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Good day ladies and gentlemen and welcome to the Emera Q2 2023 earnings conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star, zero for the operator. This call is being recorded on August 11, 2023.
I would now like to turn the conference over to Dave Bezanson. Please go ahead.
Thank you Michelle, and thank you all for joining us this morning for Emera’s Q2 2023 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.
Now I will turn things over to Scott.
Thank you Dave, and good morning everyone. I’d like to begin my remarks by taking a moment to acknowledge the two significant natural disasters that impacted our customers, our communities and our teams here in Nova Scotia in the last few months.
In May, thousands of Nova Scotians were evacuated and over 150 families lost their homes to the devastating wildfires that broke out across the province. Thankfully no lives were lost; however, many people including our own employees were impacted. We are incredibly grateful to the hundreds of first responders who kept our communities safe and courageously battled these fires.
Only weeks later, the province was hit with a record-breaking rainstorm, resulting in severe lightning and flooding that caused significant damage to homes and communities across the province, and tragically four Nova Scotians lost their lives in the flooding. On behalf of the entire Emera team, we extend our heartfelt condolences to everyone affected by these events.
I’d also like to take a moment to recognize the team at Nova Scotia Power. These disasters underscore the essential work we do and the value of a strong and reliable electrical grid, and the response from our team highlights the strength and resiliency of our people, as well as their expertise and unwavering dedication to the communities we serve.
This morning, we released our second quarter results and I’m pleased to share that we continued to deliver steady, predictable earnings and cash flow growth. We reported second quarter adjusted earnings per share of $0.60, up 2% from the second quarter of 2022, driven by strong performance from our regulated utilities partially offset by lower earnings from Emera Energy and the impact of higher interest costs across the business. For the year to date, despite higher interest costs which Greg will discuss shortly, as well as inflationary pressures generally, adjusted earnings per share has increased $0.07 or 5% to $1.58 compared to $1.51 last year.
Our regulated utilities delivered an 11% increase in adjusted earnings this quarter and 7% year to date, largely driven by an increase in rate-supported capital investments as well as favorable contributions from asset management agreements at New Mexico Gas in the first quarter.
We continued to see strong economic and population growth in our key service areas. The economic growth in Florida continues to drive meaningful customer growth, approximately 2% at Tampa Electric and 5% at Peoples Gas. Here in Nova Scotia, we’re experiencing the strongest population growth in decades, driving over 1% customer growth at Nova Scotia Power last year. At both Tampa Electric and Nova Scotia Power, this customer growth is contributing to growing customer demand on load, which helps to offset some of the impact of less favorable weather in the first half of the year.
As the economies and populations in our service territories grow, so does the level of capital investment required to support that growth and to deliver cleaner and reliable energy for our customers. In the first half of 2023, we deployed over $1.4 billion in capital, a 25% increase over 2022, and we continue to expect to invest almost $3 billion in capital this year. Our deployment in the first half of the year is on track with our three-year capital plan, which remains focused on reliability and decarbonisation investments as well as infrastructure expansion investments in support of customer growth.
Last year, we completed the Big Bend modernization at Tampa Electric. I’m proud to say that earlier this month, this project was recognized as the best energy project in 2022 by Engineering News Record. As one of the most efficient natural gas plants in North America, it can produce almost 1,100 megawatts of energy, enough energy to power more than 250,000 homes. This transformative project of a plant that once burned coal not only provides cleaner and more reliable energy for our growing customer base but also provides the necessary capacity to support the increasing build-out of solar generation.
Tampa Electric’s investment in solar has continued with over US $120 million invested in our solar program in the first half of the year, and we’re on track to have another 125 megawatts of solar generation in service by the end of 2023 for what will then be total utility scale solar generation capacity of 1,255 megawatts, representing 20% of Tampa Electric’s total generation capacity. We’ve also invested US $110 million so far this year in our storm protection plan, representing important investments to strengthen the system against severe weather events. We saw firsthand the value of these investments in the aftermath of Hurricane Ian with system impacts and outage restoration times both improved.
At Peoples Gas, we’re focused on investments in system reliability and expansion to support the incredible customer growth the utilities experienced. We expect over 75% of our three-year capital program will be invested in our Florida operations to support the strong population and economic growth that continues in the state, and overall we continue to expect to deliver 7% to 8% rate-based growth over the forecast period. However, we are focused on how to optimize the pace of capital investment to best manage the cost impacts for customers.
As we collectively continue to navigate the current inflationary environment, we are also working to support our customers with energy efficiency programs as well as financial support programs for those who are struggling. Large government tax incentive programs are also helping to reduce the cost of the transition to cleaner energy.
In the U.S., the Inflation Reduction Act provides tax credits that are expected to make several of our current and prospective projects more affordable for customers. Similarly, the most recent federal budget in Canada recognized the need to address the significant cost impacts of the clean energy transition with additional funding programs, including meaningful investment tax credit support.
