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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 day, and thank you for standing by. Welcome to the Emera Q1 2022 Analyst Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]
I would now like to hand the conference over to your speaker today, Dave Bezanson, Vice President of Investor Relations. Please go ahead.
Thank you, Jerome, and thank you all for joining us this morning at Emera's First Quarter 2022 Conference Call and Live Webcast.
Emera's first quarter earnings release was distributed this morning via Newswire. And the financial statements, management's discussion and analysis and the presentation being referenced on this call are available on our website at emera.com. Joining me for this morning's call are Scott Balfour, Emera's President and Chief Executive Officer; Greg Blunden, Emera's Chief Financial Officer; and other members of Emera's management team.
Before we begin, I will take a moment to advise you that this morning's discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide. Today's discussion and presentation will also include references to non-GAAP financial measures. You should refer to the appendix for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure.
Now I will turn things over to Scott.
Thank you, Dave, and good morning, everyone. Emera reported solid first quarter results this morning, with $0.92 of adjusted earnings per share and a 42% increase in operating cash flow compared to the first quarter of 2021. The $0.04 reduction in year-over-year adjusted earnings per share this year -- this quarter was largely driven by decreased contributions from Emera Energy, which, in 2021, performed particularly well as a result of market conditions created by Winter Storm Uri in 2021.
Our regulated utilities delivered an 8% increase in adjusted earnings per share this quarter, highlighting the strength of our regulated portfolio and the consistent, reliable earnings growth that we can expect from these businesses. As an example of that growth, our team in Florida recently achieved another significant milestone in our solar program as the first tranche of Solar Wave 2, 235 megawatts of new solar generation was placed into service.
I'm proud to say our total solar investment to date of over 800 megawatts positions Tampa Electric with the highest proportion of solar generation per customer of any utility in the state. These investments have obviously reduced the carbon intensity of the generation fleet at Tampa Electric, but they've also driven value for our customers through fuel cost savings, something that is particularly beneficial for customers in the current market conditions.
And while not the only factor, rising fuel costs are a significant contributor to the current high inflation that we're experiencing and working hard to manage on behalf of our customers. The fuel-to-asset strategy we've been executing on for many years, where we've been investing to reduce the carbon intensity of the energy we deliver to our customers, has also helped to reduce the fuel and operating cost profile of the business. These are helpful contributors to reducing, albeit far from eliminating, the inflationary impacts to the business and thus for our customers.
We continue to execute well on our capital program, with 9% higher capital investment in the first quarter compared to last year. We're on track to invest close to $3 billion in 2022, and we continue to expect to invest between $8.4 billion and $9.4 billion through the end of 2024, with over 60% of that capital plan focused on cleaner and more reliable energy. Beyond 2024, we believe that the ongoing need for cleaner generation, infrastructure renewal and grid modernization will continue to provide robust investment opportunity and growth for the business.
In that context, we talked a lot about our capital plans focus on decarbonizing our generation fleet, but we're also transforming and modernizing our grid. Investments in distributed generation, smart meters, cybersecurity and data analytics platforms are a vital part of the energy transition. They support the underlying framework that enables the build-out of increased renewable generation, and they make the grid more reliable and more responsive to evolving customer demands.
The energy transition underway is complex and costly. In the current environment, where costs are rising in virtually all areas, is adding to the challenge. We continue to monitor supply chains and the impact of inflation to proactively mitigate any risks around our capital plan and our business more broadly. At this time, we do not have any material changes to our capital plan in response to these challenges, but we continue to watch this closely.
As we continue to execute on a capital plan that has a clear focus on reducing emissions and our reliance on coal, we're proud of our track record and the very substantial progress we've made. However, it's important to recognize that the path to further reducing and eliminating carbon from the electric and energy sector is getting even more challenging, notwithstanding the abundance of opportunity for continued deployment of renewables, like wind and solar, and the exciting developments in battery storage and other technologies.
The task ahead is made more difficult by increasing energy demand, more severe weather patterns that are challenging system reliability, increasing levels of intermittent renewable sources that require backup generation or storage solutions, which are themselves increasingly challenging and expensive to secure, and of course, very ambitious government energy and climate policies.
I believe that our strategy is continuing to serve all of our stakeholders well. We remain committed to an energy transition that takes a balanced approach, making real progress, while ensuring that reliability is not compromised and the costs remain as manageable as possible for customers. And our approach positions us well to continue to deliver value and growth for customers and our shareholders.
