Emera Incorporated (EMA) Q2 2022 Earnings Report, Transcript and Summary

Good morning ladies and gentlemen and welcome to the Emera Q2 2022 Analyst Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session [Operator Instructions] This call is being recorded on Wednesday August 10, 2022. I would now like to turn the conference over to Dave Bezanson. Please go ahead sir.

Thank you, Michele, and thank you all for joining us this morning at Emera’s Q2 2022 conference call and live webcast. Emera’s second quarter earnings release was distributed this morning via Newswire and the financial statements, management’s discussion and analysis, and the presentation being referenced on this call are available on our website at emera.com. Joining me for this morning’s call are Scott Balfour, Emera’s President and Chief Executive Officer; Greg Blunden, Emera’s Chief Financial Officer; and other members of Emera’s management team. 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. Please 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 share that we continue to deliver steady, predictable earnings and cash flow growth. Our second quarter adjusted earnings per share increased 9% to $0.59 compared to $0.54 in the second quarter of last year. Operating cash flow is also up 9% over last year. For the year-to-date, adjusted earnings per share increased $0.02 to $1.51 compared to $1.49 last year. Similar to what we saw in both the second and third quarter last year, our reported earnings this quarter were impacted by mark-to-market losses at Emera Energy. Greg will walk you through the mechanics of these losses and our financial results in a few moments. Our regulated utilities delivered an 18% increase in adjusted earnings per share this quarter and 12% year-to-date, largely driven by strong results at Tampa Electric. Economic growth in Florida continues to drive meaningful customer growth at our utilities, over 2% at Tampa Electric, and almost 5% at Peoples Gas year-over-year. Customer growth is one factor that helps to offset the rate requirements to finance the major investments being made to reduce the carbon intensity of the generation mix and to continue to improve the reliability of the system. In the first half of 2022, we've deployed over $1.1 billion in capital and we're on track to deliver almost $3 billion in capital investment this year. We're working to complete the Big Bend Modernization and installed an additional 200 megawatts of solar in Florida at Tampa Electric by the end of this year. These projects are transforming the grid in Florida and both are progressing well. In Nova Scotia, we are continuing to advance the Eastern Clean Energy initiative, including the Atlanta Fluke [ph], which would enable the addition of more renewable energy onto the grid, the closure of coal-fired power plants, and improve grid reliability and resiliency. The recently announced investment in clean energy projects here in Nova Scotia by the government of Canada is a significant step in Nova Scotia's transformational energy journey, facilitating more wind energy in the province and a grid scale battery project that will be among the largest battery storage projects in North America. In the Caribbean, we recently commissioned the Clean Energy Bridge, which will deliver roughly 27% of the energy needed on the Island of Barbados. By replacing older infrastructure, this facility will reduce emissions, while improving grid resiliency and reliability for customers. And at Peoples Gas, we expect to have two renewable natural gas facilities online by the end of the year. Peoples Gas is the largest natural gas distribution utility in Florida and the first to deliver RNG in the state. When complete, these two projects will not only contribute to a cleaner energy future, they will deliver enough energy to fuel almost 10,000 homes. This is incredible progress on our ambitious capital plan especially as we continue to navigate supply challenges and proactively work to mitigate inflationary impacts on both our capital plan and in our business more broadly. So far, the effects of supply chain delays and inflation, and our capital spend has not resulted in any material changes to our capital plan. We will share our 2023 through 2025 capital plan during our Q3 earnings call. In June, we released our sixth annual sustainability report. The report highlights Emera's strategy in action and demonstrates the progress we are making towards a cleaner energy future and the role we are playing in building safer, more diverse and inclusive teams and communities. This year's report includes a detailed climate strategy that provides an update on our progress toward our climate goals and the work underway across the business to lead a responsible and just energy transition that reduces environmental impacts, while balancing investments in reliability and the impacts to customers, employees and the communities where we operate. Our clean energy journey began here in Nova Scotia, where we've led one of the most ambitious transitions to cleaner energy in Canada. We currently have over 600 megawatts of wind generation on the system at Nova Scotia Power and our investment in the Maritime Link facilitates the transmission of more than 500 megawatts of clean hydro energy from Newfoundland and Labrador. In 2021, Nova Scotia Power tripled the amount of renewable energy it delivers to customers and reduced their coal usage by 43% compared to 2005 levels. And later this month, we'll achieve another milestone in our decarbonization journey by taking Lingan Unit 2, a 148-megawatt coal unit here in the province out of regular service. In Florida, the investment in the Big Bend Modernization has allowed us to retire on coal-fired unit and convert another to high-efficiency natural gas. These investments and our ongoing solar investments will allow us to retire another coal unit in 2023, two decades ahead of its scheduled retirement. Since 2000, we've reduced our use of coal in Tampa by 90%. Closing coal units is critical to meeting government targets and community and customer expectations. Doing so in the most cost-effective way without putting system resiliency or reliability at risk for our customers, is our mission and a requirement of our regulators. And then ensuring these closures are done in a just and balanced way is core to our culture. We understand the impact to employees who work in these plants and to the communities where the plants are located. We continue to work closely with government, employees, unions and community groups to ensure a just transition, one that is anchored in transparency and collaboration. We're proud of our progress to-date, but as global demand for carbon reduction continues and policymakers target even faster time lines, it's important to recognize the significant and challenging work ahead. As I mentioned earlier, the recent funding announcement from the Government of Canada is an important milestone and it supports our commitment to minimizing the cost impacts of the energy transition on our customers. But while wind and batteries are an important part of the solution, the reality is that these investments alone are not enough to allow us to close the remaining coal plants in Nova Scotia or to achieve Nova Scotia's 80% renewable energy target by 2030. That's why we continue to advance the Atlantic Loop project. We believe this important transmission infrastructure project will play a critical role in a more integrated clean energy grid in Nova Scotia and is instrumental in achieving both the federal and provincial government's ambitious climate goals. We continue to work with all stakeholders to advance this project and are cautiously optimistic on the progress and recent momentum. With 2030 quickly approaching, we hope to have more to share on this project later this year. It continues to be busy on the regulatory front as well, with rate cases ongoing in the US, Canada and the Caribbean. The team at New Mexico Gas recently filed an unopposed settlement agreement with the regulator, which, if approved, will provide US$19 million in new rates effective January 1, of 2023. This will support our continued investment in pipeline integrity and reliability projects in the state. Rate cases in Nova Scotia and Barbados are ongoing with hearing scheduled to begin in the coming months. We expect to have resolution on these outstanding rate applications by the end of this year. It's an exciting, yet challenging time, in the energy sector. Our team continues to navigate complex economic, political and regulatory environments. And our proven strategy continues to deliver for customers, communities and investors. And with that, I'll turn it over to Greg to take you through our financial results. Greg?