Within our capital plan, Tampa Electric’s almost $1 billion investment in solar generation will attract production tax credits under the Inflation Reduction Act, and looking forward, as we highlighted in our investor day in March, we’re excited about the opportunity the federal tax credits have created in support of carbon capture and sequestration, as well as hydrogen.
Last year, Tampa Electric was awarded approximately US $6 million of funding from the U.S. Department of Energy to perform preliminary study at the Polk power station to evaluate the costs and feasibility of retrofitting carbon capture technology on a combined cycle generation unit. I’m pleased to say we received an additional US $5 million of funding from the Department of Energy this year to continue this important work on this promising project, albeit still in early days.
In Nova Scotia, we continue to support stakeholder discussions with respect to the Atlantic Loop. Our objective since the beginning has been to find a way to phase out coal generation in a way that delivers the best solution to Nova Scotia Power customers. We believe that a strong transmission tie into the province is key to the most optimal path to phase out coal generation in Nova Scotia Power’s electric grid while maintaining grid reliability for Nova Scotians.
Increasing electric transmission capacity between regions makes sense everywhere, particularly here in Nova Scotia where our electrical connections to larger markets are currently constrained. New regional transmission capacity would provide Nova Scotia with critical access to dispatchable energy capacity for when intermittent wind and solar generation sources aren’t available, and would also enable Nova Scotia to become an exporter of the incredible wind resources we have here in the province, which would also help support the development of green hydrogen and offshore wind in Nova Scotia.
But it’s complicated, and as you’ve heard me say many times, the kind of rapid and transformative transition to cleaner energy that is now underway is extremely costly, and so we’re aligned with the provincial government in the view that significant financial support from the federal government is required to achieve federal clean energy policy goals here in Nova Scotia. It’s imperative that we find a solution that is in the best interest of our customers, of Nova Scotians - that is our focus.
While governments and other important stakeholders continue to discuss whether the Loop project advances or not, the team at Nova Scotia Power continues to work with the Province of Nova Scotia to advance the other important components of the clean energy transition. This includes investments in battery storage, supporting grid connections for new wind procurements, and strengthening the inner tie between Nova Scotia and New Brunswick.
Last quarter, the team at Peoples Gas filed their petition for new rates effective January 1, 2024. Since their last rate increase in 2021, Peoples Gas has deployed more than $1 billion of rate-based investment to serve the growing population of Florida and to ensure their system continues to operate safely and reliably. Hearings are scheduled for later this month and we expect to have a decision from the regulator in the fourth quarter. The team in New Mexico is in the process of developing a rate case that it intends to file later this year, requesting new rates that would be effective in the fall of 2024.
To sum up, the fundamentals of our business and our portfolio of high quality regulated assets remains strong. We remain focused on strengthening our balance sheet, executing on our well-established strategy of investing to deliver increasingly clean and reliable energy to our customers while always considering the impact of cost on customers, and by doing that, we’re also delivering consistent, reliable growth in earnings and cash flow for our shareholders.
With that, I’ll turn it over to Greg to take you through our financial results.
Thank you Scott, and good morning everyone. This morning, we reported second quarter adjusted earnings of $162 million and adjusted earnings per share of $0.60, compared to $156 million and $0.59 in Q2 2022. Year to date adjusted earnings were $430 million and adjusted earnings per share was $1.58, compared to $398 million and $1.51 for the same period in 2022.
Our regulated portfolio was the driver of our strong second quarter results. Contributions from regulated utilities increased $27 million over Q2 2022, or $0.07 of adjusted EPS, due in part to an increase in rate-supported capital investments at Tampa Electric, Nova Scotia Power and New Mexico Gas. This was partially offset by higher interest expense across our portfolio, lower contributions from Emera Energy, and a higher share count.
Operating cash flow before changes in working capital continued to grow in the second quarter. Despite slightly unfavorable weather in the first half of the year, year-to-date operating cash flow increased by 56% primarily driven by fuel over-recoveries at Tampa Electric compared to under-recoveries in 2022. In addition, on April 1, we began collection of the 2022 fuel under-recoveries and Hurricane Ian storm costs at Tampa Electric, and the Labrador-Island link is now producing cash flow with year-to-date results reflecting one quarter’s worth, and the balance of the year receiving a full six month’s worth.
Excluding the impact of the fuel deferrals in collection of 2022 fuel and storm costs, we delivered over $1 billion in operating cash flow in the first half of 2023, roughly half of our annual target of $2.1 billion. As I’ve said before, the cash flow challenges from 2022 were timing related and they are fully reversing as we had expected.
Our path to improved credit metrics is still clear - fuel costs have remained stable and the over-recoveries we are seeing in 2023 so far are helping to pay down the under-recovered balance faster than expected. While we are adjusting for the effect of the collection of fuel costs on our cash flow, this faster collection will reduce the outstanding debt balances associated with financing these under-recoveries and therefore improve our credit metrics.
