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. If at any time during this call you require immediate assistance, please press star zero for the operator. I would now like to turn the conference over to Mr. Dave Bezanson. Please go ahead, sir.
Thank you, Lara, 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.
Now I will turn things over to Scott.
Thank you, Dave. 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 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 great 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 at Tampa Electric is a clear example of our commitment to balancing the need to collect on prudently incurred co-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 New Mexico Gas incurred over $110 million of incremental fuel costs as a result of Winter Storm Uri. While New Mexico Gas typically has a 1-month true-up of gas costs through their gas adjustment mechanism, we proposed recovery of those costs over 30 months to assist customers and help manage costs. 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 3-year fuel stability agreement, and our most recent settlement provides for the fuel deferral to be collected over a 2-year period rather than one . This year, the team executed on one of our largest annual capital programs to date. 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 that 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. 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 saved our customers money, over $80 million in 2022 in avoided fuel costs. Similarly, in Atlantic Canada, our investment in the Maritime Link saved Nova Scotia customers almost CAD 100 million in 2022 by replacing expensive carbon generation with clean hydro energy.
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. 2022 demonstrated 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 Hurricane Ian.
While Nova Scotia Power and its customers don't have benefit of the same focused government policies of Florida, Nova Scotia Power does continue to make significant investment in reliability, with CAD 180 million of investment in transmission and distribution in 2022, which is 51% more than 2015 investment levels. While we continue to work to make the system even more reliable every day, Nova Scotia Power is currently ranked number one in terms of the 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, 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 $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 a $180 million liquified natural gas storage facility to help ensure 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 customers' 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. 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 2005 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. 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 believed 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 grid, 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 engaged to ensure the needs of customers and stakeholders remain in focus.
Last quarter, we announced our 2023-2025 capital plan of $8 billion-$9 billion, driving expected rate-based growth of 7%-8% over the forecast period. Over 75% of our 3-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% at Tampa Electric and approximately 5% at Peoples Gas in 2022. Our capital deployment in Florida reflects this growth.
As the economies and populations in 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 CAD 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. A rate application of Barbados Light & Power progressed, 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 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. 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-based investment to serve the growing population of Florida and ensuring the system continues to operate safely and reliably. 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.
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 CAD 249 million and adjusted earnings per share of CAD 0.93. Our results this quarter included the recognition of a CAD 45 million Canadian after-tax settlement related to outstanding litigation, which represents CAD 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 CAD 204 million for the quarter, and adjusted earnings per share was CAD 0.76. For the year, excluding the impact of the litigation settlement, adjusted earnings were a record CAD 805 million and adjusted earnings per share was CAD 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 our 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 have 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 CAD 750 million of operating cash flow that will be collected through the regulatory recovery mechanisms available in Florida for this specific purpose. 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 recovering 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 FPSC in March, and if approved, we will begin collection on April 1. When you adjust for the impact of 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 which the business was able to capitalize on during the quarter.
It is noteworthy that Q4 built in an already strong year, resulting in the second-best year ever for Emera Energy's marketing and trading business. This year's results demonstrate the significant upside potential for Emera Energy that we often talk about. The strength of the US dollar increased adjusted earnings per share by $0.07 for the quarter. At our gas utilities, New Mexico Gas delivered a $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. Due to a combination of market conditions and weather in the region surrounding New Mexico Gas during December, these AMAs earned significantly more than they have historically.
As Scott mentioned, in December alone, the AMAs generated approximately $34 million of benefit, of which 70% will be returned to customers, and the remaining $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. 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 $20 million of the reserve to recognize in 2023.
Excluding the litigation settlement, corporate costs increased CAD 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 hedges 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. Finally, higher share count decreased quarterly adjusted EPS by CAD 0.03. For the year, adjusted earnings per share increased CAD 0.39 to CAD 3.20.
Excluding the impact of the legal settlement, adjusted earnings per share increased by CAD 0.22 or 8% year-over-year, driven by new base rates and favorable weather at Tampa Electric, higher contributions from our gas utilities and 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 underperformance 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.
