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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning, ladies and gentlemen, and welcome to Emera Inc. Q4 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]
I would now like to turn the conference over to Mr. Dave Bezanson. Please go ahead, sir.
Thank you, Laura, and thank you, all for joining us this morning for Emera’s fourth quarter 2022 conference call and live webcast. Emera’s fourth quarter earnings release was distributed this morning via Newswire and the financial statements, management’s discussion and analysis, and the presentation being referenced on this call are available on our website at emera.com.
Joining me for this morning’s call are Scott Balfour, Emera’s President and Chief Executive Officer; Greg Blunden, Emera’s Chief Financial Officer; and other members of Emera’s management team.
Before we begin, I’d like to advise you that this morning’s discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide. Today’s discussion and presentation will also include references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure.
And now, I will turn things over to Scott.
Thank you, Dave, and good morning, everyone. This morning we reported adjusted annual earnings of $850 million and adjusted earnings per share of $3.20, continuing our track record of delivering strong, predictable earnings growth and supporting ongoing dividend growth for our shareholders.
Excluding the receipt of a CAD$63 million litigation settlement representing $45 million of after-tax earnings, our annual adjusted earnings of $805 million represent our highest ever up 11% year-over-year, largely driven by continued strong growth in Florida and strong performance at Tampa Electric in particular.
The performance at Tampa Electric was largely driven by new base rates in support of the significant customer focused investments being made and by the impact of more favorable weather than expected. Our adjusted earnings were also bolstered by strong performance at Emera Energy.
Excluding the positive litigation settlement, our fourth quarter adjusted earnings per share was $0.76 and annual adjusted earnings per share was $3.03. This represents an 8% increase in annual adjusted earnings per share year-over-year. Despite what was a very challenging year on a number of fronts, including two major storms, Hurricanes Fiona and Ian, global economic pressures, supply chain disruptions, rapidly rising interest rates and record setting inflation, our business continued to deliver for our customers and our shareholders.
The fact that our business performed so well in 2022 in the face of these challenges reinforces the strength of our diverse portfolio of assets, our strategy, and of course, our team. Our regulated portfolio continues to be the primary driver of our growth. Regulated earnings contributions have been steadily and predictably increasing as we continue to make rate base investments to reduce carbon emissions and increase reliability all while doing so in the most cost effective way possible for customers.
Our recent fuel and storm cost recovery filing in Tampa Electric is a clear example of our commitment to balancing the need to collect and prudently incurred costs with what is more manageable for customers in terms of rate impacts. Due to the sheer size of the under recovered fuel balance, we proposed to the regulator in Florida that we extend the recovery of fuel costs from 2022 over 21 months, where normal practice would be to collect these costs over 12 months.
While global fuel prices are beyond our control, stretching out the recovery period helps ease the impact to our customers. This solution is similar to what we did in 2021 when a New Mexico gas incurred over $110 million incremental fuel cost as a result of Winter Storm Uri. While New Mexico gas typically has a one month true up of gas cost through their gas adjustment mechanism, we proposed recovery of those costs over 30 months to assist customers and help manage costs, and that approach works in New Mexico, the balance of those 2021 fuel costs will be fully recovered over the next 10 months.
We have a similar story at Nova Scotia Power where we have a history of being flexible with our fuel rates in order to collect fuel costs from customers over a longer period than one year, providing customers with rate stability. In 2022, we saw the end of a fee -- a three-year fuel stability agreement, and our most recent settlement provides for the fuel deferral to be collected over a two-year period rather than one.
This year, the team executed on one of our largest annual capital programs to date. And even with the backdrop of sudden inflationary pressures and challenging global supply chain disruptions, we kept our large capital projects on time and on budget. In December, we completed the Big Bend Modernization project. I’m incredibly proud of the team that delivered this ambitious and transformative project on time, under budget, and most importantly, safely.
In 2022, the Tampa Electric team deployed almost $1.5 billion of capital investment while achieving their lowest ever OSHA injury rate and lowest ever lost time injury rate both well below the industry average. The team achieved a milestone during the year of more than 6 million hours or 457 days without suffering, an incident required an employee to miss a day of work.
Other similarly impressive safety milestones were reached across many parts of our business. This is meaningful progress on our journey to world class safety and while we can never rest when it comes to safety, I’m proud of our progress and what the team achieved in 2022. With the completion of this project, Big Bend is now one of the most efficient natural gas plants in North America. It can produce 1,090 megawatts of energy.
In addition to reducing emissions and delivering on our cleaner energy commitments, the Big Bend Modernization project is estimated to save customers more than $700 million on a net present value basis over its 30-year life. Tampa Electric also achieved another significant milestone in their solar program with over 1,000 megawatts of solar generation now in service. With this achievement, Tampa Electric continues to have the highest proportion of solar generation per customer of any utility in Florida.
Our investments in solar have not only allowed us to decrease the carbon intensity of our generation mix. They’ve saved our customer’s money over US$80 million in 2022 in avoided fuel costs. Similarly, in Atlantic Canada, our investment in the Maritime Link saved Nova Scotia customers almost $100 million in 2022 by replacing expensive carbon generation with clean hydro energy.
