NextEra Energy, Inc. (NYSE:NEE) Q3 2023 Earnings Call Transcript

NextEra Energy, Inc. (NYSE:NEE) Q3 2023 Earnings Call Transcript October 24, 2023

NextEra Energy, Inc. beats earnings expectations. Reported EPS is $0.94, expectations were $0.88.

Operator: Good morning, and welcome to the NextEra Energy and NextEra Energy Partners, LP Third Quarter 2023 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Kristin Rose, Director of Investor Relations. Please go ahead.

Kristin Rose: Thank you, Vaish [ph]. Good morning, everyone, and thank you for joining our third quarter 2023 combined financial results conference call for NextEra Energy and NextEra Energy Partners. With me this morning are John Ketchum, Chairman, President and Chief Executive Officer of NextEra Energy; Kirk Crews, Executive Vice President and Chief Financial Officer of NextEra Energy; Rebecca Kujawa, President and Chief Executive Officer of NextEra Energy Resources; and Mark Hickson, Executive Vice President of NextEra Energy; All of whom are also officers of NextEra Energy Partners as well as Armando Pimentel, President and Chief Executive Officer of Florida Power & Light Company. Kirk will provide an overview of our results and our executive team will then be available to answer your questions.

A rooftop view of a busy city skyline with solar energy panels and wind turbines illuminating the skyline. Editorial photo for a financial news article. 8k. –ar 16:9

We will be making forward-looking statements during this call based on current expectations and assumptions, which are subject to risks and uncertainties. Actual results could differ materially from our forward-looking statements, if any of our key assumptions are incorrect, or because of other factors discussed in today’s earnings news release and the comments made during the conference call in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on the websites www.nexteraenergy.com and www.nexteraenergypartners.com. We do not undertake any duty to update any forward-looking statements. Today’s presentation also includes references to non-GAAP financial measures.

You should refer to the information contained in the slides accompanying today’s presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. With that, I will turn the call over to Kirk.

Kirk Crews: Thanks Kristin and good morning. NextEra Energy delivered strong third-quarter results, growing adjusted earnings per share approximately 10.6% year-over-year. In the quarter, FPL continued to deliver outstanding value to its customers in what we believe has been one of the most constructive regulatory jurisdictions in the nation. FPL’s bills are well below the national average, and we are relentlessly focused on reliability and running the business efficiently. Energy Resources extended its leadership position in renewable energy during the third quarter with strong adjusted earnings growth and its best renewables and storage origination quarter in its history. NextEra Energy has clear growth visibility through FPL’s capital plan and Energy Resources’ over 21 gigawatt renewables and storage backlog.

With the strongest balance sheets in the sector and worldwide banking relationships, we believe NextEra Energy has both significant access to capital and cost-of-capital advantages and is well positioned to continue to deliver long-term value for shareholders. Now let’s turn to FPL’s detailed results. For the third quarter of 2023, FPL’s earnings per share increased $0.04 year-over-year. The principal driver of this performance was FPL’s regulatory capital employed growth of approximately 13.6% year-over-year. We continue to expect FPL to realize roughly 9% average annual growth in regulatory capital employed over our current rate agreement’s four-year term, which runs through 2025. FPL’s capital expenditures were approximately $2.6 billion for the quarter, and we expect FPL’s full-year 2023 capital investments to be between $9 billion and $9.5 billion.

For the 12 months ending September 2023, FPL’s reported ROE for regulatory purposes will be approximately 11.8%. During the third quarter, we reversed roughly $245 million of reserve amortization, leaving FPL with a balance of over $1.2 billion. Over the current four-year settlement agreement, we continue to expect FPL to make capital investments of between $32 billion to $34 billion. Our capital investment plan is well-established and focused on enhancing what we believe is one of the best customer value propositions in the industry. Key indicators show that the Florida economy remains healthy and Florida continues to be one of the fastest-growing states in the country. FPL’s third-quarter retail sales increased 3% from the prior year-comparable period due to warmer weather, which had a positive year-over-year impact on usage for customer of approximately 2%.

As a result, FPL observed solid underlying growth in third quarter retail sales of roughly 1% on a weather normalized basis. Now let’s turn to energy resources, which reported adjusted earnings growth of approximately 21% year-over-year. Contributions from new investments increased $0.11 per share year-over-year, while our existing clean energy portfolio declined $0.02 per share, which includes the impact of weaker year-over-year wind resource. The comparative contribution from our customer supply and trading and gas infrastructure businesses increased by $0.04 per share and $0.01 per share respectively. All other impacts reduced earnings by $0.08 per share. This decline reflects higher interest costs by $0.06 per share, half of which is driven by new borrowing costs to support new investments.

Energy resources had a record quarter of new renewables and storage origination at approximately 3,245 megawatts to the backlog, which is the first time we have exceeded three gigawatts in a single quarter. Although we will remind you that signings can be lumpy quarter-to-quarter, we do believe this is a terrific sign of strong underlying demand for new renewable generation. With these additions, our backlog now totals over 21 gigawatts after taking into account roughly 1,025 megawatts of new projects placed into service since our second quarter call. We also removed roughly 1,180 megawatts from our backlog, including roughly 800 megawatts of projects in New York following an adverse decision by NYSERDA two weeks ago. We are optimistic that these projects will ultimately move forward, but are removing them from backlog for now.

