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Good day and thank you for standing by. Welcome to the Emera Second Quarter 2021 Analyst 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, Mr. David Bezanson, Vice President of Investor Relations. Sir, please go ahead.
Thank you, Rand, and thank you all for joining us this morning.Emera's second quarter earnings release was distributed this morning via Newswire, and the financial statements, management's discussion and analysis, and the presentation being referenced on this call are available on our website at emera.com. Joining me for this morning's call are Scott Balfour, Emera's President and Chief Executive Officer; Greg Blunden, Emera's Chief Financial Officer; and other members of 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 released our second quarter results, and I'm pleased to say that we continue to see solid results and steady growth in our business. We delivered quarterly adjusted earnings per share of $0.54, an increase of $0.06 over last year, and year-to-date adjusted earnings per share of $1.49, up $0.22 over 2021, despite facing pressure from foreign exchange rates.Our team also continued to safely execute on our capital program and we're on track to complete our $2.4 billion 2021 plan.The team is also making significant progress on the regulatory fronts. Last Friday, we filed a settlement agreement related to our request for a general base rate increase at Tampa Electric. Unanimously supported by all intervening consumer parties, it's a balanced agreement that supports Tampa Electric and Emera's strategy to advance cleaner energy and investments in grid modernization and reliability, all the while never losing sight of affordability for customers.As you know, Tampa Electric has been significantly reducing the carbon intensity of its generation mix with major investments in solar and the Big Bend Modernization project. Today, Tampa Electric is Florida's top producer of solar energy on a per customer basis. This 3-year agreement allows Tampa Electric to continue this progress, providing great support for investments already made as well as those planned over the period, giving us confidence in our ability to continue to deliver on many fronts. If approved, we'll see an increase in base revenues of $122.7 million starting in 2022 -- these are all U.S. dollars -- a further USD 90 million in 2023 and USD 21 million in 2024.The agreement also creates the Clean Energy Transition Mechanism, which will allow Tampa Electric to collect revenue of USD 69 million annually over the next 15 years, starting January 1st of 2022 to recover the full carrying and [ dismantable ] costs of Big Bend units 1, 2 and 3. This, together with the base rate increase in 2022, that I mentioned, means rates will increase by USD 191 million, starting January 1st of 2022 and with the follow-on additions in '23 and '24. The agreement also provides for a 9% to 11% ROE band, with a midpoint set at 9.95% for rate making purposes and no other change -- no change to our equity thickness.Thank you to the team in Florida for their hard work in reaching this outcome. In fact, this agreement reflects the hard work of all parties involved in securing rate certainty through the end of 2024 for Tampa Electric customers, while positioning the utility to make continued investments in resiliency, customer solutions and a greener energy future.Tampa Electric settlement is the third important rate case in our U.S. utilities over the past year. As you'll recall, Peoples Gas and New Mexico Gas concluded rate cases last year. This is in addition to the successful application to recover [ residual ] costs associated with winter storm Uri in New Mexico and a mid-course adjustment for fuel cost recovery at Tampa Electric. This track record is a testament to the caliber of our regulatory teams as well as the quality of the regulatory jurisdictions where we operate. It also speaks to the collaborative approach we take that ensures balanced outcomes for all involved. I know this is not easy work and I want to take a moment to thank all that involved for their expertise and efforts.We also announced another significant milestone on Monday morning. Delivery of the Nova Scotia Block of clean energy from the Muskrat Falls hydroelectric project will begin to flow through the Maritime Link to Nova Scotia Power customers this coming weekend. This is a significant step that brings us closer to the shared goal of having 80% of Nova Scotia's energy coming from renewable sources by 2023.The Maritime Link was a bold idea that will deliver clean energy to Nova Scotians for generations to come. It's part of a long-term vision to support the energy transition in this region and we see the Maritime Link as the first step in the regional transmission interconnections that are critical to support more local renewables and enable continued carbon reduction in Nova Scotia, all moving us towards achieving the vision to achieve net zero CO2 emissions by 2050. The Maritime Link project was completed on time and within budget. It was an absolutely massive project, executed safely and expertly by the Emera team and many partners who helped make it a reality. Thank you to the Emera team and all our partners and stakeholders, who share our commitment to a greater energy future through building stronger regional connections.This project is the result of the vision