Thank you, Scott, and thank you all for joining us this morning. Earlier today, we reported second quarter adjusted earnings of $156 million and adjusted earnings per share of $0.59, compared to $137 million and $0.54 in Q2 of 2021. Year-to-date adjusted earnings were $398 million and adjusted earnings per share was $1.51 compared to $380 million and $1.49 for the same period in 2021. Our regulated portfolio continued to be the driver of strong second quarter results. Contributions from our regulated utilities increased $44 million over Q2, 2021, or $0.14 of adjusted EPS. This was partially offset by higher corporate costs, lower contributions from Emera Energy and a higher share count. Our adjusted earnings measures exclude mark-to-market adjustments. Emera Energy's Q2 mark-to-market loss had a material impact on reported earnings. Many of you will remember, we had a similar situation several times before, including in the second and third quarter of last year. I'm going to take a minute to give you a refresher of what's going on here. Emera Energy has contracts with utilities, producers and other customers to buy or sell gas for a term that comes with access to the customers' transmission capacity. Mark-to-market arises on the price differential between the market price of the gas to source and where it is sold, which is fully offset by the value of the corresponding gas transportation asset. But because the gas is mark-to-market at each reporting period and the transportation asset is not, that results in some net mark-to-market gains or losses recorded in the income, with all such gains or losses, netting to zero by the end of the contract term. As always, it is important to emphasize that these situations have no actual economic market exposure, because regardless of the difference in the value of the gas between the receipt and delivery points, Emera Energy has a transportation capacity that enables it to move the gas to the point at which it is priced. Operating cash flow continued to grow, increasing $62 million year-to-date or 9% compared to 2021. The increase was primarily due to the 2021 gas cost deferral and New Mexican Gas from winter storm Uri and new base rates at Tampa Electric. Like many others, fuel cost is the area across our business, where we're seeing the most significant inflationary impact driven by global macroeconomic conditions. As a result, the cash flow increases from new base rates at Tampa Electric and growth in our businesses are partially offset by higher fuel under recoveries, primarily at Tampa Electric and Nova Scotia Power. As in the fuel under recoveries this year, we would have seen a 41% increase in operating cash flow, driven by the growth in our regulated utilities. As I mentioned on previous calls, we have regulatory mechanisms at all of our utilities to recover prudently incurred fuel costs from customers. However, we are mindful of the impact the sustained high pricing is having on customer bills. In addition to the robust efforts of our teams to mitigate the cost impacts from higher market costs, we are also committed to working constructively with our regulators and customer groups to best manage the recovery of these unexpectedly higher costs in a reasonable way as possible for our customers. Tampa Electric continued to deliver strong results with growth of US$24 million in earnings or 24% over Q2 of 2021, driven by new base rates that went into effect January 1, favorable weather and continued customer growth. Continued economic recovery in the Caribbean and the recognition of onetime proceeds at Emera Caribbean Inc. increased contributions from our Caribbean utilities by US$6 million quarter-over-quarter. Earnings from our Gas & Infrastructure segment increased US$5 million for the quarter, primarily driven by increased earnings arising from the gas transmission lease contract with a Florida utility operator that commenced on January 1. Peoples Gas also continued to benefit from strong economic conditions in Florida, driving growth in its customer space, as well as the recognition of a US$5 million amortization reversal, partially offset by higher operating costs, reflecting the growth of the underlying business. The weakening Canadian dollar increased earnings from US operations by $7 million for the quarter. Corporate costs increased $19 million this quarter, largely driven by gains on foreign exchange