Since 2005, we've reduced the use of coal by 65%, and we currently have more than 1,400 megawatts of installed renewable generation capacity across the business. That's in addition to the renewable energy that can now be imported into Nova Scotia with benefit of the Maritime Link.
Last year, we announced our climate commitment, which includes clear decarbonization goals and our vision to achieve net-zero CO2 emissions by 2050. We continue to be transparent in our characterization of a net-zero carbon future as a vision and not a concrete goal because the path to get there is not clear, certainly not in a way that does not sacrifice reliability or place an extraordinary cost burden on customers.
Our major projects, like the Maritime Link, Big Bend modernization, the solar program in Florida and the Eastern Clean Energy initiative at Nova Scotia Power, are critical pieces of our decarbonization strategy. However, to meet the challenges ahead, we'll need to do more. And we know that innovation and emerging technologies will play an important role in shaping a viable path to achieving ambitious climate targets in both the U.S. and Canada.
A critical factor to achieving net zero will be accelerating time lines and ensuring that today's emerging technologies can be commercially viable and ready to support the transition and help to not only provide cleaner energy, but also the reliability and energy availability that customers need. While we speak often of our big project initiatives, I want to take a moment to talk about some of the smaller projects our teams are working on across the business that highlight our innovative thinking and the attention we're paying to emerging technologies.
Earlier this year, the team in Tampa completed construction of a floating solar array. It's the largest floating array in Florida and the first of its kind in the Tampa Bay Area. Half of the solar panels used in the project are double-sided, which can produce as much as 30% more energy than traditional panels. Exploring this type of alternative solution helps us expand the solar potential for Tampa Electric, where land availability and cost is a meaningful factor in that region.
We continue to believe that our gas utilities are an important part of the transition to a greener energy future. One example, the team at Peoples Gas, in partnership with a local dairy, is building a renewable natural gas facility. Construction is underway. And once the facility is in service, RNG will be injected into Florida's pipeline systems and used as a reliable and cost-effective energy source.
Another example, at New Mexico Gas, the team launched a pilot project this year to test the blending of hydrogen with natural gas that can then be used in typical household appliances. The project is in early stages but as part of our commitment and strategy to reduce the carbon and emission intensity of the energy we delivered to our customers.
The team is also exploring the value of a gas storage project to help manage the risk of supply constraints as well as the risk of volatile gas prices and expect to file an application for this project with the regulator later this year. While grid scale renewable natural gas and hydrogen blending projects might not be commercially and economically feasible today, it's essential that we continue to explore and support emerging technologies like this by making small investments now so we can be ready to make the best assessment for our customers when these technologies become commercially viable.
Our BlockEnergy initiative is another clear example of our commitment to innovation and our work to capitalize on customer trends. Recognizing that it would have a meaningful impact on our sector, we established Emera Technologies over 5 years ago to explore the emerging trend of distributed generation.
By 2019, a full-scale demonstration project was developed and put into service at the Kirkland Air Force Base with resounding success. We followed this with our first residential project for 37 homes and a new subdivision in the Tampa Bay area, which, importantly, the Florida's Public Service Commission approved as a rate base investment for Tampa Electric.
Utilities are expert operators, which makes BlockEnergy a win-win for customers and utilities alike. Customers benefit from more renewable energy with a step change in reliability, but without the upfront costs or ongoing maintenance of making the investments themselves in rooftop solar battery storage or backup generation. And the technology allows utilities to do what they do best, invest in rate base with economies of scale and optimizing the flow and sharing of energy sources to reduce the overall cost for all customers.
We know emerging technologies like these and many others will play an important role in achieving a net-zero carbon future, and we're committed to continuing to explore and invest in these ideas to drive value for our customers and growth for our shareholders. More examples, along with progress on our safety journey, climate transition plan and other ESG commitments, will be included in our upcoming sustainability report that will be released next month.
Before I pass the call over to Greg, I wanted to provide a quick update on our regulatory calendar. Our rate cases in Nova Scotia, New Mexico and Barbados are ongoing, and we expect to have resolution on all 3 by the end of the year. And while we don't have a substantial update on the Atlantic Loop project, we continue to be encouraged by the ongoing conversations and hope to provide more clarity on the project later this year.
Greg?
Thank you, Scott, and thank you all for joining us this morning. This morning, we reported first quarter adjusted earnings of $242 million and adjusted earnings per share of $0.92 compared to $243 million and $0.96 in 2021.