And these are net savings to customers representing approximately $250 million in avoided fuel costs netted against the total cost of the link incurred by customers and rates through 2022. The energy we’re receiving through the Nova Scotia block over the Maritime Link will continue to deliver significant value to customers for decades.
We’re also investing heavily in improving the reliability of the grid, and 2022 demonstrated how these valuable investments are -- how valuable these investments are for customers. Tampa Electric’s storm hardening investments made under the Florida’s storm protection plan proved to be very effective at reducing the number and duration of outages resulting from here Hurricane Ian.
And while Nova Scotia Power and its customers don’t have benefit of the same focused government policies in Florida, Nova Scotia Power does continue to make significant investment in reliability with $180 million of investment in transmission and distribution in 2022, which is 51% more than 2015 investment levels.
And while we continued to work to make the system even more reliable every day, Nova Scotia Power is currently ranked number one in terms of the total outages -- total number of outages and total number or duration of outages among utilities in Atlantic Canada, and Maine, which operate in similar wind and weather conditions to Nova Scotia.
Earlier this month, Peoples Gas completed construction of its first RNG facility. Peoples Gas is now the first utility in Florida to deliver renewable natural gas to its customers as a reliable and cost effective energy source. The New River project that was put in service on February 1 of 2023 should generate enough RNG to fuel 17,000 homes a year, reduce the landfill’s methane emissions by about 14,000 tons per year and help reduce emissions by more than 34,000 tons per year.
Across the portfolio, we’re bringing the asset management expertise that we’ve developed through Emera Energy to our gas utilities in an effort to add additional value for our customers. At New Mexico Gas, asset management agreements or AMAs were implemented to generate incremental value from periods when New Mexico Gas is not using all of its pipeline capacity. These AMAs generated over US$45 million of value in 2022, of which 70% or $31 million was returned to customers through the gas adjustment mechanism and the remainder contributed to the higher earnings we’re reporting in New Mexico Gas in 2022.
In addition, last year, the team in New Mexico applied to the regulator for approval to begin construction on $180 million liquefied natural gas storage facility to help ensure reliable gas for – reliable gas supply for New Mexico customers and reduce customer exposure to gas price volatility.
These are all great examples of our strategy in action. And they highlight our commitment to not only deliver cleaner energy, but to do so in the most cost effective manner and at the most cost effective pace for our customers, while supporting system reliability. We are reducing our customer’s exposure to volatile fuel prices by building renewable generation and storage. These projects have not only generated fuel savings for our customers, but have also allowed us to make meaningful progress decarbonizing the energy we provide them.
In 2022, I’m proud to say that less than 20% of our generation came from coal compared to almost 60% in 2005. This represents a 68% reduction in coal used for generation right across Emera. And at the same time, thanks in large part to investments in solar and the clean hydro energy being delivered by the Maritime Link. Generation from renewable energy increased from 4% of our generation mix in [indiscernible] to 16% of our generation mix across the portfolio last year.
In Nova Scotia, where we’ve been on the decarbonizing journey for much longer, we now have well over a third of generation coming from renewables and that number continues to grow. We’re proud of our progress to date. But as government climate goals approach, there is significant and challenging work ahead. In Canada, both the federal government and the provincial government in Nova Scotia have ambitious climate goals. When we conceived of the idea of the Atlantic Loop, we believe that it represented the best solution for the Atlantic region and most importantly for our customers here in Nova Scotia. That has not changed.
While the passage of Bill 212 here in Nova Scotia effectively restricts our ability to directly invest in the Atlantic Loop, but as the operator of Nova Scotia’s energy grade, the team at Nova Scotia Power is still working hard to enable this solution, because we know it’s the most cost effective solution for our customers to enable the closure of coal plants in Nova Scotia without putting system resiliency or reliability at risk.
Working in partnership with federal government, we’ve stayed engaged to support the essential engineering and planning work needed to continue to move the Atlantic Loop project forward. We understand that the federal government intends to provide a very meaningful funding support proposal for the project and we remain both optimistic and actively engage to ensure the needs of customers and stakeholders remain in focus.
Last quarter, we announced our 2023 to 2025 capital plan of $8 billion to $9 billion, driving expected rate base growth of 7% to 8% over the forecast period. Over 75% of our three-year capital program will be invested in our Florida operations, driven largely by the significant economic growth in the state. Florida was the fastest growing state in the U.S. last year and is today one of the 20 largest economies in the world.
Steady migration into the state has continued and both our Florida utilities have experienced significant customer growth in excess of 2% Tampa Electric and approximately 5% at Peoples Gas in 2022. Our capital deployment in Florida reflects this growth as the economies and populations and our service territories grow, so does the magnitude of prudent and necessary capital investment to service that growth and deliver reliable energy for our customers.
2022 was a busy year for us on the regulatory front. The year began with the approval of the final cost application for the $1.8 billion Maritime Link project, with no significant or material adjustment to costs of this highly complex project demonstrating the experience and excellence of the team’s multi-year project management efforts.
