mean for us, I'd say, probably not in the next couple of years, but as we look broader than that. And then, of course, there is more of a sensitivity in some of the markets, too, as well in terms about system resiliency, in particular, because of the events in Texas. So I'd say there's a couple of things that are happening, all very consistent with the themes that have driven our capital investments to this point. And we're looking to see what the opportunities may mean for us and for our business and for our customers. But we haven't concluded on any of those things yet.
Got it. And then just in terms of hedging, any thought process at this point given the pressure of late on FX in terms of looking out to later years? And just to confirm, you guys have no hedges beyond 2022 at this point?
That's correct.
Any thought process around implementing some now or still kind of too early at this point?
Sorry, I missed the first part of your question?
Just in terms of your thought process at this point in terms of implementing hedges for the later years, given the pressure more recently on FX?
Yes. We'll continually look at it. But at this point in time, we haven't put any incremental hedges on at these levels.
Your next question comes from David Peters of Wolfe Research.
Yes, I know you don't have a formal guidance range, but just curious back to the FX, if you could just comment on potential impacts for '21 and any offsets you have against those headwinds. I appreciate the hedges that you have in place. But I think originally, you had assumed a rate of $1.28 versus the $1.21 that we're currently sitting at?
Yes, that's correct, David. So in the current year, each $0.01 change in that in 2021 would be about to $0.01 in EPS. And for 2022, it would be about $0.02 in EPS.
Can you talk to any offsets elsewhere in the business that you're seeing to help kind of offset those pressures?
Yes. It's a good question. I don't know -- it certainly wouldn't necessarily be linked to it, but we're also seeing, as you've seen in our Q1 results, and I'm sure you've seen in many of the companies that you're covering, we're seeing things like, obviously, lower short-term interest rates than maybe most of us would have thought a year ago, which is certainly helpful. All of the capital that we're investing for better or worse is going in Tampa Electric and Peoples Gas and New Mexico Gas at a lower FX rate. So our capital requirements at a consolidated basis are slightly less. So there's a few things that probably help mitigate it a little bit, but it is a volatility that will continue over the balance of the year. There's no question about that.
Your next question comes from Andrew Kuske of Credit Suisse.
Scott, you mentioned a little bit about, effectively, the cross-border divide on decarbonization with pretty clear policies in Canada. And then obviously, you have a really robust solar resource in Florida. I guess, just on a longer-term basis, how do you think about decarbonization unfolding with a cross-border divide? And then when you start thinking about the interplay of demand side management, distributed generation, effectively customers having batteries in their houses; how does all that play out on a longer-term basis for you? And I know it's a big picture question, but how do you think about that now?
Yes. Well, I think, Andrew, it comes down to simple things like ultimately, we've always got to be focused on making sure that we're providing cost-effective solutions to customers. And so the team at Tampa Electric has done a fantastic job of -- if you think about the shift in the generation profile of Tampa Electric from just even when we acquired TECO back in 2016, now with 655 megawatts of solar that's in service, and another 600 megawatts planned that will take it to order of magnitude 15% of their generation profile. And then the coal-to-gas conversion, effectively, the retirement of 2 coal units and the conversion of another coal unit to high-efficiency natural gas. Again, just a massive change in not only the generation profile, but the carbon profile for Tampa Electric. And in that case, all doing it on a basis that is more affordable to customers than if they hadn't made those changes. And so really continuing to think about the business that way to, as I say, this culture of innovation, which is a big word and maybe it doesn't sound like it really should apply to any utility perhaps. But there's an element of that in driving the transition that has happened in Florida that has already happened and still needs to happen in Nova Scotia and frankly, in the Caribbean and our gas utilities too. And certainly, as we think about distributed generation and that trend, Tampa Electric there too is playing its part with looking at community solar with the work that Rob Bennett is doing with Emera Technologies, thinking about the role that we as a utility can play to enable and accelerate the use of distributed energy, the use of batteries being used now in our Caribbean businesses, in plans in Florida, in service now in Nova Scotia and the opportunity for more, which will be an important component of ensuring resiliency as part of the transition to more intermittent renewables. And whether those batteries are at customers' homes or parked in solar or wind generating facilities or at substations, it's going to be all of the above. And so the utilities have, I think, an important role to play in all of that. And I think that broader trend of policy, whether it's driven at the provincial level or the state level or the federal level or just by economics, is going to be a continuing driver of our capital programs and growth at Emera for many years to come still.