As Scott highlighted, our regulated portfolio delivered strong first quarter results. Contributions from our regulated utilities increased $30 million over last year or $0.11 of adjusted EPS. This was offset by lower contributions from Emera Energy, whose 2021 results benefit from event-driven market volatility following Winter Storm Uri.
Emera Energy's earnings will vary both quarter-to-quarter and year-to-year depending on market conditions, which causes variability on our consolidated results. While our financial results are not as predictable as those from our regulated portfolio, their low-risk operations provide us with potential earnings and cash flow upside and are always positive on an annual basis.
Operating cash flow before changes in working capital increased by $142 million or 42% over Q1 of 2021. The increase was primarily due to the 2021 gas cost deferral at New Mexico Gas and Winter Storm Uri, partially offset by higher fuel under recoveries at Tampa Electric as a result of higher gas prices. And although fuel under recoveries can cause temporary cash flow differences, we have regulatory mechanisms across our portfolio to recover prudently incurred fuel costs from customers on a timely basis.
Earlier this year, we filed a USD 169 million midyear course fuel correction at Tampa Electric, which was approved during the quarter. Recovery of these costs began on April 1 and will be recovered over the balance of the year. This strong cash flow was expected and underpins our confidence that we are on track to achieve sustainable credit metrics that support our investment-grade credit ratings.
Now I'd like to turn our attention to the details of the quarterly results. Tampa Electric delivered strong results with growth of $29 million in earnings or 35% over Q1 2021. First quarter results reflect the impact of new rates that went into effect on January 1 of this year, which also includes the capital cost recovery for early retired assets through our innovative clean energy transition mechanism. Tampa's results also benefit from more favorable weather and the strong economic conditions in Florida that continue to drive meaningful customer growth of over 2%.
Contributions from our Canadian utilities increased $10 million compared to Q1 2021. If you recall, we experienced an incredibly mild winter here in Nova Scotia in the first quarter of last year. And this year, our results benefited from colder weather, which drove higher sales volume. However, we also saw higher OM&G due to storm costs as Nova Scotia experienced an unusually high number of winter storms during the quarter.
Emera Energy delivered a solid first quarter with $27 million of adjusted earnings, driven largely by the marketing and trading business. And although this represents a decrease of $16 million compared to Q1 2021, our prior year results benefited from Winter Storm Uri, which created the event-driven volatility the business was able to capitalize on. Our corporate costs increased $15 million this quarter, primarily driven by the timing of share-based compensation expense and related hedges. The quarter-over-quarter increase is partially due to a hedge gain recognized in Q1 of last year.
Volatility in our share-based compensation costs and the related hedges are driven by changes in our 50-day average share price leading into the quarter relative to our share price at quarter end. Contributions from our Caribbean utilities decreased by $6 million, primarily due to the business interruption insurance proceeds that were recognized in Q1 2021 at Grand Bahama Power Company.
Earnings from our Gas & Infrastructure segment decreased by $3 million in the first quarter of 2022. Higher OM&G driven largely by increased labor costs at New Mexico Gas offset higher base revenues from strong customer growth and the recognition of a USD 5 million amortization reversal at Peoples Gas. And finally, higher share count decreased adjusted earnings per share by $0.03 in the quarter.
Over 95% of our annual adjusted earnings comes from our portfolio of regulated utilities. Since 2017, the first full year with TECO in our portfolio, our regulated utilities have consistently delivered high-quality, predictable earnings and cash flow growth. Between 2017 and 2021, our adjusted earnings per share has grown by over 3%, and that's before considering the impact of our asset sale program that deleveraged our business and strengthened our balance sheet. When you remove the contributions from these assets that we sold, we delivered a 6.1% annualized growth in adjusted earnings per share.
We have a clear record of delivering competitive earnings per share growth, which supports consistent, reliable dividend increases. And over the last 5 years, this means we've delivered a 10.8% annualized total return for our shareholders, higher than both our Canadian peer group and the broader market. As we continue to execute our strategy, investing in rate base to decarbonize and strengthen the grid, while working constructively with our regulators and customer groups to ensure the energy we deliver is as affordable as possible, we have a clear line of sight to the continued growth of our business, earnings, cash flows and dividends.
Thank you, Greg. This concludes the presentation. We would now like to open the call for questions from analysts.
[Operator Instructions] Your first question comes from the line of Linda Ezergailis with TD Securities.