In addition, at our investor day in March, we were clear that we have additional levers available for credit metric improvement outside of our base plan, should we need them, and while we are encouraged by the progress in the first half of the year and the more favorable weather we are seeing so far in Q3, if needed we will not hesitate to use these levers. In fact, we have already made the decision to defer our $240 million incremental investment in the Labrador-Island Link from this year to 2024. This will result in moderate cash flow savings from reduced interest expense and, more importantly, reduce our associated funding needs in 2023. To the extent necessary, we have some incremental opportunities to defer capital, and we will reassess as necessary.
Turning to our quarterly results, contributions from our Canadian utilities increased $10 million or 26% compared to Q2 2022, driven primarily by Nova Scotia Power and higher earnings from our equity investments. Last quarter, we announced the Labrador-Island Link had been commissioned and in this quarter, we received consistent flows of energy from the Nova Scotia block and, as a result, did not recognize any hold-back costs contributing to our quarter-over-quarter increase in earnings.
Tampa Electric delivered strong results with growth of US $6 million in earnings, or 5% over Q2 2022, driven primarily by new base rates that went into effect on January 1. While the weather in the quarter was less favorable compared to the very favorable weather last year, this was largely offset by strong customer growth. The weakening Canadian dollar also increased the earnings contribution from U.S. operations by $8 million for the quarter.
Contributions from Emera Energy decreased $14 million for the quarter. This was not unexpected. As noted in our Q1 call, Q2 and Q3 are generally challenged for profitability because costs of transport and storage are amortized equally over time despite the fact that the related revenues are mostly earned in the winter months. 2023’s contracts were bid in 2022’s markets, so the costs were somewhat elevated compared to the last couple years, which is similar to what we experienced in 2019. As I will discuss shortly, year-to-date contributions from Emera Energy have still increased $10 million year-over-year and we expect the business to deliver adjusted earnings within its guidance range of US $15 million to $30 million.
Earnings from our gas and infrastructure segment decreased modestly quarter over quarter, primarily driven by higher interest and operating costs resulting from continued investment in support of customer growth at Peoples Gas, and corporate costs increased $4 million this quarter, primarily driven by higher interest cost. Finally, higher share count decreased adjusted EPS by $0.02 compared to the second quarter of 2022.
Year-to-date adjusted earnings per share increased by $0.07 to $1.58, driven by favorable foreign exchange movements as well as higher contributions from our regulated portfolio and Emera Energy, partially offset by higher corporate costs and an increased share count. As I mentioned a moment ago, despite the expected loss this quarter, year-to-date Emera Energy’s marketing and trading business generated CAD $28 million of adjusted net earnings compared to $18 million for the first half of 2022 - that’s US $22 million compared to $14 million last year, representing an almost 60% increase year-over-year.
You’ll recall that Q1 2023 was very strong, reflecting favorable hedges, access to more gas transport, and a brief cold spell in February. Emera Energy continues to expect annual earnings within its guidance range of US $15 million to $30 million.
Contributions from our Canadian and Caribbean utilities increased a combined $8 million year-over-year due to Nova Scotia Power, interim rates at Barbados Light & Power, and higher earnings from our Canadian equity investments.
At our gas utilities, results this year benefited from new rates and favorable asset management agreements at New Mexico Gas, which were partially offset by higher interest and operating costs, primarily at Peoples Gas, and consistent with the quarterly results, higher interest costs contributed to the increase in corporate cost year-over-year, partially offset by the timing of share-based compensation expense and related hedges.
At Tampa Electric, new rates and strong customer growth were offset by higher interest costs and less favorable weather, resulting in a modest decrease in earnings year-over-year. Finally, higher share count decreased adjusted earnings per share by $0.05 year-over-year.
It is clear from our results so far this year that higher interest rates have had an impact throughout our portfolio that is offsetting some of the strong growth that we are seeing form our regulated utilities. I wanted to take a moment to discuss how we’re thinking about these impacts across the business and how we expect those to trend in the near and longer term.
In our regulated utility portfolio, three of our utilities are currently in rate settlement periods that were negotiated before the rapid increase in interest rates, and while we never expected interest rates to remain at the historical lows of the COVID 19 pandemic and took advantage of the yield curve to term out significant portions of our debt, the rate of increase in interest rates over the last 12 to 18 months has been almost unprecedented in its pace. As you may recall, the Tampa Electric rate settlement included a mechanism that increased the ROE at Tampa Electric by 25 basis points and allowed for an additional US $10 million in base revenues when the average 30-year treasury yield increased by more than 50 basis points above the rate on the date of the settlement. While this innovative mechanism was constructive, the 30-year treasury yield has now increased nearly 200 basis points above the rate on the date of that settlement.
While the settlement periods in our regulated utilities have many advantages, the impact in a rising rate environment like we have seen so far means we are more exposed to higher interest costs. We will continue to operate our utilities as prudently and responsibly as possible and look for cost savings to help offset the impacts; however, at this pace of rate increases, we expect to continue to experience regulatory lag in the collection of interest costs.