hedges recognized in 2021 that did not reoccur this year, higher preferred share dividends and the timing of share-based compensation expense and related hedges. Earnings from our Canadian utilities decreased modestly during the quarter, primarily due to slightly lower contributions from our transmission investments. And similar to previous quarters, the growth in earnings were partially offset by a higher share count. Year-to-date, adjusted earnings per share increased $0.02 to $1.51. Contribution from our regulated portfolio increased adjusted earnings per share by $0.26, partially offset by lower contributions from Emera Energy, higher corporate costs and a higher share count. Earnings from Tampa Electric increased US$47 million to US$214 million or 28% year-over-year from US$167 million in 2021, with the drivers for growth consistent with the quarterly results discussed a moment ago. Year-to-date contributions from our Canadian utilities increased $5 million compared to 2021, primarily due to the mild winter we experienced in Nova Scotia in the first quarter of last year. This year's results benefited from colder weather, which drove higher sales volumes in Q1, partially offset by higher storm costs and lower contributions from equity investments. Corporate costs increased $36 million, primarily driven by the timing of share-based compensation expense and related hedges, higher preferred share dividends and a gain on foreign exchange hedges recognized in Q2 of 2021. Year-to-date, Emera Energy delivered $21 million of adjusted earnings. And although this represents a $21 million decrease in 2021, our prior year's results benefited from the event-driven volatility created by winter storm, Uri. And finally, higher share count decreased adjusted earnings per share by $0.05 year-over-year. With interest rates rising in both Canada and the United States, I wanted to take a moment to walk you through the impacts we are seeing across our business, including their refinancing needs. Like many of our peers, we took advantage of the yield curve over the last number of years. Heading into this year, the average term of our long-term debt portfolio was almost 15 years and our refinancing needs are modest over the next three years. Approximately 90% of our long-term debt portfolio matures beyond 2024 and 85% beyond 2026. And the composition of our debt portfolio also positions us well to withstand a rising interest rate environment. Variable rate debt represents less than 15% of our total debt portfolio and less than 7% of that is at the holding company level. This quarter, we completed a $600 million issuance of senior notes at Tampa Electric to address our only maturity in 2022 and we issued $400 million term loans at both Nova Scotia Power and Emera. Proceeds from these issuances will be used for general corporate purposes and put additional liquidity in place to address the impacts of the volatile commodity markets. And finally, as you may recall, the Tampa Electric settlement included in the mechanism that would increase the ROE at Tampa Electric by 25 basis points and allow for an additional $10 million in base revenues, if in any continuous 6-month period, the average 30-year treasury yields increased by more than 50 points above the rate on the date of the settlement. This rate was achieved during the quarter and in July 1, Tampa Electric filed with the regulator for approval. We expect a decision from the regulator later this month and the new midpoint ROE will be 10.2% with a range of 9.25% to 11.25%. I'm pleased to report that in the last two months, all three of the rating agencies have reaffirmed their ratings and stable outlook for Emera. We remain committed to maintaining our investment-grade credit ratings and we'll continue to proactively engage with the rating agencies. Looking forward to the second half of this year, we are well positioned to continue delivering strong cash flow growth from operations, driving improved credit metrics, although we expect there may be some timing delays in cash flow recovery associated with the fuel under recoveries, we are experiencing at our electric utilities. We remain confident that our highly regulated, diversified portfolio is well positioned to capitalize on the investment opportunities, we see in front of us and to continue to provide growth in earnings, dividends and cash flow over the long term.