and hard work of so many, including indigenous partners, provincial governments, the federal government, Nalcor, and countless local, regional and national partners. The commencement of the Nova Scotia Block flowing on the Maritime Link is a significant part of delivering on our climate commitment. With the Nova Scotia Block, Nova Scotia Power is on track to generate approximately 60% of its electricity from renewable sources by 2022. This helps deliver on Emera's overall commitment to a 55% reduction of CO2 by 2025.And in Tampa Electric, we continued the build-out of our solar program with 5.3 million pounds currently on an operating and another 700,000 to be installed this year. In early July, we released our 2020 Sustainability Report, which highlights our progress on all our environmental, social and governance commitments through December 31st of 2020. The report captures not only the progress we're making, but the commitment from our team to advance our strategy. We continued to enhance our ESG disclosures and remain committed to transparently reporting on the factors that are most important to our investors and stakeholders.Meanwhile, however, COVID continues to challenge many of our communities. While Nova Scotia case numbers remain low, case counts in Florida are concerning for everyone. Sadly, we've lost one of our employees yesterday, due to complications related to COVID-19. This tragic loss illustrates that this pandemic is far from over. This is a difficult loss for our entire team and we extend our condolences to those colleagues and family.I want to thank our employees for continuing to do their part, not only for our customers but also for each other, whether that is getting vaccinated, continuing to follow public health guidelines, and always keeping health and safety first of mind.You've heard me say it before, but our response to the pandemic has really highlighted the strength of our team and strategy. Emera is on solid ground. With significant progress on the regulatory front, we have good visibility into our cash flows for the next few years. And this allows us to focus our attention on growing the business by continuing to invest in our strategy of safely delivering cleaner, reliable and affordable energy to our customers.Before I hand it over to Greg to walk through our financials, I'd like to officially welcome Gil Quiniones to Emera's Board of Directors. Gil is currently President and CEO of the New York Power Authority. His 30-year career extends across regulated and unregulated utility markets, public utilities, and state and local governments. He is an energy industry leader with deep experience in driving innovation, new technologies and cleaner energy solutions for customers. Welcome, Gil; we're fortunate to have you on the Emera team.And now, I'll turn you over to Greg to walk you through our financial results. Greg?
Thank you, Scott, and good morning, everyone.This morning, we reported second quarter adjusted earnings of $137 million and adjusted earnings per share of $0.54. For the 6 months year-to-date, adjusted earnings were $380 million and adjusted earnings per share was $1.49. Our adjusted earnings exclude mark-to-market adjustments that I will discuss in a few minutes.Emera's adjusted earnings per share increased for the quarter and year-to-date, despite foreign exchange headwinds of $0.04 and $0.08, respectively. The Q2 increase of $0.06 per share was driven by a strong quarter in the Gas Utilities and Infrastructure segment led by Peoples Gas, with the segment contributing USD 10 million more than in Q2 2020. Peoples Gas continues to benefit from new rates and continued growth in its customer base. The timing of preferred share dividends also gave us a year-over-year increase of $12 million as we recorded 2 dividends in Q2 2020 and only 1 in Q2 2021.The Canadian utilities contributed modestly to the growth with a higher contribution from the Maritime Link and Labrador Island Link projects, and lower corporate interest expense as a result of our efforts to reduce corporate debt continued this quarter.On the non-regulated front, we continue to see better results at Emera Energy, due to strengthened market pricing and increased volatility. These positive changes were partially offset by the impact of a stronger Canadian dollar and by slightly lower earnings at Tampa Electric, which experienced increased OM&G depreciation, resulting from our continued investments in solar and Big Bend, and the effect of a regulatory settlement that led to an USD 8 million amortization credit last year.Adjustment for the foreign exchange impacts and the amortization credit in 2020, Tampa Electric was modestly up quarter-over-quarter. Year-to-date increases in adjusted earnings per share of $0.22 were due to higher earnings in the Gas Utilities and infrastructure segment, as discussed a moment ago, and better results in marketing and trading. Lower interest expense in corporate OM&G and the preferred share dividend timing also improved earnings in the first half of 2021 versus 2020. These increases over last year were partially offset by the impact of a stronger Canadian dollar, which negatively impacted our earnings by approximately $20 million or $0.08 in EPS. We continue to be partially hedged through the remainder of 2021 at a rate of $1.42 for approximately $25 million per quarter. And we look to layer on more hedges, as foreign