The remaining megawatts were removed due to permitting challenges. Overall, we remain on track to achieve our renewable development expectations of roughly 33 gigawatts to 42 gigawatts through 2026. This quarter’s backlog additions include roughly 455 megawatts to repower existing wind facilities, which includes energy resources share of approximately 740 megawatts of repowers within the NextEra Energy Partners portfolio, which I’m going to discuss in a few minutes. As a reminder, in a repower, we invest roughly 50% to 80% of the cost of a new build, are able to refresh and enhance the performance of the turbine equipment, and start a new 10 years of production tax credits, collectively resulting in attractive returns. Energy Resources has previously repowered roughly 6 gigawatts of its approximately 23 gigawatt operating wind portfolio, and we believe we will be able to repower much of our existing wind portfolio in the coming years.

Also included in the backlog additions are roughly 250 megawatts of standalone battery storage projects co-located with existing wind and solar facilities. The combination of the standalone storage tax credit and the ability to utilize existing interconnection capacity from our operating renewables and storage footprint positions us well to serve our customers’ growing needs for capacity. Turning now to our third quarter 2023 consolidated results, adjusted earnings from corporate and other decreased by $0.01 per share year-over-year. Our long-term financial expectations remain unchanged. We will be disappointed if we are not able to deliver financial results at or near the top end of our adjusted EPS expectation ranges in each year from 2023 through 2026.

From 2021 to 2026, we continue to expect that our average annual growth and operating cash flow will be at or above our adjusted EPS compound annual growth rate range, and we continue to expect to grow our dividends per share at roughly 10% per year for at least 2024 off a 2022 base. As always, our expectations are subject to our caveats. Going forward, we plan to fund the business in a manner similar to how we have historically done so at both FPL and Energy Resources. This includes utilizing cash flow from operations for roughly half of our funding needs, in addition to tax equity, project finance, and corporate debt. The sale of tax credits is serving as a new source of capital funding for NextEra Energy. We expect to transfer roughly $400 million in tax credits in 2023 and expect this amount to grow over the next couple of years to approximately $1.6 billion to $1.8 billion in 2026.

This dynamic has reduced NextEra Energy’s capital recycling needs, including those previously met via sales to NextEra Energy partners, which has historically averaged roughly $1 billion of annual cash proceeds. Let me address future equity issuances specifically. Our balance sheet and financial discipline remain core to our strategy. As we find attractive investments for our customers and shareholders, we expect to fund those investments in a way that maintains the strength of our balance sheet. As a reminder, over the last five years, we have issued roughly $1.5 billion annually on average of equity in the form of equity units. We do not expect to issue any equity for the balance of 2023 and expect our year-end credit metrics to exceed those specified by the agencies to support our current ratings.

From 2024 through 2026, we would expect our total equity needs to be no more than $3 billion in total with continued reliance on equity units to satisfy our equity needs, which have no dilution for the first three years. We believe FPL and Energy Resources are well-positioned to manage interest rate volatility in the current environment. At FPL, we primarily rely on the surplus mechanism to offset higher interest rates for the benefit of customers. In addition, FPL’s rate agreement already provided for an ROE adjustment to 11.8%, enabling it to earn a higher ROE in the current higher rate environment. We expect that FPL will be able to absorb much and potentially all of the cumulative effects of the current interest rate environment through the use of the surplus mechanism over the remaining settlement period.

Consistent with the expiration of the current rate agreement, FPL expects to file a rate case in early 2025 for new rates effective 2026. For Energy Resources and corporate and other, we now have $20.5 billion of interest rate hedges in place. While the amounts vary as we add and settle hedges, the tenor of the swaps are between five years and ten years and have a weighted average rate of roughly 3.75%. Swaps allow us to mitigate the impact of interest rate changes on energy resources backlog returns and capital holdings $12.8 billion of debt maturities from 2024 through 2026. Specifically, these swaps allow us to hedge the project-level debt funding we expect to issue on our renewables backlog as well as a portion of the $12.8 billion of the term maturities.

To put this all in perspective, NextEra Energy’s sensitivity for an immediate 50 basis point upward shift in the yield curve has essentially no expected adjusted EPS impact on 2023 and 2024 and has on average $0.03 to $0.05 of expected adjusted EPS impact in 2025 and 2026, which is equivalent to approximately 1% of our adjusted EPS expectations. This sensitivity, of course, assumes we do not implement other offsetting initiatives, including among others, our normal process of cost reductions and capital efficiency opportunities. Our backlog is in good shape and is benefiting from our interest rate swaps, global supply chain management capabilities, and the ability to procure equipment, materials and balance of plant services at scale across our portfolio.