Importantly, we have a healthy rate case cadence with constructive regulatory environments in forward test years in all of our core utilities to ensure we earn a fair and timely return on and of the capital that is being prudently deployed. As Scott mentioned, the rate case at Peoples Gas is ongoing and we expect a decision later this year for new rates effective January 1, 2024, and on January 1, 2024, we will also have another approximately $142 million in increased rates that have already been approved at Tampa Electric and Nova Scotia Power.
2024 is also the last year in a three-year rate settlement period at Tampa Electric. Tampa Electric, like all of our core regulated utilities, is on a forward test year. This means we’ll be able to assess in 2024 whether we have sufficient rates based on our forecast for 2025 and make an application to the regulator for new rates as necessary. Therefore, while we expect to continue to see some near term impacts from higher interest rates in 2023, there is a clear regulatory calendar ahead of us that should allow rates at our utilities to reflect the higher interest cost environment on a timely basis.
We remain focused on strengthening our balance sheet and credit metrics and have made meaningful progress to that end already this year. While interest costs are admittedly a headwind at this time, there are many reasons to be optimistic. Fuel costs have reversed from the highs of last year, the Labrador-Island Link is commissioned and delivering energy across the Maritime Link as planned, the Canadian dollar exchange rate remains favorable, and many of our service territories continue to see customer growth.
There remains no shortage of investment opportunities in our utilities as we continue along the clean energy transition, and we remain committed to ensuring reliability of the grid and managing the pace of investments to ensure customer affordability stays front of mind.
With that, I’ll turn the call back over to Dave.
Thank you Greg. This concludes the presentation. We would now like to open the call for questions from analysts.
Thank you. Ladies and gentlemen, we will now begin the question and answer session. [Operator instructions]
The first question comes from Maurice Choy of RBC Capital Markets. Please go ahead.
Thanks and good morning. Maybe just sticking with the discussion on the balance sheet here, apologies if I missed it, but what is the normalized FFO that you currently have as of Q2?
Good morning Maurice, it’s Greg. On a 12-month, kind of trailing 12-month basis, which would only include one quarter, obviously of the Labrador-Island Link, on a normalized basis we’re just shy of 11%.
Thanks, and recognizing that Q1 as well as Q2, you’ve recorded relatively good operating cash flow generation here, just wanted to get your latest thoughts on moving back to stable outlooks. I think back in May, you mentioned that you were not anticipating that this shift would happen anytime soon. With this kind of cash flow generation that you’ve built, perhaps balanced with the continued macro uncertainty, have you seen any positive or negative shifts from the rating agencies?
No, I wouldn’t say we’ve seen a shift in either way. I think the path we’re on is well understood by the rating agencies. Obviously things are unfolding exactly as we would have expected, either from a collection of cash flow, collection of fuel under-recoveries, storm costs, as well as the regulatory agenda in front of us, and I think it’s just a matter of executing on--continuing to execute on those and presumably that would put us in a good position to return to stable at some point, hopefully over the next couple of quarters.
Thanks. Just to finish off, as a follow-up to Slide 11, and thanks for that discussion on the interest rate impacts, recognizing that you do have favorable rate exposure both at the holdco and as well as two prefs that are set to reset later this month, you talked a lot about where rates have gone. We appreciate your thoughts on where you think the rates are going and how that drives your financing strategy. I wonder if there are any steps you can take to rein in the financing costs over and above the regulatory calendar you just spoke of.
Maurice, I wish I knew rates were going. My answer a month ago might be different than today. I mean, it does feel that we have topped out - certainly the yield curve would suggest that. In the near term as we look in particular at our regulated utilities, Tampa Electric being one, there’s some opportunity to term out some of the short term debt with long term rates being lower than what we are experiencing in the short term market, so you might see us, for example, access the market at Tampa Electric, doing a bond financing sometime over the next few months.
Great, thank you for the color.
Thank you. The next question comes from Rob Hope of Scotiabank. Please go ahead.
Let’s stick with the balance sheet - good to see a pick-up in cash flow, and I did appreciate the comments about the additional levers that could be pulled to further strengthen the balance sheet. We’re almost midway through August and the LIL 240 has been pushed, but nothing else has really been--no other levers have really been pulled. When we take a look at the puts and takes of your cash flows, is the expectation that you’re seeing more tailwinds given the fuel recoveries as well as the hot summer so far, such that you think you’re in a good position for 2023 without really the need to pull these other levers?
Yes, I think that’s certainly, Rob, how we feel today, but we’re still always evaluating our capital to determine whether or not it would be prudent from a customer perspective to move some of it out. But certainly your characterization is right - we’re seeing strong cash flows on a fuel-adjusted basis in line with our expectations if you include a recovery of fuel and storm costs quite frankly coming in way stronger than we might have otherwise expected. So yes, when you combine all of that together, we’re feeling fairly confident from where we sit here today.