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

Thank you. [Operator Instructions] The first question comes from Linda Ezergailis of TD Securities. Please go ahead.

Thank you. I'm wondering if you could help us understand your capital plan that you're going to be releasing next quarter, recognizing that you're still iterating and fine-tuning it. I'm wondering if inflation and supply chain considerations might prompt some either increases or deferrals in existing projects and how you are maybe even building in contingencies into some of your plans in the outer years?

Hi, Linda, it's Greg. Good morning. As Scott mentioned, what we're seeing at least to date is not a material change in our current year capital plans. Obviously, we're seeing some inflationary pressures on some commodities. And at the same time, seeing some supply chain constraints that's probably pushing some projects out. I don't want to get too far ahead of what we're going to come out with in the fall. But I'd say, directionally, we're not seeing any kind of material change on our overall expected spend over the next three years. Q – Linda Ezergailis: Okay. Thank you. And just as a follow-up, as you look at volatility in fuel prices and we might have different -- all have different views on how long inflationary pressures will prevail and the nature of them. But is that informing how you approach your regulatory filings and how you structure your rates and risk sharing with customers. Can you comment on how you balance a few of those considerations? A – Scott Balfour: This is Scott. I'd just say broadly, and I think this is true, certainly, for us, I'm sure it's true for every utility in North America, for sure today is the real sensitivity that we've got is managing the cost impacts of the accelerating fuel price has to -- the cost for customers. And so we're working collaboratively with our regulators, with customer groups to manage those impacts as best we can, obviously, operationally, mitigating the impact with lots of examples of that, including the solar that we've got in Tampa is saving customers money because we're not needing to buy fuel. The Maritime Link is saving customers money because we're not needing to buy fuel at these higher prices, but we're not immune to the impacts of these things. And so really, it's about being engaged with our regulators with our intervenors and customer groups, in trying to work through that and be sensitive to that as we can. So yes, informing -- our thinking and our conversations with customers and regulators, both. Q – Linda Ezergailis: Okay. And maybe just to provide additional context to some of those dynamics. Given that gas and electricity prices have gone up, -- are you seeing any impact at all on customer behavior and usage? And conversely, are you seeing maybe the relative competitive pricing of the cost of energy in your utilities shift compared to any customer alternatives that there might be in certain jurisdictions. A – Scott Balfour: So it's a complicated question, Linda. So I think that we're not seeing any direct correlation of a change of behavior in terms of energy usage relative to change in price, although that's in itself hard to term because there's so many things, of course, that go into measuring customer usage. And of course, the biggest driver is weather as well as new customer connections. And you heard me mentioned earlier that, for example, in Florida, we continue to see growth in new customers. at a significant pace. And we've also seen warmer weather again in Florida, using that example. So within that, it's hard to correlate any direct relationship to the impact of changing rates. And sure, I mean the higher fuel markets is creating lots of effort on behalf of the teams in all of our jurisdictions, continuing to try to optimize and minimize the cost of generation, both in the moment, but also in terms of generation planning. And, obviously, as I made reference to before, for example, in Florida, again, the value of that solar that we put in place is even higher now than what we expected it was because, of course, we didn't expect fuel prices to be so high at the time that those cases were reviewed with regulators and intervenors. So that's always part of the work that gets done as part of generation planning at both Tampa Electric and Nova Scotia Power does, as well as in Barbados, Oklahoma. And it's more complicated in this environment because things are changing quickly, but the underlying process continues to be the same, and we continue to work very hard every day to mitigate the short-term and long-term cost impacts for customers.