I'm wondering if you could just help us understand if the shifting long-term outlook of the importance of energy security in North America and the Caribbean affect your approach to operating assets and capital allocation. Might there be an accelerating energy transition in any of your jurisdictions?
Might there be a case for potentially prioritizing whatever remaining fuel requirements you have? Do you have those contracted or more hedged long term? And is this influencing the nature of your conversations with Atlantic Loop potentially?
Linda, this is Scott. So thanks for the question. It's a complex and an important question. And look, largely, the pace of change of the energy transition is going to be driven by economics and by government policy.
And government policy will set time lines that utilities like Nova Scotia Power and Tampa Electric and others will need to meet and follow, and that can certainly drive time lines. And otherwise, it will be driven by economics to ensure that we're creating a path that's most economic for customers, making sure that we're delivering the cheapest electron for customers or gas molecule for customers, while still being compliant with regulations and legislation that gets set by customers.
So certainly, as inflationary impacts and fuel impacts to the extent that changing price of fuel is a long-term thing. And obviously, that's an open question, and we can all have a view. The economics can shift around between the cheapest way to generate those electrons for our customers, while still being -- and meeting the regulatory and legislative policies that are set.
So all to say, this is an ever-changing environment. The pace of change, I think, is actually quite quick already. Our responsibility is to make sure that we continue to do that in a way that is most cost-effective for customers, while maintaining reliability and availability of energy that, obviously, all of us and all of our customers depend on.
And as it relates to the Atlantic Loop, what sort of things need to happen before you can provide an update for us later on this year in terms of milestones or decisions or policy or anything?
Yes. I mean, as we said before, Linda, this is in concept. Obviously, this is a simple and important project where we're looking to optimize the energy needs and energy sources in Atlantic Canada, amongst the provinces of Quebec, Newfoundland, Labrador, Nova Scotia and Brunswick. But it's complicated because there's a lot of parties involved.
And the federal government's engagement in this is important. We're encouraged -- continue to be encouraged by the engagement by all of the stakeholders in this process. But an important component of it is the participation levels and the funding participation by those parties, particularly including the federal government, where we've been clear about the fact that for Nova Scotians, we need support from the federal government in order to make this transition in this project affordable.
And so it's really just sorting out all of those dynamics. We continue to be encouraged by the progress and continue to work towards a time line of more clarity by year-end because, of course, we need that in order to be able to have a hope to meet the 2030 time line, to be able to have a project like that in service and delivering clean energy to Nova Scotia, to be able to retire the coal plants on that time line.
And just as another follow-up in terms of capital allocation and energy transitions and energy security. Recognizing that there's been challenges on a number of fronts, getting an East Coast LNG project -- export project off the ground on a number of fronts, including complexity, under what circumstances, if any, would Emera be interested in getting involved in any sort of project like that?
Yes. We're certainly not looking at LNG export capacity, Linda. We certainly think about, as I mentioned earlier, gas storage. And LNG is obviously a focal point within that, and that's certainly in focus for us right now in both of our gas utilities, thinking about gas storage, also important consideration for Tampa Electric. But at this point, we're not looking at the market of thinking about LNG for export purposes. We're looking at trying to create value for our customers.
And your next question comes from the line of Rob Hope with Scotiabank.
A follow-up question on the Atlantic Loop. Just -- I want to know, has the engagement of the federal government, in your eyes, changed over the last couple of months? It was interesting to see the Atlantic Loop specifically called out in the last budget or updates.
Yes. Thanks, Rob. And look, yes, I guess, in a way, I think you're right. We're seeing the Atlantic Loop project being referenced in many places. But frankly, that's not new. We've seen that from the federal government for a number of quarters now.
So I think we continue to, as I say, be encouraged by their engagement and interest. And I think they agree with us that this is an important project for the region. I think they agree it's an important project for Canada, but there's still a lot of details to work out. And they, and we and others are working our way through all of that complexity to find a way to help to make this happen.
All right. That's helpful. And then just switching gears, a little bit more relating to the numbers. We've seen fuel prices increase, however, you have got some recent wins on fuel cost recoveries. How are you thinking about where fuel prices are currently versus recoveries as well as kind of the target of $2 billion of cash flow for 2022?
Yes, Rob, it's Greg. From where we sit right now, everything that we've experienced from any kind of under recovery either from the tail end of last year, Winter Storm Uri, or even the early part of this year, we're expecting to recover in the current year, and that's largely because of the settlement in New Mexico.