All right, thank you. Then just a follow-up, and it was kind of noted in the prepared remarks, but the draft clean energy regulation, does this change how you think about generation investment, whether it be carbon capture, intermittent wind in Nova Scotia, as well the federal government continues to speak quite favorably about the Loop project. Can you just maybe give us some milestones where we could see some progress there?
Rob, it’s Peter Gregg from Nova Scotia Power - I hope you’re well. The CERs, obviously we just got those yesterday. We’ll be diving in deeply to make sure we completely understand any impacts it would have on our recently released integrated resource plan - you’ll see we released that earlier this week. Initially, I’d say on the good side, pleased to see mentions of the need for flexibility, particularly when it comes to the role of natural gas as a bridging fuel that can accommodate more renewables and also enhance reliability here in Nova Scotia.
But always when we look at the decarbonisation agenda, we believe it’s got to be balanced with affordability and reliability, and that’s how we’ll look at it, so still concerned as we dive into more details that it could have undue cost impacts for Nova Scotians, so that’s where our focus will be. Also, pleased to see that the Feds have indicated that they will have a robust consultation period, and we intend to consult very heavily with the federal government during that process.
Did you have a follow-on there on the Loop as well?
Yes, just in terms of what milestones are kind of near term items we could see here.
We continue to be engaged in the discussions with the federal government, and I agree with you that the federal government has made some positive comments. There’s still, I’d say, some uncertainty on whether it will be Loop or no Loop, and so where our immediate attention at Nova Scotia Power is, is focusing on investments that are required under any scenario, and really that’s an enhanced reliability intertie to New Brunswick, that’s investment in grid-scale batteries, and working very closely with the provincial government on those investments but also the need to procure more renewable resources by 2030, so we’re very focused on that and continue to be engaged in the discussions on the Loop.
Rob, let me just add in the context of the CERs, I think Peter handled it well, and obviously it’s new and we’re working our way through it, and yes, we’re pleased with the flexibility. But the challenge across the country is not the same, it’s very regionalized, and Nova Scotia is one of the provinces where this will be particularly challenging to achieve, particularly costly to achieve. So yes, while we’re pleased with the flexibility that is indicated, frankly it needs more for there to be a clear path for Nova Scotia, and it’s going to need federal funding support in order to make it affordable. Those would be my additional thoughts to Peter’s message.
Thank you.
Thank you. The next question comes from Ben Pham of BMO. Please go ahead.
Hi, good morning. On your leverage of potentially deferring 2023 capex, can you comment, is there flexibility in your rate cases and the one-off to do that seamlessly, or do you have to go back and engage with stakeholders?
Ben, it’s Greg. No, managing our capital within a certain envelope, you’ve probably heard me say it before, it’s not uncommon to have a few hundred million dollars move between years just because of timing considerations and the ability to execute on projects, because some of the supply chain constraints we’re seeing right now are just naturally causing some projects not to get done on the exact time frame we would have thought, but we’re able to make those changes across the portfolio without any kind of significant engagement with customer groups or regulators.
Okay, got it. Are you planning to provide a refresh of your capex next quarter, and can you comment when you think about even just the trends in capex, $2.53 billion, is really the willingness to increase that maybe somewhat tempered given where your balance sheet is right now?
Yes, so we will be, as is customary, Ben, providing a roll forward of our three-year capital and funding plan on our call, Q3 call in November. In terms of a willingness, all of the capital we’re spending is in support of our customers, whether that’s decarbonisation, reliability, customer growth, and so it’s not a question of whether or not we can do it with our current balance sheet consideration, but it is capital that is required to run the utilities, and as such, that doesn’t really come into play on it. How we finance it is kind of the second piece of that.
And frankly, Ben, managing affordability impacts our customers and making sure that we’re constantly focused on measuring that pace, so that we’re managing that at a time where it’s sensitive. As I say, the general inflationary environment is making that challenging, so really it’s a combination of all those things to manage it, and obviously at this point in time, I can’t speak to a trend as to where things look like in the next three-year forward forecast, but I wouldn’t suggest there’s going to be any significant differences, significant changes in trend.
Okay, and maybe lastly on rate cases, beyond the two you’re working on now, is there others you’re going to be focused on in the back half of this year, into early next year?
Sorry Ben, just so I understand, are you referring to specifically rate cases?
Yes, in terms of your calendar for launching new rate cases to you mentioned around reducing regulatory lag.
Yes, I think the only two things you’ll see is a resolution in Peoples gas that, as Scott mentioned, we would anticipate that being resolved by the end of the year, new rates on January 1, 2024, and again as Scott mentioned, New Mexico Gas will likely be filing as well. But that would be the two significant regulatory filings that we would have in front of us for the balance of 2023.
Okay, got it. Thank you.
Thank you. The next question comes from Linda Ezergailis of TD Securities. Please go ahead.