exchange rates return to normal levels as we have seen recently.Recording of the amortization credit in Tampa Electric last year and the sale of Emera Maine added to approximately $0.05 or $14 million in earnings that we didn't have this year. And finally, higher share count reduced EPS by $0.02 in the quarter and $0.05 on a year-to-date basis.Overall, we are pleased with 2021 so far.Emera Energy's Q2 mark-to-market loss had a material impact on reported earnings. Many of you will remember that we had a similar situation in 2016. I'm going to take a minute to give a refresher on what is going on here.Emera Energy has a number of asset management agreements, or AMAs, with gas and power utilities and natural gas producers, where they buy or sell gas for a specific term and take a corresponding release of the counterparty's gas transportation or storage capacity. Mark-to-market adjustments on those AMAs arise on the price difference between the point where the gas is sourced and where it is sold. At inception, the mark-to-market adjustment is fully offset by the value of the corresponding gas transportation asset. Of course, the gas price has changed over the term of the AMA, which means the value of the transportation also changes.However, the 2 elements are accounted for differently. The gas's mark-to-market and the transportation is amortized evenly over the term. This results in some net mark-to-market gains or losses recorded in income. Ultimately, though, the gas transportation asset and the mark-to-market adjustment reduces to 0 at the end of the contract term.It is important to emphasize that these arrangements have no actual economic market exposure because regardless of the difference in value of the gas between the receipt and delivery points, Emera Energy has transportation capacity that enables us to move the gas to the point at which it is priced.Well, year-to-date, we have seen a decrease in cash flow from operations before changes in working capital can be largely attributed to a significant increase in gas costs at New Mexico Gas related to winter Storm Uri. Adjusting for that cash flow impact, cash flow from operations before working capital was up slightly over last year.And looking forward, there are a number of events that have occurred recently that will positively impact operating cash flow going forward, both in terms of incremental cash and greater certainty around the cash flow that we've been expecting. As a point of reference, every CAD50 million of cash flow improves our credit metrics by approximately 30 basis points.In Q2, we received regulatory approval for a mechanism to collecting $108 million of incremental fuel costs in New Mexico that we disclosed last quarter. Starting on July 1st of this year, we will collect the full amount plus carrying costs over a 30-month period. While simply timing, this will have the effect of increasing operating cash flow over the following 30 months. This will provide USD 43 million in incremental cash flow in each of the next 2 years as well as an additional USD 22 million in the second half of 2021.This month, we also received approval for our mid-course correction related to our fuel adjustment clause in Tampa Electric. As approved, it will provide for an additional USD 83 million in revenue over the remainder of 2021. And looking forward to 2022, we continue to make significant progress on improving our cash flow. With the rate cases of our 3 U.S. utilities behind us, our corporate interest costs coming down and the Maritime Link and Labrador Island Link soon contributing their full amounts, we will have a good line of sight to the strengthening cash flow positioning going forward.And with that, I'll turn the presentation back over to Dave.
Thank you, Greg. This concludes the presentation. We would now like to open the call for questions from analysts.
[Operator Instructions]We have our first question from the line of Ben Pham from BMO.
With Tampa's settlement recognized, you've got to get still approval for that and you had the decision on New Mexico Gas fuel costs [ and lows ] coming in. Do you have better confidence now in terms of where the cash flow is going to go in 2022?
Ben, it's Greg. We do. I mean -- I think it's fair to say we always had confidence, certainly, the settlement that we reached are in alignment with what our expectations would have been and I think it's fair to say what the expectations of the rating agencies would have been. So the target of 12% FFO CFO to debt in 2022 is very much achievable at this point in time.
Okay. And when you actually head towards 2022, you have a step change in the Florida business and then the cash coming in. Do you think you could be in a position where you get to self-fund your CapEx program post 2022? I know that's a bit of DRIP still in the back end, but as you look forward, is [ that increasing probability there ]?
Yes. I think that nothing's changed from our expectation of what our funding requirements are for the '21 through the '23 period. We'll, of course, refresh that in the fall, when we also refresh our capital forecast. But at this point in time, we're committed to maintaining our DRIP at the level we are. The ATM program is functioning quite well from our perspective and we'll continue to access that for probably in the $50 million to $60 million a quarter on average going forward for the next -- at least the next couple of years.