Rate application of Barbados Light & Power progressed and we were granted interim rates in the fall. Earlier this month, the regulator in Barbados issued a decision on Barbados Light & Power’s rate application and requested an additional compliance filing before setting final rates. We expect final rates later in 2023. We filed an unopposed settlement agreement at New Mexico Gas in the spring and that was approved by the regulator just before year-end for new rates now in place.
And in Nova Scotia, of course, we filed a settlement agreement late last year, that was signed by all customer groups, municipal utilities, including groups representing low income customers and environmental advocacy. The regulator substantially approved the settlement as filed earlier this month. As I look forward, we have a somewhat lighter regulatory calendar in 2023. We expect a decision from the Florida Public Service Commission later this quarter on Tampa Electric’s fuel and storm cost filing.
The only new rate application we expect this year will be at Peoples Gas. PGS filed a test year letter earlier this month indicating their intention to file for new rates effective January 1, 2024. Since their last rate increase in 2021, Peoples Gas has deployed more than $1 billion of rate base investment to serve the growing population of Florida and ensuring the system continues to operate safely and reliability.
Our results in 2022 demonstrate our strength in delivering value for customers and in turn, our shareholders, despite some very real challenges. I’d like to thank the entire Emera team for their continued dedication, expertise, and resiliency. In 2023, we remain focused on advancing our strategy and we remain committed to an energy transition that takes a balanced approach, making meaningful progress towards a greener energy future while ensuring we deliver reliable energy as cost effectively as possible for our customers. I believe that our strategy is driving a balanced energy transition that continues to deliver value for customers and our shareholders.
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. This morning, we reported fourth quarter adjusted earnings of $249 million and adjusted earnings per share of $0.93. Our results this quarter included the recognition of a CAD$45 million after-tax settlement related to offsetting litigation, which represents $0.17 of adjusted earnings per share.
Normalizing for the impact of this one-time settlement better highlights the performance of our ongoing business. Excluding the impact of the litigation settlement, adjusted earnings were $204 million for the quarter and adjusted earnings per share was $0.76. For the year, excluding the impact of the litigation settlement, adjusted earnings were a record $805 million and adjusted earnings per share was $3.03.
This represents an 11% increase in adjusted net earnings and 8% growth in adjusted earnings per share year-over-year. Growth in adjusted earnings per share for the quarter was primarily driven by new base rates and continued customer growth at Tampa Electric, higher earnings from a marketing and trading business and the impact of a weaker Canadian dollar.
These increases were partially offset by lower contributions from our Canadian utilities, higher corporate costs, primarily driven by the timing of share-based compensation expense and related hedges and higher share count.
Over the last number of years, we have continued to deliver earnings growth in excess of dividend growth. As a result, we have made measurable progress in reducing our dividend payout ratio. Excluding the positive impact of the litigation settlement, our payout ratio in 2022 was 88%. This is a clear example of our plan to improve our target payout ratio over time with earnings per share growth in excess of dividend growth.
Operating cash flow was challenged this year by the significant fuel under recovery and storm costs incurred primarily at Tampa Electric. It is important to highlight that absent these factors, we would’ve seen a 45% increase in operating cash flow, primarily driven by growth in our regulated utilities.
The fuel under recovery and storm costs at Tampa Electric represent approximately 750 million Canadian dollars of operating cash flow that will be collected through the regulatory recovery mechanisms available in Florida for this specific purpose. And earlier this year, Tampa Electric filed an application with the Florida Public Service Commission for recovery of the fuel and storm under recoveries. Tampa Electric has proposed recovery in the storm costs over a 12-month period and the fuel costs over 21 months in an effort to better manage costs for customers. We expect a ruling from the FPSE in March, and if approved, we’ll begin collection on April first.
When you adjust for the impact the legal settlement mentioned earlier, adjusted earnings per share has increased by $0.08 or 19% over Q4 2021, largely driven by the strong performance of our regulated utilities and higher contributions from Emera Energy. Tampa Electric’s results benefited from new rates and continued strong customer growth in excess of 2%.
Emera Energy’s marketing and trading business delivered an impressive $39 million of earnings, a record fourth quarter for the business. Favorable weather created strong market conditions with the – which the business was able to capitalize on during the quarter. It is noteworthy that Q4 built [indiscernible] year, resulting in the second best year ever for our Emera Energy’s marketing and trading business. This year’s results demonstrate the significant upside potential from Emera Energy that we often talk about. The strength of the U.S. dollar increased adjusted earnings per share by $0.07 for the quarter.
At our gas utilities, New Mexico Gas delivered a U.S.$7 million or 47% increase in earnings compared to Q4 2021. This was driven by favorable asset management agreements that the business entered into to utilize excess pipeline capacity. And due to a combination of market conditions and weather in the region surrounding New Mexico Gas during December, these AMAs earn significantly more than they have historically.
As Scott mentioned in December alone, the AMAs generated approximately U.S. $34 million of benefit of which 70% will be returned to customers and the remaining U.S. $10 million before tax contributed to higher earnings for the quarter. These AMAs are a great example of how the commercial expertise that we have developed in one affiliate can be shared throughout the business to benefit both customers and shareholders alike.