The expected returns on equity for our backlog are mid-teens for solar and over 20 for wind and storage. As we have done historically, we price our power purchase agreements commensurate with current market conditions, including our current cost of capital in order to maintain appropriate returns. In addition, at the time of our final investment decision, before we commit significant capital to our backlog projects, we are utilizing interest rate swaps on contracts that we were entered into when rates were lower to maintain our return expectations. We remain financially disciplined and pass on projects that don’t meet our return expectations. Going forward, we are encouraged by the trends we are seeing in lower equipment pricing for solar panels and batteries, given increased competition globally, and declining prices for materials, which we believe will help offset the impacts of higher interest rates on power purchase agreement prices.

We are optimistic that demand will remain resilient due to the factors you all know well, including the continued cost competitiveness of renewable energy, relative to alternative forms of generation. Importantly to date, demand has remained strong, as evidenced by our substantial new additions to backlog this quarter. Now let’s turn to NextEra Energy Partners. As a reminder, the partnership is a financing vehicle that grows its distribution by acquiring assets with long-term contracted high-quality cash flows and financing those acquisitions at low cost. Over the years, NextEra Energy Partners has been able to rely on low-cost financing to help drive its distribution growth. To meet its financing needs in recent years, the partnership has relied primarily on convertible equity portfolio financing that have a low cash coupon during their term and convert into equity over time.

A significant amount of the equity required to be issued to buy out these financings began coming due this year and over the next several years, which we believe contributed to the partnership’s trading yield almost doubling at the same time interest rates were rising. Consequently, the partnership’s cost of capital increased, which made it difficult to support a 12% growth rate in a way that is sustainable and in the best interest of unit holders over the long term. By reducing the growth rate to 6%, NextEra Energy Partners LP distribution rate is now comparable to its peers, and the partnership does not expect to require growth equity until 2027. In order to meet these objectives, the partnership is focused on first executing against its transition plan.

As a reminder, the transition plans include successfully entering into agreement to sell the Texas natural gas pipeline portfolio and natural gas pipeline assets this year and in 2025, respectively. Doing so will enable the partnership to address the equity buyouts associated with the FPL’s midstream, the 2019 NEP pipelines and NEP renewables to convertible equity portfolio financing through 2025. Through the period of our current financial expectations, that would leave a small equity buyout of roughly $147 million on the genesis holding convertible equity portfolio financing in 2026. The partnership is continuing its process to sell the Texas pipeline portfolio and expects to have an update on or before our fourth quarter call in January.

NextEra Energy Partners is focused on executing against its growth plan for unit holders. That plan involves organic growth, specifically repowering of approximately 1.3 gigawatts of wind projects, as well as acquiring assets from energy resources or third parties at favorable yields. Importantly, NextEra Energy Partners does not expect to need an acquisition in 2024 to meet the 6% growth in distributions per unit target. Today, we’re announcing plans to repower approximately 740 megawatts of wind facilities through 2026, which require the final approval of the customer’s [ph] board of directors, which is expected to be received in the near term. The repowerings are projected to generate attractive CAFD yields and the partnership expects to fund the repowerings with either tax equity or project-specific debt.

Repowerings represent an efficient way to support the partnership’s growth targets. Overall, we are pleased with this progress and remain focused on executing additional repowering opportunities in the future across NextEra Energy Partners’ roughly 8-gigawatt wind portfolio. To minimize the volatility associated with the changes in interest rates and support the growth plan, the partnership also executed roughly $1.9 billion to hedge refinancing costs for the 2024 and 2025 maturities. The resulting expected refinancing costs of the maturities are factored into our expectations. Turning to the detailed results, NextEra Energy Partners’ third quarter adjusted EBITDA was $488 million and cash available for distribution was $247 million. New projects, which primarily reflect contributions from approximately 1,100 net megawatts of new long-term contracted renewable projects acquired in 2022 and the approximately the 690 net megawatts of new projects that closed in the second quarter of this year, contributed approximately $66 million of adjusted EBITDA and $32 million of cash available for distribution.

The third quarter adjusted EBITDA contribution from existing projects increased by approximately $5 million year-over-year. Third quarter results for adjusted EBITDA and cash available for distributions were positively impacted by the incentive distribution rights fee suspension and provided approximately $39 million of benefit this quarter, more than offsetting the cash available for distribution impacts of lower pay-go payments driven by lower wind resource at existing projects. Yesterday, NextEra Energy Partners’ board declared a quarterly distribution of 86.75 cents per common unit or $3.47 per common unit on an annualized basis, which reflects an annualized increase of 6% from its second quarter 2023 distribution per common unit. From a base of our second quarter 2023 distribution per common unit at an annualized rate of $3.42, we continue to see 5% to 8% growth per unit per year in LP distributions per unit, with a current target of 6% growth per year, being a reasonable range of expectations through at least 2026.

For 2023, we expect an annualized rate for the fourth quarter 2023 distribution that is payable in February of 2024 to be $3.52 per common unit. NextEra Energy Partners expects run rate contributions for adjusted EBITDA and cash available for distributions from its forecasted portfolio at December 31, 2023 to be in the range of $1.9 billion to $2.1 billion and $730 million to $820 million, respectively. As a reminder, year-end 2023 run rate projections reflect calendar year 2024 contributions from the forecasted portfolio at year-end 2023. The adjusted EBITDA and related cash available for distributions associated with the Texas Pipeline portfolio have been excluded from these run rate financial expectations. As always, our expectations are subject to our caveat.