Okay. And can you guys comment, maybe high level, when you think about your CapEx program, there's some advanced metering investments in there [indiscernible]. Is there more to go maybe just broadly automation and implementing digital systems or whatnot? Is there an upside and opportunity for that in your plan?
Ben, I think it's broadly across the portfolio. As we continue to make investments to modernize the grid and make investments in customer-facing technologies, yes, for sure, that will be part of our CapEx plan going forward. There's aspects of that, obviously, within the plan now. Our AMI and smart meters have been obviously the most significant part of that, the part that we've talked about. But there have been other components of that as well across the portfolio. And so, for certain, that will continue to be an important part of our capital program moving forward and part of the transition that we're driving as well.
Our next question is from the line of Mark Jarvi from CIBC Capital Markets.
Just wanted to come back to the question around the funding and now that you've got the settlement agreement. Maybe, Greg, when you look at that sort of funding pie chart and you had equity at 15% to 25%, where this stands now? Are you kind of trending towards that middle, say, 20% equity? You talked about $50 million a quarter for the ATM. Is that sort of where you're guiding to the midpoint of the equity requirements you've planned before?
Yes, Mark, I'd say I don't think there's anything that would necessarily suggest that we'd want to tighten that range. I think that range for equity requirements over the 3 years is still appropriate. As I mentioned in response to Ben's question, we'll update that when we update our capital program later in the year. But at this point in time, I think that's the most appropriate guidance for us to have out there.
Fair enough. And coming to the Tampa, the fuel charge recovery, was there a bit of a drag in this quarter or last quarter in terms of just carrying a higher fuel cost? I'm just wondering on that $83 million of higher revenue that comes through on a new rate, is any of that a bit of a catch-up, or is that all just adjusting to where commodity costs are trending more in the back half of this year?
Yes. It's a combination, Mark, of a catch-up for the first half of the year as well as capturing what we expect the incremental fuel cost would be above what's in the base fuel cost of rates in the second half of the year as well.
And any way to sort of give us a little bit of color in terms of how much of a grind might have been on Tampa earnings in the last quarter?
So it wouldn't have any impact on earnings at all, Mark, because it just flows through the fuel clause.
Okay. Fair enough.And my last question, just on the Muskrat Falls, the Nova Scotia Block coming through now, what's sort of the backup plan? Or is there any unplanned outages on that or issues with your own transmission lines in terms of obligations on sort of renewable electricity, sort of, mix commitments and stuff in terms of how you guys either would be exposed on any penalties or how you would fill in, if there is any sort of temporary losses in that power coming through?
Yes. Mark, I'll start, and then Peter, I know he is on the phone and he can sort of backfill my answer.But broadly, we expect now with the Nova Scotia Block flowing, that will also enable incremental energy beyond the Nova Scotia Power block also to flow. We expect that will effectively allow Nova Scotia Power to procure the renewable energy that it needs in addition to that that's already being generated natively here in the province to be able to meet that standard.But Peter, over to you to add any more clarity.
Yes. Thanks, Scott and Hi, Mark. In terms -- if there were to be any transmission outages on that line, and it's part of our reliability planning, we need to ensure we've got a portfolio of resources that's available to fill in any gaps. And so, you see continuing -- we'll continue to utilize our coal fleet as we shut those down over the next number of years; we've got gas facilities, we've got existing renewables, we've got hydro facilities; we've also got the [ time line ] into New Brunswick. And so, we've got options and that's what we do every day. We have plan for those contingencies to make sure we can provide a reliable source of power.
Our next question is from Maurice Choy from RBC Capital Markets.
My first question is on Tampa Electric. You were obviously open to go right to the end on a fully litigated case, but you're also willing to engage in a settlement, which obviously was a route that you took. And you mentioned earlier that this agreement aligned with your expectations. But as you look at this package holistically, can you discuss the puts and takes that led you to accept this settlement? And also, how this deal may compare to the ones that your peers in Florida also filed? Do you go in this year [ as well as IPO yesterday ]?
Yes. Thanks for the question, Maurice. Archie, can you answer the first part of that question and then I'll answer the second?