And given the solid performance at Peoples Gas during the quarter, we did not recognize any of the accumulated depreciation reserve in the fourth quarter. We therefore continue to have access to U.S. $20 million of the reserve to recognize in 2023. And excluding the litigation settlement, corporate costs increased $39 million this quarter, largely driven by the timing impacts of the share based compensation expense and related hedges, higher interest expense and realized losses on foreign exchange had just compared to realized gains in 2021.
Our Canadian utilities experienced a challenging fourth quarter, milder weather in Nova Scotia in addition to higher storm regulatory and other operating costs decreased contributions from Nova Scotia Power compared to Q4 2021. In addition, as a result of lower energy flows from Nalcor, contributions from our transmission investments decreased in the fourth quarter due to the Maritime Link holdback.
And finally, higher share count decreased quarterly adjusted EPS by $0.03. For the year, adjusted earnings per share increased $0.39 to $3.20. Excluding the impact of the legal settlement, adjusted earnings per share increased by $0.22 or 8% year-over-year driven by new base rates of favorable weather at Tampa Electric, higher contributions from our gas utilities, Emera Energy and the impact of a weaker Canadian dollar.
Weather is always a factor in the energy business and is one of the main drivers that can result in over or under performance in any given period. One of the strengths of our portfolio of high quality regulated assets is its geographic diversity.
In Florida, we experienced weather that was more favorable throughout 2022 than expected, and more favorable even compared to 2021. Favorable weather in combination with new base rates that were in effect for the year and continued customer growth drove a 24% increase in U.S. dollar contributions from Tampa Electric in 2022.
And similar to the quarter, higher earnings in our gas utilities were driven by the impact of the AMAs at New Mexico Gas as well as continued 4% to 5% customer growth at Peoples Gas. Excluding the impact of the weaker Canadian dollar, our gas utilities delivered $13 million or 8% growth in earnings year-over-year.
Contributions from Emera Energy increased $16 million during the year compared to an already strong 2021. And the increase in corporate costs and decrease in contributions from gain [ph] utilities were driven by factors consistent with those that impacted the quarter as discussed a moment ago.
And finally, higher share count decreased adjusted EPS by $0.10 for the year. Throughout 2022, we’ve highlighted the continued material impact of fuel under recoveries, primarily at Tampa Electric and the impact on cash flow. We’ve often discussed the well-established regulatory mechanisms in place to recover prudently incurred fuel and storm costs in Florida. And with a recent filing for the recovery of these fuel and storm costs at Tampa Electric, there’s now a clear line of sight into when the impact and operating cash flow will reverse.
However, these short term under recoveries have also had the meaningful impact on our debt balances, which is less often discussed.
In Florida, we will collect the short-term interest rate on fuel balances through our regulatory recovery mechanism, and therefore these are funded with short-term debt. This means that our short-term debt balance at the end of 2022 is elevated by the under recoveries.
Between 2021 and 2022, the total fuel under recovery at Tampa Electric was U.S. $518 million, and the storm cost deferral is U.S. $130 million or over 860 million Canadian dollars in total. These have been funded with short-term debt at the utility, which both elevates our total debt balance and increases the weighting of variable rate debt in our portfolio. But much like the impact on cash flow, the impact on our debt balance is also temporary. As fuel and storm costs are recovered from customers, their associated debt balances will be repaired.
If the applications for the storm and fuel costs recoveries at Tampa Electric are approved as filed, we will collect approximately a U.S. $100 million of storm costs and U.S. $220 million of fuel costs in 2023, which will be used to repay the associated short-term debt. The remaining balances will be collected in 2024. The other factor that has had a material impact on our debt balance at the end of the year is foreign exchange.
Approximately 70% of our debt portfolio is U.S. dollar denominated. On consolidation, these balances are translated to Canadian dollars at the spot rate. The spot rate at December 31 was $1.35, which elevated our debt balances at the end of the year. It should be noted that the U.S. dollar denominated debt acts as a hedge against the U.S. dollar assets and earnings. And as a result, there’s no underlying economic exposure.
For planning purposes, we have used a foreign exchange rate at a historical five-year average of $1.30, which coincidentally is the actual FX rate realized under 2022 U.S. dollar cash flow.
The impact to our debt balances is significant between fuel and storm costs under recovery and the impact of foreign exchange, our debt balance is $1.3 billion higher than expected. Rating agencies each have their own methodologies for calculating both cash flow from operations as well as debt balances for credit metrics.
We believe that looking through the impact of the temporary timing differences in cash flow collection from fuel and storms and normalizing for the disconnect between foreign exchange translation on cash and debt balances best reflects our true cash flow and debt profile.
Based on these adjustments in our view, our cash flow debt metric was approximately 11% in 2022. Our experience this year does not change our view on our operating cash flow profile going forward. And we have a clear path to achieve our cash flow and credit metric objectives.
At our Investor Day next week, we will be walking you through our expected changes in both operating cash flow and debt to show the path to credit metric improvement. And with new rates across the portfolio this year, strong customer growth continuing in both Florida and Nova Scotia, and a proven strategy of investing in a rate base to deliver cleaner and more reliable energy for our customers. We are well positioned, deliver both earnings and cash flow growth, providing value to shareholders and maintaining our investment grade credit ratings.