Thank you

Thank you. The next question comes from Rob Hope, Scotiabank. Please go ahead.

Good morning, everyone. Maybe a first question just on the Atlantic Loop. Just the prepared remarks, it seems like this project is getting a little bit of momentum with a potential decision towards the end of the year. Can you just maybe give us a little bit more color on where we are in the process there, and kind of what the eventual project could look like, if it's changed at all?

Hey Rob, it's Peter at Nova Scotia Power. Good to speak with you. I agree that we have seen a bit of an uptick of momentum. We share the federal government's goal of trying to get resolution to this by the end of this year. As we said before, though, it's a complex project with multiple stakeholders. So I think Scott said in his comments that we're cautiously optimistic to getting there. I'd say that the meetings continue to happen in earnest with all stakeholders. Everybody is engaged. There's still a fair amount of work to do, but I'm hopeful that by the end of the year, we would have at least an idea of an agreement in principle between all parties that we can move forward with.

All right. I appreciate that. And then I just want to go back on the increased fuel costs for the first half of the year. As you talk to your customers and the regulators, when looking at the under recovery of fuel so far this year, when do you -- when would you prefer to have that recovered by? And have you talked to the credit rating agencies about what your plan would be there?

Yeah, Rob, it's Greg. Yeah, I mean, if we go based on past practice, and there certainly has been nothing through our discussions yet that any of the stakeholders, customer, groups or commission staffs want to deviate from that. Generally, in Florida, fuel costs are trued up either in the year that the under recovery takes place, or in the following 12 months. And at this point in time, we wouldn't expect anything different at Tampa Electric. Nova Scotia Power has generally taken a more smoothing approach to it, although the maximum that we've ever done in Nova Scotia has recovered it over a three-year period. And it's important to note now that most of the under recovery we've experienced to-date this year is at Tampa Electric and not Nova Scotia Power, because Nova Scotia Power has a hedging program in place, which has helped us to mitigate the volatility to-date. With respect to the credit rating agencies, we have -- but really, with S&P and Moody's themselves, provided the fuel costs are generally going to be collected from customers in the following 12-month period. They normally treated as an adjustment to working capital and therefore, doesn't have an impact on your core credit metrics in the year that you had the under recovery.

Appreciate the color. Thank you.

Thanks, Rob.

The next question comes from Maurice Choy, RBC Capital Markets. Please go ahead.

Thanks and good morning. And just a quick follow-up to the fuel cost on recovery. Just to say, as you sort design your funding plan that you have today, this is obviously not something that you anticipated. So with this continuing on and you've recovered over the next 12 or X amount of years, how does this factor into your funding plan particularly recognizing that CapEx is also likely to go up?

Yes, Maurice, it's Greg. It really doesn't have any impact on our funding plan at all. I think to-date, the most significant under recoveries at Tampa Electric and really that's a short-term issue probably over the next 12 to 15 months. And so that's really why we've done some things like we did the two-year bond issuance at Tampa Electric earlier or, I guess, last quarter. We've put in some term loans at both Nova Scotia Power and Emera just to provide us the flexibility and so these are all one-year term loans just to make sure that we have the adequate liquidity in the event that we had some funding requirements for the next 12 months. But we had financing that maxed that. And as a result, it wouldn't change our overall capital plans or funding plans for the next three years.

That's good to know. And thanks for that. And my second question, your thoughts on the implications of the Inflation Reduction Act, including the puts and takes from a tax perspective as well as any stronger push towards renewables?