Sure. Very good. Thanks, Scott. So, Maurice, I think what your first half of the question was, were we prepared to go the full distance on a fully litigated rate case; and we absolutely were. The team here was -- in parallel with the settlement we were working on, was busily prepping themselves for being on the witness stand during the hearing and preparing filing testimony, et cetera, et cetera. So we were fully prepared to go all the way. And we felt good and continue to feel good, both with the strength of our case and the value that it represented for both customers and shareholders.Our interest in engaging in a settlement to [ another ] opportunity was presented to us. It was really one of -- is there a way for us to work through this and achieve an outcome that we believe is equal to, if not better than what we might derive from a fully-litigated settlement and is there a way to do it that brings certainty to what the price increases will be for customers on the 1st of January of 2022. There are other reasons as well, reputational and otherwise, why we would have saw fit to engage with all of the consumer parties.The deal -- the agreement that we ultimately reached is one we feel really good about. For us, as an organization and where we sit today, it is a settlement that represents a significant derisking of our business. It is a prudency determination on all of the assets that we were seeking recovery for, as a 100% recovery on all of those assets including those that we intend to retire. So we feel really good about what we've achieved. For us, it certainly is -- it is a platform for growth, all at a pace that we believe customers can afford. And that is an important element for us as we work through this settlement.So when we look at the settlement, we look at it in its entirety as opposed to looking at any one element of it. And I say that because we look at it as an entire package of not just derisking -- an affordable pace, and a platform for growth, but we also look at it from the perspective of doability. And we know what we negotiated and we feel extremely confident that the agreement that we have reached will allow Tampa Electric to perform in the higher end of that ROE range. We don't view the 9.95% midpoint as a midpoint; we view that, quite frankly, as a starting point. And based upon what we have negotiated with the consumer parties, we are extremely confident that that is a starting point.I don't want to comment on what others in the state have negotiated. I mean the [ SFPL ] announced something yesterday and we haven't had a chance to work through that yet. We wish them well through their process. It does appear to have a pretty robust ROE. But without knowing the entire contents of the agreement, it's really hard to get a sense of how it compares -- how their settlement with a subset of their interveners compares to the settlement that we have achieved with all of our consumer parties.Anything else, Scott?
Yes, I think you had covered it. I think that largely answers the second question too, Maurice. I think, as Archie said, look, what we have in front of us, a settlement or agreement that we have in front of us, unanimously supported, I think will give us a clear pathway to approval. There is, of course, a process that needs to go through with the Florida Public Service Commission. In fact, obviously, with all of the intervening parties supporting that agreement, we have confidence in the outcome. And this settlement agreement will allow us to deliver on our plans; our plans for our customers and our plans for shareholders as well. So I think that's really been the right answer to the question and Archie's reference to, you need to look at things as a whole package, which is certainly what we've done, and we're happy with the settlement package that we've achieved.
And maybe just a follow-up to those comments. The 9.95% is your starting point and, obviously, the higher end is at 11%. Can you compare that expectation to what you've achieved over the last few years? From my recollection, it's probably around 10% or just above 10%. But happy to hear your thoughts on that.
Yes, Maurice, it's Greg.I mean I think it's fair to say that we probably -- and maybe one year might have been slightly higher than this or one year slightly lower. But I think we've generally been in around 10.25% to 10.50% ROE at Tampa Electric. And I think this settlement, in its totality, probably positions us well. But on average, we would expect to kind of maintain that level of performance at the utility.
Great. And just my follow-on question on the Investor Day that you've scheduled for December. Notwithstanding that you're obviously still waiting for a decision from the regulator in Florida, but what are perhaps 2 or 3 things that you're still waiting on over the next 2 to 4 months in order to provide us an update to the CapEx and funding plan?
I wouldn't say there's anything, Maurice, that we're waiting for from a regulatory perspective or anything like that. We're just going through -- it's a natural part of our planning cycle right now at Emera, where we're going through and reviewing capital plans with all of our businesses. And there's just some internal work that needs us to get rolled up and we will review that with our Board to make sure that we have their full support. And so, it's really more of an internal processing than anything else.
The next one we have from Rob Hope from Scotiabank.
Just a follow-up question on the adjusted ROE. So just want to further kind of clarify our understanding here. How -- what are the key drivers that will move you kind of to the upper end of the band? And then, through the agreement, do you think you will kind of start towards the upper end and then as a little bit of rate lag sets in, you could kind of drift lower to get you to that overall 10.25% average?