Thank you. Maybe given that you’re reassessing all your priorities around deleveraging and what might be optimal, recognizing you are able to defer some capex, can you maybe also give us an update on whether you might consider any additional levers related to potentially selling any assets or interest in assets that might be valued higher by third parties, and conversely, might some of the tailwinds you’re seeing allow for you to consider discontinuing usage of the ATM over the next couple of years?
I think as it relates to asset sales, portfolio optimization, capital recycling, all the language that gets used in this sector, Linda, I’d say the answer is really no different than what you’ve heard before. We continue to look at the portfolio and look at our sources of funding and our balance sheet, and when we see opportunities that are value-enhancing for shareholders and make sense for our strategically, then we spend a lot of time working our way through that and we won’t hesitate to take steps when we see it make sense. You’ve seen us do that obviously before with the sale of gas plants and Emera Main, but at the same time the portfolio that we have today is--you heard me say it in my remarks, we think we have a very strong portfolio of assets that contribute positively to earnings growth and cash flow growth, and so we remain very comfortable with the portfolio, but we constantly assess, I guess would be the way to answer that question.
I’ll let Greg respond to the ATM.
Yes, I think with respect to the ATM, Linda, you’ve heard both Scott and I mention, there’s significant capital investment opportunities that are in front of us as a result of customer growth and a desire to decarbonise our fleets, and so from where I sit, I see the ATM as a very prudent and cost effective way of raising the equity to support that growth that we’re going to see and I would expect that would continue to be an important part of our funding plan as we go forward.
Thank you. Just reflecting on recent events, the unfortunate wildfires and flooding in Nova Scotia and looking forward to the balance of the hurricane season in Florida, it looks like conditions support maybe an above-average activity as we come towards the end of that. How might that inform any sort of prospective rate application or initiatives to continue to storm harden and maybe accelerate decarbonisation? How are your thoughts evolving around lessons learned with some of the recent experiences in your core utilities?
I think Linda--I mean, look, largely decarbonisation investment initiatives are either driven because investments can be made that are the most economic ones for customers, like the solar investments and coal-to-gas conversions that we’ve been doing in Florida, or gets driven by policy obviously, which is more relevant to the path that Peter and the team in Nova Scotia have been following.
In the context of--and in an environment where the U.S. government, both from a financial incentive with the IRA and the IIJA, or now draft proposed guidelines, EPA guidelines providing more clear requirements in terms of decarbonisation, to the extent that those are enacted, those obviously will be drivers for those investments, and of course in Canada, we know about the federal and the provincial climate and energy policy goals that are driving milestone achievements in 2030 with 80% renewable and closing coal plants, and now with the CERs towards a version of net zero by 2035. Those will all be drivers on decarbonisation.
On storm hardening and system resiliency type investments, of course in Florida, Archie and team are well into a 10-year program now. There had been some conversation that had been started with some of the customer stakeholder groups about whether perhaps that should be moderated somewhat in the more inflationary cost environment that was going on, but ultimately the evidence with Hurricane Ian and the commission there saw the value of those investments in terms of what it did for the resiliency of the system, and that program continues with vigor in Florida.
In Nova Scotia, the team here obviously very aggressive right now in terms of its vegetation management really, tree trimming, order of magnitude, Peter, I think $25 million a year right now being spent--
Correct, yes - almost double.
Almost double to what it was before, really trying to--you know, it’s own version of storm hardening without the same regulatory mechanisms that exist in Florida, but taking the important steps necessary to storm harden the system.
Anything else, Peter, that you’d say on that front?
I think you’ve covered it well. I’d just part of it is just good utility management practices as well. Scott mentioned our vegetation management - while the fires were certainly tragic for many Nova Scotians, we lost 30 wood poles over, I think it was 30,000 hectares, so it just reflected what Scott mentioned, the importance of vegetation management, making sure we don’t have the fuel on the ground adjacent to our infrastructure, to protect that. Then also on the floods, all of our hydro systems performed well under really extreme circumstances, so I think it just underlines the importance of strong asset management planning and good utility practices as well.
Thank you.
Thank you. The next question comes from Mark Jarvi of CIBC. Please go ahead.
Yes, thanks. Good morning everyone. Just wondering how the run-up in the 30-year U.S. treasuries gets factored into the Peoples Gas rate case. Obviously you took a different approach with Tampa Electric. How do you incorporate that into Peoples Gas and the evolving interest rate costs?
Yes Mark, it’s Greg. It doesn’t specifically get factored in, but obviously when we filed the rate application, we had assumed an increase in interest rates and have requested a higher allowed ROE. I would say that with the run-up in interest rates, it’s less controversial on a forecast of the interest rates, that obviously it’s supportive of higher ROEs as well, so I’d say it’s probably indirectly slightly positive, but it also puts us in a position where, depending on how the capital flows and the continued customer growth at Peoples Gas, we’ll probably have to re-evaluate sooner rather than later as to the timing of the next application after this one.
And there’s be no contemplation of doing sort of the inverse adjustment that was happening in Tampa Electric, that if bond yields receded, that there would be a retroactive--or sorry, an adjustment on the allowed ROE [indiscernible]?