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%-5% customer growth at Peoples Gas. Excluding the impact of the weaker Canadian dollar, our gas utilities delivered CAD 13 million or 8% growth in earnings year-over-year. Contributions from Emera Energy increased CAD 16 million in the year compared to an already strong 2021. The increase in corporate costs and decrease in contributions from Canadian Utilities were driven by factors consistent with those that impacted the quarter, as discussed a moment ago. Finally, higher share count decreased adjusted EPS by CAD 0.10 for the year. Throughout 2022, we've highlighted the continued material impact of fuel underrecoveries, 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. With our recent filing for the recovery of these fuel and storm costs at Tampa Electric, there is now a clear line of sight into when the impacts on operating cash flow will reverse. However, these short-term underrecoveries have also had a 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 a 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 underrecoveries.
Between 2021 and 2022, the total fuel underrecovery at Tampa Electric was $518 million, and the storm cost deferral is $130 million, or over CAD 860 million 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. 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 repaid. If the applications for the storm and fuel cost recoveries at Tampa Electric are approved as filed, we will collect approximately $100 million of storm costs and $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 thirty-first 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. 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 on our 2022 U.S. dollar cash flow. The impact to our debt balances is significant.
Between fuel and storm costs underrecovery 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. 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 to deliver both earnings and cash flow growth, providing value to shareholders and maintaining our investment-grade credit ratings. Thank you. 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. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the number one on your touch-tone phone. If you would like to withdraw your request, please press star followed by the number two. One moment, please, for your first question. Your first question comes from the line of Mark Jarvi from CIBC. Please go ahead, sir.
Thanks. Good morning, everyone. Maybe Greg, a question for you with the at-the-market program. Is the expectation you'll renew that in 2023? Just maybe will sort of the level of activity be comparable to what you did in 2022?
Yeah, Mark, at this point in time, yeah, we would expect to renew that. It's been a very cost-effective way to raise equity as we required, and it is part of our funding plan, as you know, going forward. We would continue to expect under, you know, normal circumstances to, you know, access that market for around CAD 250 million on average each year.
Okay. Scott, maybe 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? I guess also, you know, if you think about some of the challenges in getting Labrador and Link up and running, do those types of issues in terms of startup issues delay your enthusiasm for large transmission project investments going forward?
Yeah. Thanks, Mark. I mean, to start with your second question, no, they don't. I think, you know, the issues that Nalcor is having, with their Labrador Island Link asset really has nothing to do with Emera directly. You know, our confidence in our ability to design, build, operate, large-scale transmission assets, I think, you know, 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, look, 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.
Bill 212 puts some concern obviously about that at large scale for a new project. That's really the consideration in terms of where we're at now. We continue to believe that this is an important project for Nova Scotia, an important project for Nova Scotia Power customers. 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, you know, a path forward potentially with federal government support or, you know, updated discussions with the provincial government that you could see prudent recovery of a, of a larger investment?
At this point, Mark, I'd just say it's too soon to say. You know, we've certainly made our position clear as it relates to, you know, the effective restriction that Bill 212 has put on our ability to secure the investment and make the investment required. You know, really, it's up to government partners at this point to help create that path forward. 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. First question, I want to 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've mentioned that you're 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, you know, CAD 1.35 or even CAD 1.30 that you use in this assumption?
Maurice, we'll provide a little bit more color and detail around that next week. You know, 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 will comfortably allow us to get to at a minimum 11.5%. We're still working through some other items that will provide, we hope, some upside to get closer to the 12% in 2023.
Thanks. Maybe just a follow-up to these other items that you just mentioned. You know, 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%-13% offers you some cushion and balance sheet flexibility, particularly given the world that we live today. Just some thoughts on as to how you might approach where you ideally like the metric to be.
It's a fair question, Maurice. At no point should you interpret that we want to be at 12% on a sustainable basis, that, you know, we think the 12.1 is the right number. You know, 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. 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. That should, you know, give us kind of around 100 basis points plus cushion versus the 12% target.
Great. Thanks for that color. Maybe I could just finish off with Big Bend. Now that unit one 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?
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, 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. 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 that means it's sort of keeping coal around a bit longer than some stakeholders might like. That's an ongoing debate that we have within the company. At least for the foreseeable future, we see value in that flexibility, and we're gonna 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, and 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. Oh, go ahead, Scott, please.