Obviously, there's some of that gas cost in New Mexico will get recovered in '23, but also the midyear course correction at Tampa Electric. If we see gas costs remain elevated at the levels they are over the balance of the year, we'll have to make a determination of whether we file for a second midyear course correction at Tampa Electric.
We haven't made or concluded on that yet, again, because that would be based on a forecast as we see today. And so that would be the one area that might have some potential variability between this year and next year. But outside of that, and I should mention as well, less of an issue at Nova Scotia Power because they do a lot of hedging on their fuel costs. So really, it's gas cost at Tampa Electric. And we do have a regulatory mechanism to recover over the balance of the year, but it would not surprise me if it stayed at these levels and that some of that might leak into next year.
And your next question comes from the line of Maurice Choy with RBC Capital Markets.
My first question is on the capital plan. Thanks for confirming the plan, and that there is no material change in relation to inflation and supply chain matters. But you made it clear that this is obviously an assessment for now. And so is it a case that a more wholesome assessment will be made in the next iteration of the plan? Or is it a case that 2025 and beyond projects more impact and less so for the next 3 years?
Yes, I think that's right, Maurice. When we rolled out our capital program, we obviously put a lot of thought into that in the fall and, in particular, the projects under development and other things we're seeing. What probably would be a little bit different this year is the projects, not so much for 2023, obviously, but for 2024, 2025, as we do more scoping of those projects and cost estimates.
To the extent that inflation weighs in on some of that, we'll incorporate that in November. Nothing -- at this point, nothing has changed in terms of our plans, our execution around it, but we are seeing cost pressures on some of the projects a couple of years out.
Your next question comes from the line of Mark Jarvi with CIBC.
Obviously, you've acknowledged the rising gas and electricity prices. Are you seeing that impact at all customer behavior and usage?
No. Maybe a little bit, Mark, on our gas utility in New Mexico. It seems to be that the usage per customer seems to be off slightly. Whether that's tied to the price of gas or not, I'm not so sure. We certainly have not seen it at Peoples Gas at all, although we have seen a little bit softer usage from our commercial customers just because restaurants are now operating at full capacity because of staffing issues. Hotels aren't necessarily washing sheets and towels at the same frequency that they were before.
I'd say the opposite is actually happening at the 2 electric utilities, which is probably more meaningful. Right now, electricity, relative to other sources of energy, is probably the most cost-competitive out there. And so whether it's electric vehicles, heat pumps here, people working from home, we're actually seeing a little bit of positive growth from a load per customer perspective.
So all in all, probably balanced, may be slightly favorable because of the electric utility exposure.
And then is there anything to be done in terms of early refinancing? I think there's some notes maturing next year just with the rising rates, so sort of your updated thoughts on managing maturities?
Yes, it's a good question, Mark. I mean, obviously, we, like I think most, if not all of our peers have been taking advantage of the yield curve over the last number of years and going maybe a little bit further out on a tenor basis than we traditionally have. Over 85% of our debt is fixed debt with maturities beyond 2026. We don't have a whole lot of necessary required financings over the next couple of years. It's pretty modest. So at this point in time, we're not planning to do anything outside of the normal course of business.
Okay. And then last question for me. Just with the veto of the sort of net metering-related bill in quarter, your sort of initial thoughts on that, any implications, whether it's for Tampa Electric or also just for BlockEnergy, if at all?
Yes. I mean, I think, look, our view of net metering really hasn't changed, and it's about trying to get great design in a place that's fair to all customers. So our view on that hasn't changed. Obviously, we respect the decisions that have been made in Florida and in Nova Scotia both.
But we'll continue to work within the tariff design that exists currently. I think, fundamentally, these are issues that will surface again. But in the meantime, we continue to deliver energy to our customers and support the needs of customers, whether they have solar panels on the roof or not.
And you don't foresee any issues in the near term in terms of fixed charge recovery or some of your infrastructure cost recovery if we do see an uptick in residential solar?
No.
No.
And your next question comes from the line of David Peters with Wolfe Research.
I was just curious as it relates to this Department of Commerce investigation here in the U.S. My understanding is that Solar Wave 2 shouldn't be impacted at all just because of who you're getting your panels from. But I was wondering, for Wave 3, have you contracted panels yet for those projects? And do you see any potential impact, I guess, to '23 as a result of the investigation?