While NextEra Energy Partners navigates through this current environment, it’s important not to lose sight of the value of the underlying portfolio. NextEra Energy Partners is the seventh largest producer of electricity from the wind and the sun in the world, with over 10 gigawatts of renewables in operation. The partnership owns renewable projects that deliver high-quality cash flows in 30 states, serving 94 customers with an average counterparty credit rating of BBB plus via contracts with an average remaining contract life of 14 years. We remain optimistic the partnership can be an attractive vehicle to own existing renewable assets over the long term. We want the partnership to be successful, and separately, to address a question we’ve been receiving from some investors, NextEra Energy has no plans to buy back NextEra Energy Partners.

With that, I’ll turn the call over to John.

John Ketchum: Thanks, Kirk. Let me briefly address NextEra Energy Partners. It’s been a difficult year, and we have a lot of work to do. As Kirk shared, we are focused on executing against our transition plans and look forward to providing an update on the Texas Pipeline portfolio sales process on or before the fourth quarter earnings call. We are also focused on delivering LP distribution growth of 6% through at least 2026, and the repowerings we announced today are a good start towards achieving that objective. At NextEra Energy, our foundations are rooted in FPL, the nation’s largest electric utility, and NextEra Energy Resources, the world’s leader in renewables. Both businesses have performed very well, complement each other, and push one another to be even better.

This is validated by the solid financial and operating results both continue to deliver and the excellent progress we are making against our development expectations. Over recent weeks, we met with many of our investors and have welcomed your feedback. In response, we addressed many of the questions we heard from you in our remarks today and in the presentation materials you now have. Along those lines, I want to reiterate the solid fundamentals on which NextEra Energy is built and our outstanding prospects for future growth, having just completed our annual strategy review process with our board of directors. FPL remains among the best utilities in the United States, achieving top operational performance across key metrics while maintaining the industry’s lowest cost structure, one of the cleanest emissions profiles, and a customer bill that is roughly 30% lower than the national average.

It is located in one of the fastest growing states with what we believe is one of the country’s most constructive regulatory environments. FPL has by far the lowest non-fuel O&M of any large utility in the nation. Over the last 20 years, our relentless focus on cost, efficiency and low bills have saved customers nearly $15 billion in fuel cost alone. Year after year, FPL receives top accolades for reliability, despite operating on a peninsula and historically facing a high probability for hurricanes. It has plans to add approximately 20 gigawatts of solar over the next 10 years for the benefit of its customers while undergrounding its distribution system to lower operating costs and withstand the impacts of hurricanes to help keep the Florida economy, which is now the 16th largest in the world, running on all cylinders.

We believe FPL is the highest quality regulated utility in the country. At Energy Resources, we are just getting started. Renewable penetration as part of the US generating mix currently stands at roughly 16% and is expected to double, reaching over 30% by 2030. As the world’s leader in renewable energy with an approximately 20% market share in US renewables origination, Energy Resources stands to benefit significantly from the unstoppable shift towards electrification. Experience and scale matter, and with over 20 years of renewables experience, a 31 gigawatt operating portfolio, a development pipeline of roughly 300 gigawatts of renewables and storage projects, and roughly 150 gigawatts of interconnection queue positions we are well positioned for future growth.

In addition to our scale and competitive advantages that you all know well, our ability to finance cheaper with one of the strongest balance sheets in our sector provides us with an access to and cost of capital advantage. We believe all of this enables us to differentiate ourselves in a complex macro environment to build even more renewables at attractive returns. In short, we believe Energy Resources has built the most competitive and complete renewable energy business in the world and is in a better position than ever to lead the decarbonization of the US economy. We have spent the last two decades building a world-class clean energy platform powered by our greatest strength, our people, and a culture of continuous improvement that drives innovation and smart clean energy solutions.

I want to extend my appreciation to our team today as we remain committed to serving our customers and providing long-term value for our shareholders. Thank you, and now we welcome your questions.

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Q&A Session

Operator: [Operator instructions] Our first question comes from Steve Fleishman with Wolfe Research. Please go ahead.

Steve Fleishman: Yeah, hi. Thank you. So just a couple questions; first on the slide on the tax transferability and the billion dollars effectively creating $6.5 billion of equity content, could you just talk to that more and just, I think if I do the backward math, that’s about a 15% FFO to debt kind of calculation. Is that kind of what you’re using to get to that, or is there more nuance to it?

John Ketchum: Yeah, Steve, on that slide, I’ll take that. This is John. We are — the example is a $1 dollars. You take a $1 dollars, you divide by the 18% FFO to debt, that gets you about $5.5 billion. You add the $1 billion of cash that you receive, and that gets you the $6.5 billion of equity content on a $1 billion transfer.

Steve Fleishman: Got it. Okay. And when you lay out your, that would seem to be a key part, since you talked about the transferability numbers going from $400 million to a $1.7 billion. That’s a key part, and that would show up in your funding plan in the corporate debt issuances now, since it’s not tax equity anymore. That might be kind of matched against that, or would it be in the tax equity and project? How do we think about where that shows up?