Thank you. And with that, I’ll now turn it 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. [Operator Instructions] Your first session comes from the line of Mark Jarvi from CIBC. Please go ahead, sir.
Thanks. Good morning, everyone. Greg, the question for you with the – at the market program, is expectation you’ll renew that in 2023 and just maybe will sort of the level of activity be comparable to the – what you did in 2022?
Mark, at this point in time, we would expect to renew that. It’s been a very cost effective way to raise equity as we require. And it is part of our funding plan as you know going forward. And so we would continue to expect under normal circumstances to access that market for around $250 million on average each year.
Okay. And Scott, I have a question for you. In terms of your comments around the Atlantic Loop and sort of tempered enthusiasm to invest there. Just sort of updated, what would change your tone in terms of willingness to invest? And I guess also if you think about some of the challenges in getting Labrador-Island Link up and running, do those types of issues in terms of startup issues delay your enthusiasm for a large transmission project investments going forward?
Yes, thanks, Mark. To start with your second question, no, they don’t, I think, the issues that the Nalcor is having with their Labrador-Island Link asset really has nothing to do with Emera directly. Our confidence and our ability to design, build, operate large scale transmission assets, I think, is best demonstrated by the Maritime Link project and putting that into service on time and on budget and having it operate as expected and now delivering meaningful value to shareholders, sorry, to customers, meaningful value to customers.
On the Atlantic Loop, really, it’s largely about having a confidence in the ability to invest in a project and to have confidence that there would be a return on and return of that investor capital that we would be putting to work. And Bill 212 puts some concern obviously about that at large scale for a new project. So that’s really the consideration in terms of where we’re at now. But we continue to believe that this is an important project for Nova Scotia, an important project for Nova Scotia Power customers. And that’s why the team at Nova Scotia Power is working with its government partners to do everything we can to help enable that project to as cost effectively and as efficiently from a system perspective as possible to enable the closure of coal plants here in Nova Scotia.
I guess my question, is it completely ruled off or is there password potentially with federal government support or updated discussions with the provincial government that you could see prudent recovery of a larger investment?
At this point Mark, I’d just say it’s too soon to say. We’ve certainly made our position clear as it relates to the effective restriction that Bill 212 has put on our ability to secure the investment and make the investment required. So, really it’s up to government partners at this point to help create that path forward. But we’re doing everything that we can to enable it.
Understood. All right. Looking forward to the update next week. Thanks.
Thank you. Your next question comes from the line of Maurice Choy from RBC. Please go ahead.
Thank you, and good morning. My first question, I want to still come back to Slide 13, the cash flow to debt metric which I know your plan is to be above 12% on a sustainable basis. You mentioned that you are exiting 2022 at around 11%, and that’s obviously a proper improvement from what it was in Q3. What do you expect to finish this year in 2023 at assuming that the regulatory matters at Tampa Electric go as you filed and FX stays at $1.25 [ph] or even $1.30 that you use in this assumption?
Yes, Maurice, we’ll provide a little bit more color and detail around that next week. But we’re on a path to show a continued improvement from the 11%. I think with the new rates that are in place at New Mexico, Nova Scotia Power and Tampa Electric, we will comfortably allow us to get to it at a minimum 11.5%. And we’re still working through some other items that we will provide – we hope some upside to get closer to the 12% in 2023.
Thanks. It may be is a follow-up to these other items that you just mentioned. Obviously being above 12% is what your plan is positioned for you to be at. There’s obviously quite a bit of room for interpretation of what you view to be an ideal range above 12%. For example, 12.1% meets your goal, but being at 12.5% to 13% offers you some cushion and balance sheet flexibility, particularly given the role that we live today. So just some thoughts on as to how you might approach where you ideally like the metric to be?
Yes. It’s a fair question, Maurice. No point should you interpret that we want to be at 12% a sustainable basis that we think the 12.1 is the right number. I think if you look at the – probably the reasonable and fairly well baked plan we have in front of us to get to 11.5 plus in 2023. So I’ll call it a 50 basis point improvement. We would like to target some kind of level of improvement of around 50 basis points each and every year over the forecast period. And then that should give us kind of around 100 basis points plus cushion versus the 12% target.
Great. Thanks for that color. And maybe I could just finish off with Big Bend. Now that Unit 1 has been repowered and obviously well done for delivering this on time and under budget as you said, Scott, which is not an easy feat these days. Unit 2 has been retired. Unit 3 is well on its way this spring. What future plans do you have for Unit 4, if any?
Yes, I think, Archie Collins is on the line. Archie, do you want to respond to that?
Sure. Happy to do that. Good morning, Maurice. Big Bend 4, we just last year in 2022, we actually made a fairly significant capital investment in Big Bend 4 to that allows that unit to achieve full load 480 megawatts on natural gas. We also have the ability to consume 100% coal in that unit. So we’ve got a lot of flexibility in that asset. Now we’re able to play off one fuel against the other and determine what’s the most cost effective for customers at any point in time. We like that level of flexibility. It adds a little bit of diversity into our portfolio. We know that means it’s sort of keeping coal around a bit longer than some stakeholders might like. So that’s an ongoing debate that we have within the company. But at least for the foreseeable future, we see value in that flexibility and we’re going to continue to keep that asset available on either natural gas or coal.