So no, we don't expect any impact to the completion of Wave 2, which includes the solar generation we expect to put in service through the balance of this year and next. But yes, as it relates to the expectation that, at the end of Solar Wave 2, that won't be the last solar generation that makes sense to put into service in Florida. It's quite reasonable to expect that there will be price and supply chain constraints as a result of what's been going on.
I suspect First Solar has become a very popular supplier as a result of what's going on. We've been fortunate to have them as a key supplier partner since the beginning of our solar initiative, and that's obviously served us well. But no, we are not contracted for a panel supply beyond the completion of Solar Wave 2, which is, still, what 350-ish megawatts of solar beyond that, that we've already got in service.
Okay. And then just one other one, maybe a question for Greg. I know you guys have used a fair amount of preferred equity in the past as part of your financing plan. So I was first just hoping you can maybe give us a sense of what you're seeing in that market today in terms of pricing and just overall openness of the market. And then if you could just remind us where you stand with respect to financing needs this year and next, just with respect to equity or hybrid instruments.
Yes, David. On the preferred market, we've always said there's a window of opportunity. Sometimes the markets open, sometimes it's not. It feels like it's close right now. It doesn't mean you couldn't do a transaction if you wanted to, but I think the terms would be much more favorable to the investor as opposed to the issuer. So we're not planning to do anything in the short term, but we're certainly capable and ready to do something if we find that market demand and pricing is attractive in the second half of the year.
From a common equity perspective, it's a really normal course business for us. We're really happy with the execution of our aftermarket equity program and raising roughly around probably CAD 60 million a quarter, and we'll continue to do so. And similarly happy with our DRIP, with raises around $50 million to $60 million a quarter as well. So we'll just continue on that path. We're not making any changes to that at all.
And from a debt perspective, really, we don't have anything that needs to be done. We'll likely be going to the market later this year at Tampa Electric, just regular course business with a bond issuance to support the rate base growth there, but nothing from a holding company perspective.
Okay. Great. And then last one, just on the Nova Scotia rate case. Can you just maybe give an update on where things stand there? And expectations in the case, specifically on the ROE sharing and stepping up the equity thickness that you guys requested? And then just how the fuel request sort of squares with what you're seeing today in terms of pricing?
David, it's Peter Gregg from NSP. First part of that, so we're on track to put the plan for our general reapplication filing. So we've just completed the round of information requests, where we responded to intervener's information requests. And we're on track for the hearing to start in early September, and we're just -- preparations for that are underway.
Sorry, can you repeat the second part of your question?
I was just wondering -- I know there was a few items you guys requested in there, just the higher ROE sharing, stepping up of equity thickness. And just -- I know the fuel component, kind of how that squares with what you're seeing today in the market given how things have changed so fast?
We continue to proceed with the equity thickness request, and that will be subject to the hearing. I'd say, certainly, everyone has been seeing increase in fuel prices over the last several months, for obvious reasons. And so we're taking a look -- a hard look at that in terms of what updates might be required by [ GRA ] process.
Your next question comes from the line of Matthew Weekes with iA Capital Markets.
My questions have actually all been answered at this point. So I'll just turn it back.
[Operator Instructions] Your next question comes from the line of David Quezada with Raymond James.
Just a quick one for me. I'm just curious, as it relates to the longer-term generation mix at Tampa Electric, I'm curious what you think the ultimate penetration of solar could be there? And under the assumption that you move forward with additional waves of solar, what kind of complementary investments might be needed to facilitate that?
Archie, do you want to address that?
Sure. I can take that. Good morning, David. good morning, everyone. So David, I think that, a couple of years ago, when we first embarked on this decarbonization journey in an earnest way with the initial 600-megawatt investment in solar, we had commissioned a study at that time for the size of our system to do kind of perform an assessment of how far could we go before we might start to have some issues.
And we were able to determine that we could get up around 1,200, 1,400 megawatts of solar, which represents about 21% of our capacity and not have any issues. To get beyond that, it requires some investment in battery storage or storage of some form, which is why in our current 3-year capital plan, we've got 280 megawatts of storage in there.
And so as we invest in more solar, that paves the way to -- or sorry, as we invest in more storage, that paves the way to continue to invest in more renewable energy. So -- we certainly have designs ongoing beyond the 21% capacity that we're currently forecasting to be at by the end of '23.