Yes. I'd say, Maurice, the team is still going through it and quite frankly, the review of it probably raises as many questions as it provides answers. But I'd say, from a financial perspective, it doesn't seem to have much of an impact. We're going to be -- we'll be below the threshold for the alternative minimum tax, which is good. Obviously, anything from an ITC, PTC perspective on renewables is helpful, but it's not going to have any kind of meaningful financial impact either from an earnings or cash flow for us in the next couple of years. Obviously, strategically, it's helpful. I mean the more push and the more support in the United States for more renewables, some new technologies that will help achieve our long-term carbon reduction goals. More support for electric vehicles, which will underpin some load growth. Those are all very, very positive for us. But the direct financial implications seem to be pretty minor at this point in time.

Perfect. Thank you very much

You’re welcome.

The next question comes from Mark Jarvi of CIBC Capital Markets. Please go ahead.

Thanks. Good morning everyone. I just wanted to touch on the base spending plan, but also the potential $1 billion in incremental spend. So just spending year-to-date, your expectations are still at 2.8% for the balance of this year. Is it a possibility that you understand a little bit this year and there's some in slippage to next year and then on the $1 billion you talked about for a couple of quarters now incremental spend as we've move through the year and Atlantic Loop maybe takes a little longer to become to fruition. Is the expectation in that just rolls ahead one year on transact incremental $1 billion of spend potential?

Yeah, Mark, I think on the incremental opportunity on capital, most of that was in the in 2023, 2024 year. And traditionally, we would expect as we roll forward our capital plan which we'll share with you on the earnings call in Q3 that some of that will likely have been firmed up by then, and we're working through some of that. And obviously, as we do that, which is our traditional path. There's always other projects that start to get identified. So we'll look after all of that and share with you in Q3. In terms of this year, if I think if I understood your question right, I mean, there's always a handful of projects that – or whether it's scoping issues or supply chain constraints, or allocation of resources that there's always some movement between years, where projects can either be moved into a year or moved out into the next year, and that continues – that's normal course of business for us. I wouldn't expect any of that to have a material impact on our forecasted capital spend for 2022.

Okay. And then, Greg, just coming back to that slide you provided on your debt and profile is helpful. Just when you think of that 2023 maturity 2024 maturity just updated views relative to reintegrated on those is the idea here to roll those over and take a bit of a hit on the effective interest rate. Anything else you can kind of share in terms of how you handle next maturities?

Yeah. I mean, we haven't concluded any of it, Mark. I mean, to be quite frank, where interest rates are today is not unexpected. Maybe they got here a little faster than maybe we anticipated, but our long-term financing plan had already – had always assumed that interest rates were going to increase from where they were. I think the levels we were at, quite frankly, weren't sustainable. We're not planning to do any early refinancing of those at this point in time, and we'll continue to monitor the market and make decisions on those refinancings as we get closer to the maturity dates.

Got it. And then just coming back to the inflation reduction, I kind of said that it's not that meaningful, but – and I know it's a small component of the business, but Block Energy, I wonder whether or not there's anything from IRA that's incremental supportive and the commodity volatility to again lead the tailwind for that business, just updated views on Block Energy potential?

Yeah. So I think it's directionally helpful, I think, Mark, for Block Energy, recognizing the technology and the battery components of that. But again, as Greg said, we're really still working through the – the mechanics and details of the act overall. But Block Energy itself continues to progress well. We've got 37 homes in service in Florida region, now with the version two product. We're working on a second utility pilot in the US, not related to Tampa Electric, and we continue to advance the go-to-market version, the polar go-to-market version three of this technology as well. And so we continue to be really encouraged, very excited, frankly, by this technology and the opportunity but it's still early days. And so we're taking it a step at a time and proving it out and testing it this idea of utility-grade system that interconnects rooftop solar, with residential storage, backup generation and a single connection to the AC grid. And pleased with our progress, but it's still early days. We'll be no doubt talking about it more in the quarters to come

Okay. Thanks, Scott, thanks, Greg.

Thank you.

Thank you. The next question comes from Ben Pham of BMO. Please go ahead.