John Ketchum: The way I think about it is it’s going to show up in your cash flow from operations. That’s the cash that you actually receive, and then there’s also some equity content that benefits the rest of the sources, including corporate debt issuances.

Steve Fleishman: Got it. Okay. Helpful. And then one other question on the — so the tenor of the interest rate swap seems pretty long, which is helpful. Just, when we think of how you’re using the swaps to kind of basically limit interest rate risk of the projects, how much project, if there’s a $1 billion of a project, how much is project debt going forward, percent of that, let’s say, that you might be using a swap against?

John Ketchum: Yeah, the way I think about it, Steve, it’s 70%. So, when you think about our backlog, just some rough math, if you take the $20.5 billion, I would think about roughly $15.5 billion of that or so going against the backlog, and then the balance going against near-term maturities that we have through 2026. But the interest rate sensitivity that we have given you includes our exposure on everything, right? So, on the project debt, on the corporate debt issuances, it includes it all.

Steve Fleishman: Okay. That’s helpful. And then just one overall question on the renewables environment; maybe you could just talk to, just a little more color on what you’re seeing, because there’s been a general view that the higher cost of capital environment’s really slowing, renewables growth and I just, maybe just more color on what you’re seeing, and is there going to be a slowdown that comes next quarter because of the move up, or just more color on the overall environment would be helpful. Thank you.

John Ketchum: Yeah, Steve, I’m going to turn it over to Rebecca. But one thing I would say is the renewable business is increasingly moving more and more towards the scale players, and you can see reasons why. One of them is the ability to have a balance sheet to actually enter into the kind of interest rate hedges that we can enter into. If you can’t do that, that really puts you at a significant disadvantage. And then all the other competitive advantages that you’re all aware of, where, we buy at scale, we build at scale, we operate at scale. And the last point I want to make is the cost of capital advantage. In today’s market environment, having a strong balance sheet with an ultimate parent with an A-minus rating is really, really important, and a super big competitive advantage that we have over the smaller developers that we compete against and that’s a big part of our success. But let me turn it over to Rebecca to talk more about what she’s seeing in the market.

Rebecca Kujawa: Good morning, Steve. So, we are thrilled with the signings that we posted for this quarter. Obviously, Kirk highlighted that 3.2 gigawatts is a record for us. It’s specifically the first time we’ve been over three gigawatts and it represents, all the things that I think you would want to see, which is strong returns across the portfolio, a great mix of technologies, a good mix of customer type that we signed and entered into these agreements, and also a mix of signings in terms of the date and across those technologies. There were — our first additions to the backlog in 2027, I actually think it is slightly disproportionate to what we’re seeing in terms of our overall backlog and a strong pipeline of projects that we see going into the fourth quarter, which are far more weighted to a little bit in ’24 and a lot more in ’25 and ’26, but we’re really excited about it.

So, really strong and exciting development pipeline and I’ll echo John’s comments and it’s really what we’re seeing on the ground, that after some weariness over the last couple of years, our customers are really, drawn to us for our ability to execute. They understand the pipeline that we’re building and the resources that we bring to bear to get projects successfully built and I think that increasingly matters and we’re going to continue to address it quarterly. But, all signs are very positive for what I’m seeing today.

Steve Fleishman: Okay. Great. Thank you.

Rebecca Kujawa: Thanks, Steve.#

Operator: Our next question comes from Shahriar Pourreza with Guggenheim Partners. Please go ahead.

Shahriar Pourreza: Hey, good morning, guys. Just maybe quickly touching on the embedded expectations for NEP, I guess in terms of the Texas pipeline sale, John, are there any more comprehensive updates on the process? And I guess, are you anticipating any delays or challenges in light of the market conditions and kind of the reason why I ask is there’s obviously a theory out there or a thesis that you’re having a little bit of an issue offloading these assets. So, I’d love to maybe if you can give a little bit more color and anticipation of your full disclosures.

John Ketchum: Yeah, sure. Thank you. Let me start by saying, obviously, as we said in our prepared remarks, our focus is on selling these pipes, growing at 6% and putting NEP in a position to succeed going forward. So, along those lines, we continue to work very diligently on the sales process. We’re working with counterparties to get it done. And at the same time, look, this is a little bit more of a challenging macroeconomic environment. These are very valuable pipes and we are looking for a transaction that maximizes value for unit holders and we’re going to continue to be disciplined. But in terms of the progress that we’re making, things are continuing to advance and move forward and we look forward to having a further update either on the fourth quarter call or sometime before that in terms of where we are.

Shahriar Pourreza: Got it. And then just John, do you anticipate the repowering to sort of fully offset the repowers pipeline sale in ’25?

Rebecca Kujawa: Hey, Shahriar, it’s Rebecca, I’ll take that one. So, we’re super excited about repowers as part of the longer-term growth plan within NEP. And with such an extensive pipeline of renewable projects, to pursue these repowers, it’ll be a nice complement to continuing to acquire assets. So, it doesn’t meet the entire growth plan, but certainly is a nice part of it. As we talked about in May, we have a total of 1.3 gigawatts that we see in the near term. And obviously, this is a first step forward in order to make progress on that. So, attractive CAFD yields, as we noted, there’s still some steps to finish. But we’re also not done with the opportunities repower other assets in the portfolio.