Excellent. Appreciate that color. And maybe just a quick follow-up to that. And as it relates to affordability and the high fuel cost environment today, does that high fuel cost environment make it perhaps more palatable from a regulator's perspective to try to move forward with additional solar investments? Or does that, in a different way, hurt affordability and make it harder to make a case for the large capital items?
So yes, so I think I understand your question, David. So really, what the teams do, whatever source of new generation or transition in generation is really look at the math and determine what's in the best interest of customers from a financial perspective as well as making sure, of course, that the energy availability and capacity requirements are there.
And so yes, the math is a little different now. But it's yes, we're seeing the cost of everything go up, including, obviously, the cost, as we chatted about before, of solar panels, of land, of materials, of construction costs, but so, too, the cost of fuel. As to whether that's fundamentally shifted the lens between looking at early retirements of thermal generation and accelerated investments in renewables, frankly, it's a little too soon to tell.
But in the meantime, obviously, using Tampa Electric as an example, there have been significant investments in renewable generation, like solar, on the basis that it has been cost-effective for customers. Similarly, the early retirement of one unit of Big Bend and the conversion of another to high-efficiency natural gas through Big Bend modernization. And really, the same exercise goes on at Nova Scotia Power as the team there looks to how to best achieve the legislative requirements of 2030 in terms of renewable generation and finding the most economic path for customers to be able to do that.
And that's one of the reasons why we see the Atlantic Loop project as being important. But also, some of the initiatives that the team and Nova Scotia Power is taking in relation to battery storage and additional wind resources and transmission upgrades, all of them with a view on the economics relative to the alternatives and making sure that we're always choosing the path that's most economic for customers.
Your next question comes from the line of Patrick Kenny with National Bank.
Just wanted to delve into the gas storage strategy a little bit more. And I guess, given the portfolio is over 95% regulated today, curious what the appetite for incorporating unregulated gas storage assets might be given the backwardation in the gas market. It would appear that there could be some assets shaking loose over the coming months. So just maybe your thoughts on, looking at storage assets that may not be physically connected to your utilities, but might still be able to help you manage fuel costs for customers.
Yes. Thanks for the question, Patrick. So at this point, I'd say, across the business, storage of whatever kinds right now, frankly, but certainly gas, gas LNG, we're looking exclusively within regulation in support of the needs of our customers. And that's doing Mexico Gas, Peoples Gas and Tampa Electric. All of those, at this point in time, not looking at gas storage in Nova Scotia, but more focused on a path to renewables and hydro report.
Got it. And then maybe just on the renewable natural gas front, in light of inflationary pressures, are you seeing any change in the pace of development of potential projects that could be blended into the system over time?
No, I don't think so. Helen will correct me if she's got a different view. No, I don't think it's changing a few around the pace at this point, but it's still -- this is a young industry. And we're excited to have a couple of projects on the go in Florida and excited about advancing them and bringing them into service. But I'm not, myself, aware that it's accelerating or the opposite impact as it relates to any other potential developments in the state.
Helen, anything you'd say different?
No, that's exactly right, Scott. I'd say, all we're experiencing is what everybody is across the supply chain, some issues here and there with parts and supplies and that sort of thing, but nothing that's having a material impact.
And your next question comes from the line of Richard Sunderland with JPMorgan.
I just wanted to briefly follow up on the gas storage question. Can you provide more details around the New Mexico evaluation, thinking really the timing and magnitude of the capital opportunity?
Yes. Ryan, would you address that?
Yes, I'm happy to address that, Scott. I think as everybody knows, we -- last year, when we had approval of our gas cost from Winter Storm Uri, the commission asked us to take kind of a deep dive into various gas storage options for New Mexico Gas Company to own and control here that would work to reduce the impact of gas spikes or just supply in general. So we actually filed that information filing with the commission just recently in the last 30 days. And so that's on file. It's more of an information filing.
But in that filing, we did say that we think the best option for us is LNG. So we will be we will be filing later this year a certificate of convenience and necessity and requesting that the commission here approve that. In terms of capital spending, we're still working through the pre-FEED study and all of that, but we would anticipate that it would be in excess of $100 million of capital that would be spent on the LNG facility.
But again, we're still working through the details, and we'll have a more -- much more firm number later this year when we file for that. So I hope that answers your question.
[Operator Instructions] We don't have any further questions at this time. I'll hand the call back to Dave Bezanson.
Thank you very much, and thank you for your interest in Emera. That now concludes our call. Have a great day.
Thank you, and that concludes today's conference. Thank you all for joining. You may now disconnect.