Hi. Thanks, good morning. I had a couple of questions on Tampa Electric. When you think about the ROE application and approval in the near term, is that just for the regulator double tracking your numbers and making sure that it is the criteria? And the $10 million pickup is -- is there going to be some such activity around that ability to get that boost?

Yeah. No, Ben, I think the way you characterize it is a fair representation. So it's relatively a mechanical exercise we're going through right now. And there's been no intervener opposition or nobody's filed to participate in the area. Obviously, with a change in ROE and the impact of that, including the additional revenue requirements, the commission has a responsibility to make sure and confirm the math to support that, including whether or not the trigger was effectively hit. So all of that's been filed with the regulator. We would not anticipate anything controversial coming out of that hearing.

Okay. Great. And then considering first half results and is like a couple of key drivers how is Tampa Electric trending relative to your expectations? And you put in your second half budget, I mean is there ability to benefit from this higher range that you had approval for?

Yeah. I'm not so sure necessarily that the higher range will have much of an impact on our balance of year results, obviously, if we get an additional $10 million of incremental -- annualized incremental revenue and rates and if that takes place, let's pick September 1, we have some prorated amount of that in 2022. It has some modest positive impact, I think, low single-digit millions of dollars Ben on our clause-related recoveries, so things like the storm protection plan that will start to collect revenues and earnings on that at the midpoint of the band as well. So maybe a slight bias upwards over the second half of the year, but we're pretty comfortable at this point in time that we'll be comfortably within the new range of ROE for the 2002 fiscal year.

Okay. Perfect. Thank you.

You're welcome.

Thank you. The next question comes from Dariusz Lozny of Bank of America. Please go ahead.

Hi. Good morning, and thank you for taking my questions. Maybe just to start-off on the year-to-date results. It seems like you've got pretty strong momentum at the utilities, in particular, in Tampa. But year-to-date, on a consolidated basis, you're tracking a little bit below what might be assumed just from your rate base growth. Can you talk a little bit about how you see that momentum tracking through the second half or perhaps what levers or timing considerations we should be thinking about as we think about how the earnings should shape up in the second half?

Yes, Dariusz, I mean we're comfortable with the path we're on. I think it's important to remember that our year-to-date results include the exceptionally strong first quarter of 2021 that we had with Emera Energy because of winter storm Uri. And that was not expected -- we were not expected to duplicate that or replicate that in 2022. The rest of the businesses are performing very well. And so I think what you see in Q2 is likely more reflective of what we expect to see over the balance of the year.

Great. Thank you. That's helpful. One more if I can, just on the utility side of things. Can you talk a little bit about what type of normalized growth you're seeing in terms of load at across customer classes? You cited some very strong customer growth figures, but just curious how that's manifesting in the load that you're seeing.

Yes. I guess, it's always difficult Dariusz try to break apart the weather aspect to it versus everything else. But I'd say, what we're seeing in particular electric utilities, we're seeing load growth on a weather-normalized basis more and less start to match customer growth, which historically, that has not been the case because of energy efficiency. Often, load growth was slightly less than customer growth and those two seem to be seemingly a little bit more in line these days than they have been over the past number of years

Okay. Great. I appreciate those responses. I'll pass it here. Thank you.

.:

Thank you. The next question comes from Andrew Kuske of Credit Suisse. Please go ahead.

Thanks, good morning. Maybe you could give us some perspective on just your existing land positions in and around generation facilities, where you could build either solar or just integrate battery technology, along the lines of what you did at Big Bend across the portfolio, just to give us a sense of how you could use existing transmission infrastructure to really help energy transition on an accelerated fashion without causing rate shock.

Hi, good morning. Andrew. It's Archie from Tampa Electric. I'll try to answer that question. And if I don't hit the mark, let me know. And so we TECO has a fair amount of land that we hold on our balance sheet for future use, throughout our service territory and on the fringes of our service territory. Some of that is being held for transmission rights-of-way expansions or for potential locations to site future generation. Much of what we hold really isn't suitable for solar development. And so our real estate team is continuously out scouring the market, looking to add cost-effective real estate that would be suitable for solar expansion.