Shahriar Pourreza: Got it. Perfect. And then just lastly for me, just on the sources and uses of cash, I think we all really appreciate the enhanced disclosures there. I guess, obviously, given the capital-intensive nature of the business, do you anticipate any incremental levers to potentially offset the $3 billion of equity and $3 billion of asset sales if, the capital market conditions become a bit more challenged? I guess any reason to rethink around flexing the payout or the balance sheet metrics? Thanks, guys.

John Ketchum: Yeah. Listen, thank you. Thank you, Shahriar and obviously, we are very, very focused, as always on costs. We’re very, very focused on capital productivity and efficiency as well. So, those are two levers we always have and I think our shareholder base is very familiar with the success that we’ve had in our annual cost reduction processes that we run across the company. But those are certainly point of focus for us and look, when I think about the $3 billion of equity and the $3 billion of asset recycling, if you look historically at what we’ve been able to do, I’d be pretty disappointed if we can only do $3 billion of asset recycling, not only through NEP, but third parties and as a reminder, over the last three or four years, we’ve been very successful in selling renewable projects, not only to NEP, but to third parties.

Think about the OTPP transaction, the Apollo transaction, the KKR transaction. So, we feel very good about our sources plan that we’ve laid out and look forward to executing against it.

Shahriar Pourreza: Perfect. Thank you, guys. Much appreciated. Congrats.

Operator: Our next question comes from David Arcaro with Morgan Stanley. Please, go ahead.

David Arcaro: Hi, good morning. Thanks so much for taking my questions. I’m wondering if, you mentioned returns, over 20% returns for storage and wind. I think that’s higher than you’ve indicated in the past and assuming that’s driven by higher PPA pricing, was wondering if you’re seeing, just given higher PPA prices, any impacts to demand in the renewables market here? And how you think about that level of return in terms of whether it’s sustainable, given the competitive dynamics in those end markets? Thanks.

Rebecca Kujawa: Dave, I’ll take that. As you know, we’ve always characterized the backdrop for renewables as a competitive environment. So, I’m very proud of how this team, our team, is executed across an ever-changing environment. And I certainly think it’s a strength of our team and most importantly, the competitive advantages that John has highlighted, investment over a long period of time, the ability to work with our supply chain, the ability to work with the folks that we partner with to build the projects and ultimately operate these projects well over time. So, I think that really contributes to our ability to maintain appropriate returns and I also think it reflects what you expect us to do, which is adjust to all of the current costs of both building, financing and operating projects over time and we believe that we are successfully able to achieve that.

In terms of demand, obviously, we can’t fully predict the future, but I can tell you that the two data points that I think are really top of mind and illustrated from our report today is 3.2 gigawatts is a fantastic sign I think, of demand. And as I highlighted a minute ago to Steve’s question, a good underlying foundation of technology, dates, locations, etcetera. So, I’m really pleased and also, in looking at the pipeline for the fourth quarter, obviously, this is a development business. Things can change. But I believe that we’re in a good position to continue realizing strong demand, particularly in that 24 timeframe to 26 timeframe. So, based on what we see today, very exciting and I think it’s founded on the things that you all know well, which is a backdrop of increasing electrification, increasing demand for generation and capacity value across our sector, and renewables continuing to be the least cost form of generation.

So, I would hope you would expect what I would argue is the best position company to execute well against an environment like that.

David Arcaro: Great. Thanks. That’s really helpful. And I was also curious on the tax credit transfers market. Could you touch on what you’re seeing in terms of demand and interest from counterparties? How deep is that market and what level of pricing that you’re realizing when you’re transferring these credits as it becomes a more important source of cash flow over the next few years?

John Ketchum: Yeah, Dave, I’ll take that question. First of all, I would argue, we have an outstanding tax department. And our tax department, yeah, together with our treasury group started early and we’ve already reached out to 50 of the top U.S. taxpayers in our building relationships and have had terrific execution against our ’23 plan. The demand is extremely robust for tax credit transfers and we’re already working on ’24 as we speak, having ’23 pretty much behind us. And one of the things that really helps NextEra and the tax transfer market is the fact that we have a strong balance sheet. We have an A minus rate from the parent and we’re able to underwrite the credit. And being able to underwrite the credit is really, really important because we compete against a lot of really small developers that can’t, that if you go to the top 50 taxpayers, they’ve never heard of these companies.

They don’t know who they are. They don’t really know what they do. They know NextEra and we can provide an indemnity behind the tax credit that we transfer. It sleeves off our vest, so to speak, to be able to do that and we get preferred pricing because of it and so I feel great about where things stand in terms of our tax credit transfer program.