Yes. I mean I think the greatest variability that we'll see over the next couple of years is weather- and load-related, Rob. Obviously, we're experiencing some customer growth and we expect that to continue over the period. And with that customer growth, obviously, comes some load growth. We do have also step changes in revenue in both '23 and '24, which also helps. So again, on its whole, we would expect to maintain a fairly consistent ROE profile, with probably the variable being weather, then ultimately residential load as a result of that weather.
All right. And then just in terms of your kind of capital outlook, the opportunity is underdeveloped that you've been talking about for some time now, we'll call it, just under $200 million of potential CapEx this year and over $400 million next year. Where are we in moving those opportunities from under development into the secured bucket?
It's -- you've heard us articulate before, about half of it is projects related to the Atlantic Loop or direct investments in Atlantic Loop. And as we said, we expect to have greater clarity and be able to provide some additional color around that in the fall of this year. Some of the other projects, I can't say we're seeing necessarily material changes in it; we are seeing some progress in some of our utilities, New Mexico is an example, where we're starting to look at gas storage as an opportunity in reaction to what was experienced with winter Storm Uri. So there's a few things like that, Robert, but I wouldn't say there's necessarily anything significant to call out for you.
The next one we have from Linda Ezergailis from TD Securities.
A number of my questions have been answered, but maybe I'll switch to focus a little bit to your operating results.I'm wondering if you could give us a sense of the puts and takes in your operating expenses as it relates to any sort of inflationary pressures you're seeing versus any sort of ongoing or new productivity initiatives, especially perhaps leveraging learnings from remote learning and adopting new technologies during the pandemic?
Well, I can start, Linda, and then maybe Scott can add on. Obviously, it's a big question.I can say on the kind of our day-to-day operating expenses, like if you think of kind of corporate expenses and things like that, we're not really seeing any inflationary increases yet. But although I'm not sure what -- the level of activity would necessarily highlight that at this point in time because clearly, no re-traveling and some of those things. So we're still seeing a lot of benefits from that side of it. I think how -- what we've experienced over the last year, how that will continue, I think there's no question that the volume of travel, some conferences, things like that, investor conferences and things like that. I think there's no question, some of them will stay virtual. And I think we'll see some benefit from that side of it.On our core operating utilities, again, minimal impact so far, I would say, from an inflationary perspective. Maybe the area we're starting to see some is on things like poles and wires, kind of just the day-to-day maintenance of our system. But we're still -- fortunately, we're a cost of service utility, those inevitably get passed through to customers; a lot of our costs are labor and labor-related costs that are through agreements with unionized workforces. Interest rates are certainly being helpful. So I'd say, collectively as a whole, that's something we're watching. But it's not something that we've seen any kind of impact on our financial results to date.
Yes. I think in terms of cost efficiencies, Linda, -- I think sort of remote aspect of work, I'm not sure that I would point to anything of notable scale there. But where we are certainly seeing some efficiencies is we continue to invest in cleaner energy, things like the conversion of coal units to natural gas-fired units drives a lot of operating cost efficiency. The labor components of running a gas plant is much less than that of running a coal plant. So that's the same again when you think about renewables.So we're seeing those kinds of efficiencies as well, the impact of technology, smart meters and the impact there; taking away some of the manual processes that were required, not just the reading of meters as was required in Nova Scotia, for example; but even the ability to remote disconnect and reconnect were leading to roll the truck in order to perform that service. So we're seeing those kinds of efficiencies that the business is benefiting from and that's an ongoing focus area for us for sure.
And as a follow-on, recognizing it's not a significant part of your business, but it is one of the more variable aspects, your Emera Energy. I'm wondering if you can give us a sense of whether some of the hot weather we've been seeing recently, this summer, has translated into market dispositions and opportunities Q3 to date? And any sort of visibility or observations for balance of the year beyond Q3 would be helpful context.
So, this is Judy. So, I guess, I will answer the second one first. We're having a rational year in 2021than we had in '20 or '19. So I feel comfortable saying that we will be in our -- expect to be within our earnings range, which is USD 15 million to USD 30 million. I would say we're hopeful to be towards the higher end there, but the reality is about 40% of the year is still kind of happened in November and December. So I can't kind of -- I can't predict that as confidently as I can to say that we certainly will be within the range.There hasn't been -- there's been a little -- July has been okay, but certainly not as sweet as June was, I guess, how I would describe it. It's been hot in the west, but less so kind of in our prime territory; not that just not too exciting.