Great. Thanks for the color and taking my questions.
Thank you. Your next question comes from the line of Ben Pham from BMO. Please go ahead.
Okay, thanks. Good morning. I’m wondering with the gas price movement which we’ve seen year-to-date. How do you think about that impacting your business maybe direct or indirect?
Maybe I’ll start with – go ahead, Scott. Sure, please.
Yes, that’s fine Greg, if you want to go.
As you probably can tell Ben, we’re not in the same room at the moment. Yes, so, Ben, part of the fuel filing that we did at Tampa Electric to recover the under recovery of 2022 fuel costs over the 20-month period in 2023 and 2024. As part of that, we had to provide an update on fuel costs for 2023 at Tampa Electric. And at this point, we’re forecasting to have a fairly significant over recovery of fuel costs. And there’ll be – we’ve proposed an adjustment to customer rates to turn that back to customers over the balance of this year, so over the April 1 to December 31 period.
So, the decline we’ve seen has put us in a position where the fuel rate at Tampa Electric is actually higher than what we’re actually experiencing, and that’s probably the area where it’ll have the most meaningful impact to us. Obviously, lower gas prices help both Peoples Gas and New Mexico Gas as well in terms of the fuel component of customer bills. But really the most significant impact is the fuel cost recovery at Tampa Electric.
Okay. Got it.
Ben, I just add that it’s really helpful to our customers, right? It just – it helps to make the energy we’re providing to our customers more affordable. Obviously that was a real challenge in 2022, at the same time as inflationary pressures and other pressures that the customers were experiencing. So reducing fuel prices and obviously reduces rate pressure for customers and thus helps to ensure that we’re not putting undue pressure on customers’ bills.
Okay. Great. And then maybe going back to the balance sheet, and you’re exiting this year and in a good position. I’m wondering as you look forward, how does asset sales fit into the calculus for you guys as you look up towards [indiscernible]
Yes. I think Ben, I mean really no different than it always has is that from our view, first and foremost is, we’re executing on our strategy. And end of 2022 results, I think demonstrate the execution of that strategy and delivering cleaner energy to our customers investing in reliability and doing that in the most cost effective way for our customers is driving meaningful investment needs and is driving meaningful growth for shareholders too, including improvement of credit metrics.
And so we remain very confident in the path ahead for us. But we’re blessed with the diversification within our portfolio. And we always have – when we sort of consider our strategy and our portfolio over here, we’re constantly thinking about how best we allocate capital. And obviously, right now you’re seeing that with a significant amount of capital being invested in Florida, but we’ve demonstrated in the past when it makes sense for our investors to think about and recycling the capital or in the language that we’ve used optimizing our portfolio, then we’re very prepared to do that.
But as we sit today, we’re confident with the path of executing our strategy, delivering for our customers, and as we do that, continuing to drive the growth and earnings and improvement in credit metrics as we do that.
Okay. And maybe just a final follow-up on asset sales, I know, you went through a monetization program in the past some that was evaluation driven and some are just more focused on your core areas. Would you ever – let’s push comes down our shove, would you ever consider maybe monetizing maybe pieces of the best parts of your portfolio, we’ve seen some of those examples in the U.S. utility land. There’s one of your thoughts on that.
Yes. It’s a question that’s been asked before, Ben and I presume by that you mean our assets in Florida. And no, that would not be a strategy that we’d be considering. We consider those businesses, the driver of our growth and future. And so no, those – that would not be something that we’re is currently in focus. Yes, I do know that’s something that some peer utilities have done effectively. And so that’s always an option, but not something that we’re considering.
Okay. Thank you.
Thank you. Your next question comes from the line of Rob Hope from Scotia Bank. Please go ahead.
Good morning, everyone. Just two cleanup questions for me. First one is for Greg. Just relating to the 50 basis point improvement in the leverage metrics per year based off of the existing plan, just want to confirm that that is, we’ll call it an adjusted number and not reflecting kind of the incremental cash that you’ll get from unrecovered fuel then 2023 and 2024 out of Florida.
Correct.
All right. Thank you. And then just taking a look at Peoples Gas, the outlook for flat earnings year-over-year, can you just walk us through some of the dynamics there? Because you are seeing very strong economic activity and customer growth in the region, but is inflation as well as kind of this the sheer magnitude of capital that you put the work there kind of the key burdens there?
Yes. You’ve identified exactly the two issues, Rob, I mean, the business is performing very well but with that customer growth is requiring us to invest capital at maybe a little faster pace than we would’ve expected. And putting obviously pressure as a result of that because incremental capital comes with higher depreciation, higher financing costs, put a little bit of pressure on our expected ROE, which is why we are filing for new rates.
Probably secondary to that though would be the inflationary increases we’re seeing across to the Board. But the primary driver is just the timing of the deployment of capital support the customer growth.
All right. That’s great. Thank you.
Thank you. Your next question comes from the line of Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I’m wondering if you could help us understand your outlook for Nova Scotia Power in 2024. Do you think that there’s any hope of earning within your allowed ROE or do you expect at this point to under earn? Any contacts would be appreciated.