Rebecca Kujawa: And I’d love to add one point on that because I think it’s a great complement to our broader business and particularly the C&I customers that we’re working with to actually buy some of the renewable energy. Some of the customers that are most active in the market in procuring renewable energy are also the ones that are most interested in buying tax credits from us and I think they really like the value proposition, certainly of the economics, as John highlighted, but really like the value proposition supporting and enabling investment in renewable projects. So we see a really deep market, a lot of interest, and really a lot of cross-selling opportunities across the portfolio.

David Arcaro: Okay, great. Appreciate all the color. Thanks so much.

Operator: Our next question comes from Julien Dumoulin-Smith with Bank of America. Please go ahead.

Julien Dumoulin-Smith: Hey, just going back to the last question a bit, how do you think about the composition of the $25 billion to $35 billion of project tax equity and tax credit transferability, how do you think about your existing tax equity commitments, and how do you think about some of the impacts from a regulatory perspective on the tax equity market? Obviously, you’re talking about a robust start to the tax credit transferability. How much does it matter? How much does it play into that $25 billion to $35 billion, and ultimately, how much TE is contemplated anyway in that range, if you will?

John Ketchum: Yeah, I’ll go ahead and take that, Julien. First of all, when you look at our tax equity project finance split, things can move around. Let’s just hypothetically think about it as kind of 50-50. I think that might be a decent starting place to think about and we feel very good about our ability to be able to access tax equity. the regulatory issues, I think, that you pointed out, I think, are going to get resolved. I think there were some unintended consequences around Basel III, and we have had significant discussions with the folks involved. On those issues, the administration certainly thinks this was an unintended consequence, as do, I think, folks at the Fed and the administration, I think, is very focused on trying to get a good resolution around it.

But, I don’t worry about it too much at the end of the day for us. I think the Basel III thing gets fixed and, worst-case scenario, the banks will find other pockets to be able to issue tax equity. We’ll be issue — we’ll receive our allocation off the top of the deck like we always do. And, these relationships that I just spoke about with corporate parties, these 50 folks or so that we’ve been dealing with, there’s no reason they can’t step in and provide tax equity financing. And we’ll be talking to them about those structures as well and then transferability, which we’ve already spent some time talking about this morning, can fill any gap. So long story short, we feel terrific about our ability to source tax equity financing going forward.

Julien Dumoulin-Smith: Got it. So transferability is not technically part of the $25 billion to $35 billion, but obviously it’s a fluid conversation, right, if I understand that piece.

John Ketchum: Can you say that again, Julien?

Julien Dumoulin-Smith: The transferability, the credit transferability, technically not included in that $25 billion to $35 billion as it stands, but it’s a fluid question of how you finance going forward.

John Ketchum: Yeah. The tax transferability is not in that number. Again, it shows up in cash flow from operations and then the equity content that’s created really shows up in that corporate debt issuance line, but look at the corporate-the cash flow from operations in terms of the dollars that we’re receiving for tax credit transfers.

Julien Dumoulin-Smith: Yeah. And then just quickly, if I can, on the interest rate question here, thank you again for the additional sensitivities and disclosures here. How do you think about sort of a baseline and the open impact as you roll to kind of 2026? I think it’s notable, for instance, you guys reaffirmed through that period with your usual commentary. How do you think about sort of the puts and takes as you roll into that longer dated ’26 period, considering the roll off of the hedges here in that, I think, period more specifically, if you will? Is there a way to kind of quantify the interest rate kind of head one?

John Ketchum: Yeah. So a couple of points I’ll make. One is you’ve seen the sensitivity. So zero impact in ’23 or ’24, $0.03 to $0.05 in ’25 and ’26. With the five year to 10 year tenors, with the average coupon 375 basis points, we feel very good about the protection that we have there. We’ve talked about where FPL sits. And then you think about the project financings that we entered into. We use those hedges. Those project financings are basically 20 year amortizing debt that have 20 year hedges that then get rolled into them that have the benefit of those swaps and so when you think about our existing project finance portfolio that we have, there’s another $4 billion of interest rate swaps that aren’t even in the $20.5 billion that we mentioned to you today that protect and safeguard those as they roll and do.

So long story short, between the $20.5 billion that we have against the backlog the fact that our existing portfolio is already locked in and hedged, we feel very good about our interest rate exposure.

Julien Dumoulin-Smith: Got it. Excellent. All right, guys. Thank you very much. I’ll pass it there. Have a nice one.

Operator: Our next question comes from Carly Davenport with Goldman Sachs. Please go ahead.

Carly Davenport: Hey, good morning. Thanks for taking the questions. Appreciate the incremental disclosure on the funding plan and the asset sales and just to follow up there. Are renewables the only element kind of embedded in that $3 billion in proceeds, or are there any other non-core assets and energy resources that you’d consider monetizing?

John Ketchum: Yeah. So when I think about it, Carly, renewables come top of mind. We’ve had a history over the last several years of being able to recycle capital through renewables. But remember, too, we’re a large company. There are other assets that could potentially be available for capital recycling that are non-core. The FCG transaction that we just recently announced is a good example of that and we’ll always look for opportunities. If there are situations where third parties value assets more than we do, then sure, we’ll look to be opportunistic, but it’s not a core part of the plan.