I appreciate those thoughts. I guess my second question still relates to cross-border divide, and it's probably more for Greg. And it's just in your CapEx slides in the deck. Do you see it being useful in the future to maybe just have the U.S. dollar CapEx for the U.S. business and then the Canadian CapEx? Obviously, you're a Canadian dollar reporting issuer and you have a translation rate in the deck. But do you feel that that will mask the growth of the underlying growth in the U.S. business that's happening on a U.S. dollar basis?
It's a good suggestion, Andrew. I mean, we tried not to overreact a year ago when the dollar was at $1.42 and rework a lot of that and trying to do the same consistency today, but it is a good suggestion. We'll take that away and take a look at it. Thank you.
[Operator Instructions] The next question comes from Patrick Kenny of National Bank Financial.
I just wanted to clarify guys on the Tampa filing what the process looks like if the U.S. corporate tax rate does go up to 28%? Is there an automatic adjustment to the revenue requirement? Or do you have to go back in for approval? And could there be a potential lag in realizing that cash flow uplift relative to the Jan 1 effective date?
Yes, Patrick, we've asked for a mechanism to recover that, but I think it's fair to say that you should expect some kind of regulatory lag on that. So even when tax rates went down, I think it was still a full year before that savings flowed back through to customers. So even with the mechanism improved, I don't think we'd see any impact of that until probably 2023.
Got it. And then just on the trading and marketing front here, you may have touched on it already, but can you quantify just how much of the performance in the quarter was simply extreme weather-driven versus perhaps structural in nature going forward?
Judy, over to you.
Okay. Well, I guess that's an interesting question. I mean the business generally makes hay in big weather events. So I don't know -- I mean, I can say -- let me put it this way. I would say we made somewhere between USD 10 million to USD 15 million of margin in what I'll call markets adjacent to where the most turmoil was. So I think of that as kind of benefiting directly from the Uri event. So after tax, that's probably $10 million to $15 million, I guess. The New England weather didn't really blow out at any time, but it was steadily cold through the quarter, and that's what we like to see. So prices in New England were kind of almost double what they were this time in the first quarter last year, but still kind of an average of $5 to $6 and peaking out at $14 or $15. So I would kind of call that a normal cold winter. So if I had to try to answer your question in some meaningful way, I would focus on what margin we earned kind of in adjacent markets to where Uri was really impactful. And like I said, that's somewhere between $12 million and $15 million of margin.
Okay. That's very helpful. And then just over on the Caribbean front here, any leading indicators you can speak to with respect to travel and economic activity, perhaps coming back later this fall to more normalized levels?
Yes. I think, Patrick, largely, I mean, really, our Caribbean interests are centered in Grand Bahama and Barbados. Of course, we have interest in St. Lucia and Dominica too, but really most of the substance of our Caribbean business is in those 2 islands. And their behavior is a little different. So a leading indicator in the Grand Bahama electric fleet is really very, very linked to the U.S. economy. So as the U.S. economy strengthens, I would expect to see the economy in Grand Bahama strengthen, of course, tourism will also help. There is -- there has been some shipping related, cruise ship related activity would be another one to look at. But the biggest one for Grand Bahama would be really just linkage to the U.S. economy. Barbados obviously is different. And there it's principally tourism driven. And so their tourism with the U.K., Canada and U.S. being primary components of that, of course, much broader, but those would be the ones to look at. So it's really tourism in Barbados and the U.S. economy for Grand Bahama.
There are no further questions at this time. I will now return the call to Ms. Power for closing remarks.
Thank you, Chris, and thank you all for joining us and for your interest in Emera. We look forward to speaking with you again next quarter. And if you have any questions in the meantime, please feel free to reach out to myself and the IR team.
This concludes today's conference call. Thank you for participating. You may now disconnect.