Yes. Thanks, Linda. It’s Greg. I’ll start. I think the settlement was a reasonable balance for the company and our customers. And as a result of that, we think there’s a assuming somewhat normal weather, we think there’s a reasonable path to earn at the low end of our band or near the low end of our band in 2023.
Still some work to be done in 2024. What the team is looking at and trying to identify opportunities. But at this point in time, we’d expect to be somewhat below the low end of the band. But is there I think you might have characterized, is there a hope that we could get there? Maybe, but I’m not so sure. Hope is a strategy, but the team is working at trying to identify a path to and we’re certainly committed to trying to get to the low end of the band in 2024 as well.
Thank you. And as a follow-up, just bigger picture and maybe you’ll be addressing us a little bit next week. Just wondering if you could give us an updated sense of views on the levelized unit energy cost in your jurisdictions for various forms of energy, whether it be solar, gas, coal in Florida, other, how might we think of for example unit for how much coal it might consume over the next couple of years based on your outlook for energy prices and recognizing that there’s been some inflationary pressures on solar, especially the land value in Florida.
Just interested to get an update on a unit basis, what your views are on energy cost? And I guess the second part to my question, and I realize this is a lot, is how much room do you see in your various grids for adding that intermittent source of power over time?
Yes. Linda, so we’ll take that away, obviously that’s a question with a longer answer than would be workable here, but we can work to try and give a sense of that. But you’re right. We’re seeing sort of the supply chain and real estate prices and inflationary pressures globally, as you know, we’re not necessarily seeing the continued reduction in the cost of some forms of renewable energy that’s not unique to Canada or the U.S. that would be a global phenomenon. But we can take that away and give you a bit more perspective.
Thank you.
Thank you. Your next question comes from the line of Dariusz Lozny from Bank of America. Please go ahead.
Hi, good morning, and thank you for taking my question. Maybe just to start a high level one, how would you characterize the environment and the key stakeholder relationships in Nova Scotia as you stand today, obviously there was a lot of consternation towards the end of the NSPI rate case, but you got a constructive outcome there. And perhaps how does that then manifest itself in your efforts to recover 2022 storm costs?
Yes. So I know Peter Gregg is on the line. Peter, do you want to respond at least to the first part of that question?
Sure. Thanks, Dariusz. Yes, bit of a tumultuous year, but I think the URB [ph] affirmation of the settlement was a good positive step forward, I think reflects meaningful ongoing discussions with the key stakeholders on this file. And I think really important that either Scott or Greg mentioned earlier, the number of customer representatives had signed onto that that settlement was significant and important.
I think the other thing I’d add is that we know we need to engage with stakeholders on a regular basis in a meaningful way. Perhaps we could have done a better job of that in the past. And it’s something certainly I and the team are committed to at our actively engaging in at this point.
Excellent. Thank you very much for that color. One more if I can. And this is again another relatively high level one. Are there any efforts are you may be considering any other ways to reduce the variability that’s in your results from one quarter to the next specifically from foreign exchange and also various impacts of long-term compensation? I realize those were perhaps somewhat outsize impacts from 2022, but maybe just as we look forward as far as efforts to improve visibility, reduce the variability. Are there any considerations on either of those fronts?
Yes. There is. It’s Greg. I think certainly with the initiation of a foreign exchange hedging program on our adjusted earnings that will certainly help. And we’re progressing our way through that and have a lot more hedged. And so I think that’ll leads certainly helpful. As we go forward, obviously on foreign exchange specifically, we have seen quite a bit of volatility over the last couple of years for a whole number of factors, which is probably continue – contributing to that. But kind of similar results, we do actually hedge our long-term compensation, but again, we’re finding ourselves in a position that you’d be very familiar with that we’re just seeing such market volatility that it’s just causing some timing differences. So I think on both foreign exchange and hedging of long-term compensation, as we get into more normal circumstances with more normal volatility, I think you’ll find that that’ll smooth out – smooth it out on a quarter-to-quarter basis.
Okay. Thank you very much. Appreciate those responses and look forward to next week.
Thanks, Jerry.
Thank you. Your next question comes from the line Andrew Kuske from Credit Suisse. Please go ahead, sir.
Thanks. Good morning. I guess, we’ll have a ample time to talk about Florida next week, while we’re there. But I’m going to focus my questions on Nova Scotia. And I guess, the first one really revolves around the province’s aspirations for offshore wind. How do you think about that from an NSPI standpoint? And not necessarily you being involved in offshore wind, but just the transmission interconnectivity. We’ve seen a number of regimes used around the world for the connectivity from offshore wind farms to the shore. How do you think about that right now on a high level basis?
Greg, Scott, do you want me to take that?
Yes. Sorry, may not come in. Yes. Peter, you can respond to that.
Sure. Andrew, a few points on that. I think there’s opportunity in Nova Scotia, I think both on onshore continued development of onshore wind and offshore wind. Our focus to date has really been on the onshore and with the – we often talk about the Atlantic Loop, but there – the project we are working on is called the Eastern Clean Energy Initiative, which involves the Atlantic Loop, but it also involves more development of onshore wind. Province did RFP bring some more proponents in last year. And those projects will continue, and I believe there’s even more room for onshore.