That's a good context. And maybe just as another quick follow-on. Recognizing that your annual planning process needs to run its course, I'm just wondering how any sort of conversations with both your equity and debt investors are informing your thoughts, going into that process around potentially expanded investor base? Are you seeing some of your sustainability initiatives and reporting and targets translating into potentially broader access to new classes of investors or potentially shifting your investor base a little bit? Any context around that would be helpful.
Yes. I'm not sure I would necessarily -- I mean it's an interesting question, Linda. I'm not sure I would necessarily say we've seen a really notable shift or extension. But I would say that we've been getting really good feedback from existing investors and prospective new investors, who are focused on the ESG space around our disclosure, around the language that we're using as it relates even to our carbon reduction initiatives and efforts. And look, we've been working hard to try and tell the story better. I think we've had a good story to tell for a long time. We just haven't really focused on telling it as well as we have in the last year or 2 and making steps that we did to really bring some robustness to our sustainability report, the most recent one issued about a month ago now, are not just telling the story about the carbon reduction efforts that have already been achieved, but what our plans and our goals are moving forward as part of our climate commitments.And I think, frankly, being candid with our investors around our visibility to achieving an 80% reduction by 2040, but the net zero component of our climate commitment being more visionary [ rather an ambition ] without the ability to have perfect line of sight as to how that could be achieved affordably as we sit today. So I think all those messages have resonated. And I think, frankly, within our 2 largest emitters, Nova Scotia Power and Tampa Electric, just even the clarity of the significant progress that both have already made in terms of carbon reduction, I think, has been something that shareholders have welcomed more clarity around the significance of the achievements that are made.
Our next question is from Andrew Kuske from Credit Suisse.
Your renewable power generation exposure has largely been tied to your rate base activities in your utility businesses in several jurisdictions. What appetite do you have to either build or acquire renewables outside of a regulated framework?
Yes. I mean, Andrew, it's a really good question and, of course, one that we have asked ourselves about. I think we continue to be comfortable with our approach, obviously, -- with an eye on the pace of investment, given its impact on affordability, but is to really focus on the transition of our generation base inside our regulated utilities towards renewables. Looking at it outside of our regulated service territories, we do look at it, we do think about it. Of course, our efforts with Emera Technologies today is, in a way, a part of that in terms of looking at how distributed renewable generation and backup storage, battery storage can be part of a system, whether that's inside our service territories or in the service territories of others. And so, that today would be our primary focus, but it's an area that we've looked at. But primarily our focus is rate-based investments at renewables and continuing to push along our BlockEnergy concept that Emera Technologies have developed.
So that's very helpful context. And so, maybe it's just really a function of so much growth within the embedded rate bases and you're trying to avoid rate shocks. And that's really the focus right now because it's effectively captive solar efforts, for example, in Florida?
Yes, exactly right. And we look at the risk return trade-off in doing something outside of the investment opportunity profile that we have now. And so we keep directing our capital towards those areas, where we think the risk return balance is most in favor of our shareholders.
One small question and maybe a bit of a blast from the past, but also ties into the renewable power side of things and really just on tidal power. Are there any initiatives going on on the tidal power side at this point in time?
Not by us. I know the province here in Nova Scotia continues to look at it, but no, we've obviously taken [ 2 kicks ] at that. And it's a really interesting concept, but it's a long way from being commercial. And so -- as I say, our capital continues to be focused on those places, where the risk return profile is to the best advantage of shareholders. And so that's not an area that we're currently pursuing.
Our next question is from David Quezada from Raymond James.
My first question here, just on Maritime Link. I believe there's a comment in the MD&A that you have the potential to purchase additional power from Nalcor under Energy Access Agreement. Just curious what would cause you to exercise that and how you could make use of it; potentially, I guess, flexibility on the cap and trade program or requirements in Nova Scotia?
Peter, are you comfortable to answer that?