Yes, that was a result of settlement agreement. That’s certainly something that we would be open to if we found ourselves in settlement discussions, but unlikely to be achieved on a litigated hearing, which is currently the path we’re planning for.
Sounds good, okay.
Just on the recent EPA proposal, just wondering when you think about the units at Tampa Electric here, [indiscernible], you’ve talked before about Polk and, I think, Big Bend, about CCS and how you’re blending [indiscernible] units. At that point do you have to make a decision on how fast you pursue that, and then also, is there a decision between investing your own units or thinking about purchase power ramping up a bit more?
Archie?
Sure, good morning Mark. The proposed EPA rules really had a pretty modest impact on our generating fleet in Tampa. The only units that are implicated in the guidelines as currently written would be Big Bend 4, which is the single remaining coal-fired unit we have in the fleet, and the modernized Big Bend unit, the gas-fired 1,100 megawatt natural gas facility that Scott referenced in his opening remarks.
In order to comply with the EPA guidelines, all Big Bend 4 would have to do is invest in the ability for Big Bend 4 to co-fire 40% natural gas. We already have the ability to co-fire 100% natural gas, so for all intents and purposes, as long as that unit retires before 2039, which is roughly in the time frame when we would be expecting that unit would retire in its natural course, we’re good there.
On Big Bend modernization, there is an expectation that by 2032, we would have to either be introducing hydrogen as a fuel source in addition to as a supplement to natural gas, or investing in CCS. Our belief at this point is that there will be sufficient flexibility embedded within the EPA to allow--in the EPA regs to allow a little bit of trading within the utility itself, meaning the work that we are intending to undertake at Polk, provided we get comfortable with the business case, etc., will more than make up for what we would need to do on Big Bend 1.
As we think about where we are, the assets that we have and the plans that we have in front of us, we feel we are in extremely good shape to be complying with the EPA regs, to the extent they ultimately are enacted.
That’s good to hear, thanks for that, Archie.
Just one last question for Greg, just in terms of not seeing the ATM usage here in the first half of the year. Is that partly just a reflection of the deferral of the investment in LIL?
Yes, it’s a combination of things, Mark. Obviously share price has been depressed, but maybe equally so the volatility around it has been hard to land on. But yes, we’ve seen significantly stronger cash flows, in particular the fuel recoveries that we had, and we’re deferring some capital, but you should expect that you’ll see us back into the ATM market in the second half of the year, kind of consistent with prior periods.
Okay, thanks everyone.
Thank you. The next question comes from Andrew Kuske of Credit Suisse. Please go ahead.
Thanks, good morning. I guess the question is for Scott. You gave a pretty favorable backdrop for a lot of the potential in Atlantic Canada, and I guess maybe not to get too political, but when you look at just some of the incentives that have been given to the automotive battery industry in Ontario, do you think Atlantic Canada needs some similar incentives to really stimulate the offshore wind, green hydrogen, and then increased electricity transmission that goes with all of that, to really get things going in a very positive fashion?
Look Andrew, I think as it relates to the development of wind in Nova Scotia, I think two things are true. One is onshore wind is generally more economic than offshore wind; however, what’s intriguing about offshore wind is the degree to which it blows at times when it’s not as windy onshore; in other words, does it provide more capacity factor. From a grid perspective, that’s where offshore wind could have some helpful contribution to continuing to advance the journey to cleaner energy.
In terms of the development of offshore wind in support of hydrogen, yes, I suspect, I believe that that industry requires some of the clear intended financial support that came out of Budget ’23 in order to accelerate that industry, and that’s good. I think that exactly makes sense in order to take advantage of that resource development opportunity here.
But I think getting back to the broader and more important message from my perspective, the reality around the journey to net zero electricity in Canada, I think there’s a few things that are important to recognize. First of all, the Canadian grid is already one of the cleanest in the world - 85% non-emitting, and the cost to move from 85% to net zero is significant and, frankly just like anything, the last few steps are the hardest and the most expensive. That will be true here too.
But the particular challenge is it’s not uniform across the country, and some provinces are blessed being much closer to that end point today than other provinces. Nova Scotia is one of those other provinces where this will be particularly challenging, just given the situational environment that we’re in, the size of the province, the nature of the historical generation sources that exist here, and the available sources that are native to the province. We’re just not blessed with some of the same benefits that other provinces do, and therefore yes, it will be particularly important in order to achieve the ambitious climate and energy goals that have been set for significant financial support in order for those goals to be achieved.
Appreciate that color. Maybe just keeping it in Nova Scotia, with some of the basic blocking and tackling you can do at NSPI, obviously the population growth is helping and that looks more secular in nature, maybe structural in nature right now. But when we look at things like heat pumps, maybe if we could get an update from Peter on just heat pump rollout, how that looks as part of a bigger, broader decarbonisation effort, not just of--it’s really not of electricity but of the overall energy consumption in the province.