As we look, I know we have many discussions with potential offshore developers. We’re really looking at that from a transmission interconnectivity perspective. We’ll continue to have those discussions, if there are opportunities obviously for investment in the transmission assets we’d certainly look at that very closely.
Okay. Appreciate that color. And then maybe a bit more granular and kind of hot off the presses from yesterday with the feds in the province of Nova Scotia, just the heat pump subsidies that are coming. How do you think about that in relation to the core asset base of NSPI?
The way I think about that is, I think, there’s still a heavy reliance on home heating oil in Nova Scotia. So that’s a very positive thing for our customers, the subsidies to move into efficient heat pumps. We’ve had a program allowing for longer term financing for our customers to switch to heat pump hasbeen very successful. We’ve liked to see that, obviously, there’s a low growth opportunity through that electrification exercise and we think that that’s an important sort of longer term development.
Okay. That’s great. Thank you very much.
Thank you.
Thank you. Your next question comes from the line of Patrick Kenny from National Bank Financial. Please go ahead, sir.
Thank you. Good morning, everyone. Just on Block Energy, I’m sure we’ll be getting the full update next week. But just in later the volatility in fuel costs, wondering if you’re seeing any pickup in customer demand for the Block Energy platform, either in Florida or perhaps other jurisdictions where you might be looking to deploy the technology?
Yes. Patrick, the way it’s – I mean, it’s still early for us with Block Energy is, as we’ve effectively got pilot now in Florida and now working on a second pilot outside of Florida. And I think you’re right. I think the volatility of fuel prices and the impact that has on energy prices for customers is an important selling feature of the Block Energy Solution. But so too is reliability. And one of the things that was clearly demonstrated in 2022 through Hurricane Ian is the resiliency, the improved reliability that can be achieved with this product as Hurricane Ian, of course, ravaged Florida and resulted in a number of outages including, of course, in Tampa Electric service territory.
While those customers that were served with Block Energy continued want to have energy throughout that experience. So the combination of those two things continues to have us feeling excited and confident as to path forward for Block Energy. There’s certainly building interest from customers of all kinds in this Microgrid Solutions. But still relatively early days and certainly as you point out something that we’ll talk about more when we’re together in Florida next week.
Got it. And then, I guess, just from a larger scale perspective, just given the heightened level of interest in all things energy storage, whether it’s batteries, gas storage or developing pumped hydro. I know your three year capital plan is locked in, but just given the long lead times for some of these opportunities. Curious if your team is looking to bring any of these larger scale energy storage type assets into the portfolio by say the latter part of the decade?
Yes. You’re exactly right. The energy transition is – and this is in part going back to a question of Linda’s as well, but energy transition obviously has its challenges when a lot of the early moves in that transition is the build out of intermittent renewables. And most systems can take a good portion of intermittent renewables, but once you get to a certain percentage, at least in Nova Scotia and in Tampa Electric, that would sort of be in the mid to high teens of generation mix. It starts to get more challenging to avoid the degree of intermittency that is now on the system with that generation from not causing challenges with system reliability.
So therefore storage becomes important. And so, yes, absolutely storage is going to be an important part of the – continuation of the energy transition, the continuation of delivering cleaner and reliable service for customers. And you’re right, it’s going to be sort of storage of all forms. And that’s obviously a big part of the Maritime Link project in a way is finding ways to bring in storage in the form of hydroelectricity, which can have some of those advantages. Batteries obviously a big component. You heard me talk about LNG even for our gas utilities and that’ll continue to be a theme of our capital program well beyond our current three year forecast period.
Okay. That’s great. I’ll leave it there. Thanks, Scott.
Thank you. Your next question comes from the line of Richard Sunderland from J.P. Morgan. Please go ahead, sir.
Hi, good morning. Thanks for the time today. Just one quick one from me on the New Mexico AMA contribution. Curious if 4Q 2021 is a good normalized base there, meaning that year-over-year impact was all upside versus, I guess, normalized expectations also just under the current market dynamics. Any continuation of that upside into 1Q?
Hi, Rich. It’s Greg. Oh, sorry.
So go ahead, Greg. And then Ryan can add on.
Yes. I think, 2021 is probably more representative Rich of what we would expect on a normalized basis, obviously, we had some outperformance in 2022. I’m not so sure, 2023 will be back to 2021 levels, but I don’t think it’ll be at 2022 levels either. We’re still seeing some market dynamics of which you’ll create some upside potential, but not nearly to the extent that we saw in 2022.
Ryan, just want to add a little more color from your perspective.
Yes. I would agree with what Greg just said. I don’t think there’s anything further that I would add.
Great. That’s all from me. Thank you.
Thanks, Rich.
Thank you. There are no further questions at this time. I would now turn the call back over to Mr. Dave Bezanson for closing remarks.
Thank you, Laura, and thanks everyone for attending today. We look forward to seeing many of you next week at our Investor Day. Have a great day.
Thank you.
Thank you so much, presenters. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a lovely day.