And perhaps it's Peter from Nova Scotia Power Inc. Nova Scotia really, I guess, in three areas. When you think about the decarbonization journey, we will be converting existing coal plants to gas-fired generation. So it's utilizing existing plants just converting the generation source. On the transmission side, obviously, we talk about Atlantic Loop, that will require transmission to be built between Nova Scotia and Brunswick. We’ve acquired most of those land rights. We are in the process of acquiring the remaining land rights for that project. Then I guess the last thing I would say just referencing the grid scale battery announcements that came out that we do have four sites across the province for those installations as well.

I think the only thing I would add to that Andrew, it's Scott, is in those cases where we – where we can, we do. So, one of the two now of the solar sites for Tampa Electric are on buffer lands to Big Bend Station. And so those areas where we can use a land that is not yet productive, but is suitable for solar or for storage that's very much what happens and Big Bend Station is a good example, where there is a significant amount of solar and even you may recall, that showed some analysts and shareholders a couple of years ago. There's also battery storage at that site as well. So where we can use land holdings for development of cleaner energy storage or generation, we absolutely do. But a lot of it is not necessarily suitable for that in which case we need to be adding to those land resources in order to build that generation.

And if I could just add one point, it would be that. When it comes to setting renewable, certainly, solar investments, we're also excited about the prospect of floating solar in fact we've done a pilot floating solar project on the Big Bend property. And so that land is increasingly difficult to come by in Florida. It's a destination of choice. There's, lots of people moving there. But there is lots of wet land that could be a great location for solar if we can get the price point right.

That's very helpful color and context. And I remember the doing quite well to the site. Maybe just focusing on part of the answer from earlier on, on the transition in Atlantic Canada, Nova Scotia, in particular, just on natural gas availability and supply availability? And just what are your thoughts on the outlook for natural gas and having sufficient supply and from multiple sources.

Certainly, some of our planning and our outlook for the requirement for natural gas for our use, we do have sufficient supply. We're obviously working with local gas provider here in Nova Scotia to make sure that supply gets exactly to where we need it. Just a reminder, when we think about the coal to gas conversions, those won't be baseload generation plants. Those will be largely peaker plants dispatchable capacity plants that we need for reliability purposes.

Very helpful. I'll leave it at that. Thank you.

Thank you. [Operator Instructions] The next question comes from Matthew Weekes of IA Capital Markets. Please go ahead.

Good morning. Thanks for taking my questions. Maybe just a couple of clarifications. I'm just wondering if you can remind us what your sensitivity to changes in the foreign exchange rate is based on hedges you have in place versus what you build into your plan?

Matthew, it's Greg. I mean in general or directional a $0.01 change in currency is a couple of cents in EPS. As you're well aware, we do have a hedging program in place where we try to mitigate that exposure. We've obviously have taken advantage of the weakness of the Canadian dollar over the last little while. And we have about 40% of our 2023 US dollar earnings hedged at a little less than $1.30 and we have about 20% of our 2024 expected US dollar earnings hedged at a little bit better than $1.30.

Okay. Sorry, that was 20% on 2024, correct?

Correct.

Okay. Thanks. And then just on the cash flow and looking at the difference in your slide and the 7.6 year-to-date versus 9.66 sort of potential. Is that -- is the bridge there just based on the amount of under-recovery that you expect to recover over the next 12 months mainly at Tampa Electric based on what you've filed for at this point?

Yes. The difference, the $200 million-plus difference is really the under recovery of fuel costs at Tampa Electric for the first six months. There's a little bit of Nova Scotia Power in there as well, but it's mostly Tampa Electric. And we're still working through what our regulatory approach will be. We have the ability to file a second midyear course correction if we so choose, but we also have to do a filing to true up fuel rates on January 1st, 2023, which would be our 2023 forecast as well as any expected under recovery this year. So, we're just working through the regulatory approach to that, but we would expect that a good portion, if not all, of it would be collected before the end of next year.

Okay. Thanks. I appreciate the commentary. I'll turn it back.

Thanks Mathew.

Thank you. There are no further questions at this time. Please continue.

At this time, we'll close the call. Thanks for your interest and we'll talk again in another quarter.

Thank you.

Thank you. This does conclude the conference call for today. We thank you for your precipitation and ask that you please disconnect your lines.