Sure. Yeah, no, That's fine, Greg, if you wanna go.
As you probably can tell, Ben, we're not in the same room at the moment. 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. At this point, we're forecasting to have a fairly significant over-recovery of fuel costs. There'll be, we've proposed an adjustment to customer rates to turn that back to customers over the balance of this year. Over the April 1 to December 31 period.
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. 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. Really the most significant impact is the fuel cost recovery at Tampa Electric.
Okay. Got it.
Yeah. Ben, I just add that it's, you know, it's really helpful to our customers, right? 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. Reducing fuel prices obviously reduces rate pressure for customers and thus helps to ensure that we're not putting undue pressure on customers' bills.
Okay, great. Maybe going back to the balance sheet and you're exiting this year 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 getting to the 11.5% upload of that?
Yeah, I think, Ben, I mean, really no different than it always has is that, you know, from our view, first and foremost, is we're executing on our strategy. 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. We remain very confident in the path ahead for us.
You know, we're blessed with the diversification within our portfolio, and we always have, when we sort of consider our strategy and our portfolio every year, we're constantly thinking about how best we allocate capital. Obviously right now you're seeing that with a significant amount of capital being invested in Florida. You know, we've demonstrated in the past when it makes sense for our investors to think about recycling the capital or in the language we've used, optimizing our portfolio, then we're very prepared to do that.
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 growth and earnings and improvement in credit metrics as we do that.
Okay. Maybe just a final follow-up on that and asset sales. I know you went through a monetization program in the past. Some of it was valuation-driven and some are just more focused on your core areas. Would you ever, you know, if push comes on a shove, would you ever consider maybe monetizing pieces of the best parts of your portfolio? We've seen some of those examples in the U.S. utility land. I just wondering your thoughts on that?
Yeah. You know, it's a question that's been asked before, Ben, I presume by that you mean our assets in Florida. You know, that would not be a strategy that we'd be considering. We, you know, we consider those businesses the driver of our growth and future. You know, that would not be something that we're currently in focus. Yes, I do know that's something that, you know, some peer utilities have done effectively. That's, you know, it'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 Scotiabank. Please go ahead.
Morning, everyone. Just two cleanup questions for me. First one's 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 in 2023 and 2024 out of Florida.
Correct.
All right. Thank you. Then just taking a look at Peoples Gas, you know, the outlook for flat earnings year-over-year, can you just walk us through some of the dynamics there? You are seeing, you know, very strong economic activity and customer growth in the region, is inflation as well as kind of this, the sheer magnitude of capital that you put to work there, kind of the key burdens there?
Yeah. 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 have expected, and putting obviously pressure as a result of that 'cause incremental capital comes with higher depreciation, higher financing costs, putting 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 the board. The primary driver is just the timing of the deployment of capital to 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 context would be appreciated.
Thanks, Linda. It's Greg. I'll start. You know, I think the settlement was a reasonable balance for the company and our customers. As a result of that, we think there's a you know, 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, which the team is looking at and trying to identify opportunities. At this point in time, we'd expect to be somewhat below the low end of the band. 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.
The team is working at trying to identify a path to. We're certainly committed to trying to get to the low end of the band in 2024 as well.
Thank you. As a follow-up, just bigger picture, and maybe you'll be addressing this 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. You know, 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? 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.
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?
Yeah, Linda. You know, we'll take that away. Obviously, that's a question with a longer answer than would be workable here. We can work to try and give a sense of that. You're right? We're seeing, you know, sort of the supply chain and real estate prices and inflationary pressures globally is, 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. We can, you know, 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 Glowacki from Bank of America. Please go ahead.
Hi. Good morning, 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, you got a constructive outcome there. Perhaps how does that then manifest itself in your efforts to recover 22 storm costs?
Yeah. I know, Peter Gregg's on the line. Peter, do you wanna respond at least to the first part of that question?
Sure. Thanks, Dariusz. Yeah, you know, bit of a tumultuous year, but I think the URB affirmation of the settlement was a good positive step forward. I think reflects meaningful ongoing discussions with the key stakeholders on this file. I think, you know, really important that either Scott or Greg mentioned earlier the number of customer representatives that signed on to that settlement was significant and important. I think, you know, 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. It's something certainly I and the team are committed to, and are actively engaging in at this point.