Carly Davenport: Got it. Okay, great. That’s helpful. And then just as you think about the timing cadence of the backlog additions and also the dispersion across the different technologies, I think, Rebecca, you alluded to the fact that the 4Q pipeline is shaping up to be kind of more weighted to the ’24 timeframe to ’26 timeframe versus this quarter being a little bit longer dated. But can you also just talk about the split across wind, solar, and storage? It seems like there’s been step up in solar relative to wind. So just any thoughts on how you see that piece evolving going forward would be helpful.

Rebecca Kujawa: Thanks, Carly. It’s a great question. Yes, I definitely support that first part of your comment. And it’s consistent with what I had said before that I think this quarter was a little bit anomalous in terms of the waiting to 2027 and the pipeline is very much more weighted for what I see today for ’24, ’25, and ’26, with much of it in the ’25 and ’26 timeframe, just given the fact that we’re ending into ’24. In terms of the technology, obviously, we had very strong findings for storage and as Kirk highlighted in the prepared remarks, in terms of the — maybe not surprise is probably not the right word, but really pleased to see how we’re starting to see adoption across a broader set of markets, not just California, but into the Midwest, where our utility customers and obviously some of the C&I are really valuing the ability to incorporate storage for capacity value and affirming and shaping the renewables product.

So that’s really positive in my mind. On the wind side, I think we’re still seeing a little bit of dynamics that shaped up as a result of the tax credits that we originally we and the industry – thought were going to phase down after 2020. So we saw a significant amount of pull forward of demand. And I think that’s still affecting the industry a little bit and then, obviously, the PTC being extended for solar significantly improved the economics from a relative standpoint, which has been super positive for demand. We still see a lot of geographies where wind is incredibly attractive and so I feel good about long-term demand for wind and I also feel really good about long-term demand for repowering projects. Obviously, we had a great start to the repowering initiative following the IRA extension with over 700 megawatts we talked about today.

Obviously, its share for a year, it’s a little bit less than that, but when you look across the entire tens of gigawatts now of renewable projects, there’s lots of opportunities to repower as well. So overall, across the board, really excited about the opportunities that we have in front of us.

Carly Davenport: That’s great. I appreciate the color.

Operator: Our next question comes from Andrew Weisel with Scotia Bank. Please go ahead.

Andrew Weisel: Hey, good morning, everyone. First, a question. Can you talk a bit about supply chains? I’d be curious your latest thoughts on the availability and status of supply chains, both for solar equipment as well as for grid-level equipment like transformers or switchgears?

John Ketchum: Sure. Yeah, let me take that, Andrew. So, first of all, with supply chain, things are really improved a lot. As Rebecca just mentioned, we have the two issues, right? CERC convention, which has been asked and answered, provided a lot of clarity around what can be done, what can’t, and with the Presidential Proclamation. So, in very good shape there. Second was forced labor and making sure that our suppliers are working constructively with Customs and Border Patrol to get their panels cleared for importation into the country. And so, for the most part all of our solar suppliers have been able to do that and so, we are in very good shape there. I think on grid power, I actually the grid-level issues that you just mentioned, we’re in very good shape on.

We had gone long on grid-level equipment, including transformers and so, we have a significant supply in our inventory and we’ve also looked forward in a plan for this in terms of trying to make sure that we have equipment available where if our customers or the transmission owner in the places that we’re building renewables are short on equipment, are short on grid-level equipment in particular, that we have it in our inventory and are able to offer that up as a solution. And I think one of the big benefits that we have, given our scale and given our leverage and the ability to buy this equipment in very large quantities and really lock up a lot of the manufacturing lines for this equipment, it’s a true competitive advantage for a renewable business the way I think about it.

Andrew Weisel: Great. Just to clarify, NIR [ph] is buying this equipment, or FPL? Like, do you keep those separate inventories?

John Ketchum: Both are. Both are because both need it.

Andrew Weisel: Okay, great. And one quick follow-up, if I may, I’m almost apologizing to bring this up. But the Florida State Supreme Court asked the PSU for some details on their approval of the rigged case settlement. Can you just share your expectations around timing of the process and maybe potential outcomes?

Armando Pimentel: Hey, Andrew. It’s Armando. You’re right that the Supreme Court remanded the settlement agreement back to the Public Service Commission. Our view is that the Public Service Commission is going to take that up soon and will likely be in a position early next year, I would say first quarter of next year, to be able to send that back up to the Supreme Court with the additional details that the Supreme Court is looking forward to receiving. That process would be very similar to the process, both the timeline and the materials that the Public Service Commission went through with the Duke case that was remanded by the Supreme Court back to the Public Service Commission last year, where the Public Service Commission did not reopen the record.

We don’t expect our record to be reopened and made sure that they put together a conclusion that would be satisfactory in their view with the Supreme Court and send it back to the Supreme Court. So we think we’re on the same process as that Duke case was, and we look forward to having the Public Service Commission resubmit that, again, first quarter of next year.

Andrew Weisel: Sounds good. Thank you.

Operator: This concludes our question-and-answer session and the conference has also now concluded. Thank you for attending today’s presentation. You may all now disconnect.