Yes, we’re certainly seeing positive impact. We’ve seen that over the last several years as the penetration of heat pumps continue to grow in Nova Scotia. We continue to see that contribute to--while we’re a winter peaking jurisdiction, to revenues happening in the summer months as people deal with the warmer weather, so it certainly is helping grow the load here in Nova Scotia. We expect to see that continue.
We’ve still got, I think it’s just a little under 30% of our customers across the province use home heating oil as their primary source, and so there’s a real opportunity to see continued penetration of heat pumps across our service territory.
That’s great, thank you.
Thank you. The next question comes from Dariusz Lozny of Bank of America. Please go ahead.
Hey guys, morning. Thanks for taking the question.
Just wanted to circle back to the FFO to debt quickly. I think you guys mentioned just under 11% for the trailing 12 months, and I believe the target for ’23 is at least 11.5%, so just doing the back of the envelope math there suggests that you’d be on track for just north of 12% in the second half of the year. Can you confirm if that’s the case and you’re still tracking to 11.5% or higher for the full year?
Yes, we’re still tracking to kind of mid-11s, Dariusz. Obviously moving the investment, the planned investment in the Labrador-Island Link is probably about 15 basis points on our expected credit metrics on an annualized basis, and of course we’ll have the full benefit of the cash flow from the Labrador-Island Link in the second half of the year as well, so to your point, we’re certainly trending in the direction that we would have expected.
Great, thank you. One more if I could. O&M, pretty substantial year-over-year jump. Can you maybe unpack that a little bit? Obviously inflation is a meaningful contribution. Can you also speak to customer growth, any other substantial drivers that you’re seeing, and how you expect those to shape up for the balance of the year?
Sorry, I missed the first part of it, Dariusz - O&M at the--?
O&M, just the O&M line item, if you could potentially speak to the contributions from respectively inflation, customer growth, or any other drivers that you’re seeing.
Yes, at the corporate level from a pure costing perspective, we are seeing very little change. Most of the change you’re seeing year-over-year is just the timing of our long term compensation expense, which has some volatility related to share price and the related hedges that we have in place. But from a corporate perspective outside of interest and the share-based compensation, our core operating costs have been relatively flat on a year-over-year basis.
Got it, okay. Thank you guys.
Thanks Dariusz.
Thank you. The next question comes from Patrick Kenny of National Bank Financial. Please go ahead.
Yes, good morning guys. Just on the carbon capture opportunity down at the Polk power station, and recognizing it’s very early days, as you mentioned, but just given we’ve seen a bit of a slower pace here in Canada on CCS development and government support, could you just provide your take on what the earliest time frame might look like in terms of deploying capital for that investment?
Good morning Patrick, it’s Archie again. I think--so this is a very, very active file for us down in Tampa, looking at what we refer to as the promise of Polk. The phase that we’re in now--so we’re fortunate that we’re getting support from the U.S. Department of Energy on the monies that they have earmarked for our frontend engineering studies at Polk, to the tune of $11 million so far, which is a pretty substantial portion of the overall investment that we’re making thus far.
Our efforts right now are in completing those engineering studies. We anticipate that in 2024, we would be filing the applications for the Class 6 wells that are necessary to store the carbon beneath the Polk power station. Meaningful capital spending likely doesn’t begin until 2027, something like that, based upon the trajectory that we’re on, and realistically we wouldn’t think we would have--to the extent we undertake a CCS project at Polk, it’s probably not completed until 2031 or so, which again would be in line with the timelines that are set out in the proposed EPA regulations.
Okay, that’s perfect. Thanks for that, Archie.
Then maybe just for Greg, to come back to the discussion around the equity portion of the funding plan, so just given the pullback on the ATM, could you just refresh what your capacity for additional hybrid securities might look like going forward, and also any other thoughts around potential refinancing opportunities to perhaps mitigate the impact of rising financing costs?
Yes Patrick, we have probably somewhere around $500 million to $1 billion of capacity on our balance sheet to do either Canadian dollar preferred shares or some kind of hybrid offering. Obviously that market is not very attractive right now. From a debt perspective, if you look at, I think it was Slide 11 in our presentation, half of the rise in interest costs have been at Tampa Electric, and that’s likely, as I referenced earlier, an opportunity for us to term out some of that short term debt into long term debt, albeit it will still be more expensive than it was a year ago. But the way the yield curve is right now, there’s some opportunity to reduce the exposure and reduce our overall costs over the balance of the year by terming out some of that debt.
Okay, that’s great. Thanks guys, I’ll leave it there.
Yes, thanks Patrick.
Thank you. Once again ladies and gentlemen, if you do have a question, please press star, one at this time.
There are no further questions at this time. I will turn the call back to Dave Bezanson for closing remarks.
Thank you very much. Before wrapping up, please note that our next analyst call will be held on November 10, and as Greg mentioned, we will be rolling forward our capital and funding plans as per usual at that time.
Thanks very much, and have a great day.
Ladies and gentlemen, this does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.