Excellent. Thank you very much for that color. One more if I can. This is, again, another relatively high level one. Are there any efforts or are you maybe 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 outsized impacts in 2022. 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?
Yeah, Dariusz, it's Greg. I think certainly with the initiation of a foreign exchange hedging program on our adjusted earnings, that will certainly help. You know, we're progressing our way through that and have a lot more hedged. I think that'll be 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 contributing to that. Kind of similarly, we do actually hedge our long-term compensation. 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.
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 it out on a quarter-to-quarter basis.
Okay. Thank you very much. Appreciate those responses and look forward to next week.
Thanks, Dariusz.
Thank you. Your next question comes from the line of Andrew Kuske from Credit Suisse. Please go ahead, sir.
Thanks. Good morning. I guess we'll have ample time to talk about Florida next week, while we're there, but I'm gonna focus my questions on Nova Scotia. I guess the first one really revolves around the province's aspirations for offshore wind. You know, how do you think about that from an NSPI standpoint? 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?
Peter?
Scott, do you want me to take that?
Yep. Sorry. May not have come in yet.
Yep.
Peter, if you can, 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. You know, we often talk about the Atlantic Loop, but the project we're working on is called the Eastern Clean Energy Initiative, which involves the Atlantic Loop, but it also involves more development of onshore wind. The province did an RFP to bring some more proponents in last year. 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. 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, you know, how do you think about that in relation to the core asset base of NSPI?
The way I think about that is I think, you know, there's still a heavy reliance on home heating oil in Nova Scotia. 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 pumps. It's been very successful. We've like to see that. Obviously, there's a load 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 BlockEnergy
I'm sure we'll be getting the full update next week. Just in light of the volatility in fuel costs, wondering if you're seeing any pickup in customer demand for the BlockEnergy platform, either in Florida or perhaps, you know, other jurisdictions where you might be looking to deploy the technology.
Yeah. Patrick, you know, I mean, it's still early for us with Block Energy as we've, you know, effectively got pilot now in Florida and now working on a second pilot outside of Florida. You know, I think you're right. I think, you know, the volatility of fuel prices and the impact that that has on energy prices for customers is an important selling feature of the Block Energy solution. So too is reliability.
You know, 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 BlockEnergy continued to have energy throughout that experience. You know, the combination of those two things continues to have us feeling excited and confident as to path forward for BlockEnergy. There's certainly building interest from customers of all kinds in this microgrid solution.
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. I guess just, you know, from a larger scale perspective, just given, you know, 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, you know, the long lead times for some of these opportunities, curious if your team is looking to bring, you know, any of these larger scale energy storage type assets into the portfolio by, you know, say, the latter part of the decade?
Yeah. You're exactly right in that, you know, the energy transition is. This is in part going back to a question of Linda's as well. You know, energy transition obviously has its challenges when a lot of the early moves in that transition is the build-out of intermittent renewables. You know, most systems can take, you know, a good portion of intermittent renewables. Once you get to a certain percentage, sort of 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 that causing challenges with system reliability. Therefore, storage becomes important. 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. You're right, it's gonna be, you know, storage of all forms. And that, you know, 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. 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 JPMorgan. 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 2021 is a good normalized base there, meaning that year-over-year impact was all upside versus, I guess, normalized expectations. Just under the current market dynamics, any continuation of that upside into 1Q?
Yeah. Hi, Rich. It's Greg.
Ryan-
Oh, sorry. Yeah.
Yeah.
With Ryan-
Go ahead, Greg, and then Ryan can add on.
Yeah, I think, you know, 2021 is probably more representative, Rich, of what we would expect on a normalized basis. Obviously, we had some outperformance in 2022. You know, I'm not so sure 2023 will be, you know, back to 2021 levels, but I don't think it'll be at 2022 levels either. We're still seeing some market dynamics which will create some upside potential, but not nearly to the extent that we saw in 2022.
Ryan, just wanna add a little more color from your perspective.
Yeah, I would agree with what Greg just said. I don't think there's anything further that I would add.
Great. That's all for 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, Lara, 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.