Yes. I think Rick can add as well. David, I think it's certainly an option. And as we look to decarbonize our resource fleet, it makes sense economically to expand that source of power when you compare it to other options. I would say it is an option for us to further decarbonize us as we shut down coal. But we'll judge that based on how it stacks up to other options. As Scott mentioned before, as we decarbonize, the most important thing for us is that we do that in an affordable way. So we need it to be a cost-competitive option for us.
Yes. I think Peter said it great, David. I mean it really is -- it's something that's available to Nova Scotia Power if it's in the best economic interest of its customers. And so it's got that option to procure that energy. But if it can procure other energy or generate other energy for less cost, then it will do that. It really provides that incremental benefit to Nova Scotia Power planning and Nova Scotia Power customers as it relates to cost and affordability of energy moving forward. So I think that's probably the best way to describe it.Rick, is there anything else that you'd like to add? I wasn't sure if you were on or not, Rick?
No, no, you both have covered it.
Thank you.
Okay. Great. Appreciate it. And then maybe just one kind of high-level question in the U.S. Just wondering if you have any thoughts on how potential clean energy standard federally could affect things or, I guess, create opportunities maybe even across your footprint?
Yes. I think the way I'd describe it, David, is, look, we have -- as a regulated utility through regulation, we have an obligation to produce for customers the cheapest electron that is compliant to whatever the rules and regulations and legislation exists in that environment. And so, the renewables that Nova Scotia Power has been investing in over the last few years has been part of that journey to meet the 40% renewable requirement that was set provincially here.The renewables, that are being invested in Florida, have been made on the basis that they are the most cost-effective sources of energy for the overall mix for Tampa Electric. So to the extent that there is a renewable standard that's imposed, it's another consideration, it's another factor as it relates to the generation planning for Tampa Electric if it's a U.S.-based or Florida-based standard. That may change, i.e., accelerate the pace of investment in order to produce that cheapest electron that is compliant with regulation.So it would be directionally positive. But in the moment, Tampa Electric continues to decarbonize its fleet, both with things like Big Bend Modernization and the investment in renewables because it's in customers' best efforts now even before consideration of a renewable energy standard. So it's not holding us back from doing the right thing for customers today. If there was a change, obviously, Tampa Electric would factor that into its own planning and that might cause an acceleration. But we also want to make sure that we're balancing affordability for customers at all times and that would be part of the planning as well.
Our next question is from Dariusz Lozny from Bank of America.
Just wanted to clarify and follow-up on the inflation comments from earlier, specifically as it relates to your solar initiatives in Florida. Are you seeing much as far as inflationary pressures of the panels or things like that? Or -- it sounded like maybe the answer is no. But I'll let you respond there.
Archie?
Yes, happy to take that. Dariusz, we're not seeing any inflation on the panels because we would have purchased those in advance. We have a long-term agreement with First Solar at fixed pricing that goes out for the full term of the construction period; and that goes beyond just the panel; it goes to the inverters, the trackers and other elements that we had at the safe harbor as part of that -- of those investments in order to secure the investment tax credit. So we're seeing some inflation on things like the steel that's used for the posts and some other smaller aspects of the projects, but nothing substantive that changes the economics of those investments.
Okay. Excellent. And one more if I can. Just now that you've -- the regulated outlook is relatively derisked following the proposed settlements in Florida. Just curious how you're thinking about your dividend now, in the near term, and the intermediate term, as far as the growth or potentially the payout ratio? Just curious how you're thinking about.
Yes. I don't think we're thinking about any differently today than we were last week or last year. And obviously, the -- any change in the dividend is always a purview of Board of Directors. But it's typically a discussion that we have on an annual basis, typically in the fall. And look, when we set the dividend growth target at the level that it currently is, we did that with an eye to the long term as to what we believed was sustainable over the long term. Of course, our guidance period will be adjusted from time to time. But really had a view as to what do we believe the earnings growth potential of the business is on an EPS basis and looking to ensure that we see an earnings growth potential that exceeds the rate of growth of the dividend over the long term.And that's how and why the dividend growth target of 4% to 5% was set a few years ago, and we continue to look through that lens and with that outlook today as we have before.
I am showing no further questions at this time. Mr. Scott Balfour, please continue.
Okay. So thank you everybody for participating in the call and we look forward to our call as part of the third quarter. I wish everybody a healthy and safe balance of the summer.
Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect. Have a great day.