Susan Harcourt:

Thank you, Operator. Good morning and welcome to our second quarter 2024 financial review call. Our press release, presentation, and related financial information are available on our website at aes.com. Today we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements which are disclosed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer, and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our second quarter results and our 2024 guidance and parent capital allocation. Turning to slide 14, adjusted EBITDA with tax attributes was $843 million in the second quarter versus $607 million a year ago. This was driven by growth in our renewables SBU, new rates and growth investments in our U.S. utilities, and higher margins in our energy infrastructure SBU. Turning to slide 15, adjusted EPS for the quarter was $0.38 versus $0.21 cents last year. Drivers were similar to those of adjusted with tax attributes, but partially offset by higher depreciation and higher interest expense as a result of our growth. I'll cover the performance of our SBUs or Strategic Business Units on the next four slides. Beginning with our renewables SBU on slide 16, higher EBITDA with tax attributes was driven primarily by contributions from new projects, but was partially offset by lower availability from a forced outage event at our 1 gigawatt Chivor hydroplant in Columbia. The outage was caused by record water inflows in early June, which brought significant sediment into the plant and damaged the units. Repairs of the plant were completed quickly and all units resumed operations by mid July. Higher adjusted PTC at our utilities SBU was mostly driven by higher revenues from the $1.6 billion we invested in our rate base in the past year, new rates implemented in Indiana in May, year-over-year low growth of 3.1% as well as favorable weather. Higher EBITDA at our energy infrastructure SBU primarily reflects higher revenues recognized from the accelerated monetization of the PPA at our Warrior Run plant and higher margins in Chile. Partially offset by lower margins in the Dominican Republic and the sell-down of our gas and LNG businesses in Panama and the Dominican Republic. Finally, relatively flat EBITDA at our new energy technologies SBU reflects our continued development of early stage technology businesses. Partially offset by continued margin increases at Fluence. Now turning to our expectations on slide 20, as a result of our strong first-half performance and high confidence in a strong second-half, I am very happy to share that we now expect adjusted EBITDA with tax attribute to be in the top half of our 2024 expected range of $3.6 billion to $4 billion. Drivers of adjusted EBITDA with tax attributes in the year ago include higher contribution from new renewable commissioning, contributions from growth investment, and expected higher load at our U.S. utilities. Partially offset by expected closings in our asset sale program. Turning to slide 21, I am also very glad to share that we now expect our 2024 adjusted EPS to be in the upper half of our guidance range of $1.87 to $1.97. We increased our share of earnings in the first-half of the year from 25% in 2023 to nearly half in 2024. Growth in the year to go will have similar drivers as adjusted EBITDA with tax attributes. Partially offset by higher interest expense from growth capital. Now to our 2024 parent capital allocation on slide 22, sources reflect approximately $3 billion of total discretionary cash including $1.1 billion of parent free cash flow, $900 million to $1.1 billion of proceeds from asset sales, and $950 million of hybrid debt that we issued since our last earnings call in May. On the right-hand side, you can see our planned use of capital. We will return approximately $500 million to shareholders this year, reflecting the previously announced 4% dividend increase. We also plan to invest $2.4 billion to $2.7 billion towards new growth. Of which, 85% will go to renewable and utility. Turning to slide 23, we are well on our way to towards achieving our long-term asset sale target of $3.5 billion from 2023 through 2027. We signed or closed more than $2.2 billion of asset sales since the beginning of last year. And we are now nearly two-thirds of the way to reaching our target even though we are only 1.5 years into our five-year guidance period. We do not announce specific asset sales in advance. But the remaining proceeds could come from sell-downs of renewables projects, our intended coal exist, monetization of our new energy technologies businesses, and sales or sell-down of other noncore assets. In summary, we made excellent progress this quarter toward all of our strategic and financial targets. We have clear line of sight towards achieving the key drivers of our year-to-go earnings growth. And we are well-positioned to continue delivering on our financial goals beyond this year. We also made significant headway on our long-term funding plan which allows us continue simplifying and focusing our portfolio while we scale our leading renewables and utilities business. Our strategy to serve high value corporate customers including a rapidly growing base of datacenter providers across our Renewables and Utilities businesses is highly resilient, and will continue to yield financial success for AES and our shareholders. With that, I'll turn the call back over to Andres.

Operator:

Thank you. [Operator Instructions] Our first question today comes from Durgesh Chopra with Evercore ISI. Durgesh, please go ahead.

Steve Coughlin:

Yes, sure. Hi, Durgesh, it's good to hear your voice. So, the credit is looking very, very strong. So, we continue to be on a path of improving credit. At the parent level, I expect will be even higher than last year's year-end. And so, it looks very good. There's obviously intra movement in quarters as we have some cash flow lumpiness coming up, but it continues very strong. I think we'll see the year end be even better than last year.

Steve Coughlin:

Yes. So, we have a threshold of 20%. So, you're referring more to, I think, where we ended, which had plenty of cushion above that. And I think we will likely see ourselves even higher than that at the end of this year.

Andres Gluski:

Sure, Durgesh. No, it's not slowing down our signing of contracts. What we really had is a situation that we had, to some extent; foreseen a couple years ago where it's really there's a shortage of renewable power for datacenters in many markets. So, what's the biggest concern of our clients is actually time to power, can you get me the power on time to power datacenters. And that's their main constraint. So, no, there has been anything holding us down or, quite frankly, a major issue of conversation with them. I do think we have to step back and say, "Look, ITC investment tax credits, production tax credits, they've been around for 32 years." Second, there's been a tremendous amount of investment related to the Inflation Reduction Act. And 85% of that investment has gone into republican districts. Today, there are eight million people working directly or indirectly in renewables in the U.S. So, a total dismantling is highly unlikely in any scenario, whether there are some changes around the margin; sure. But thinking about the sector, quite frankly we operate in markets where there are no subsidies. We actually make more money in those subsidies. And it would change somewhat the structure of the contracts. But we see a wholesale revision of this very, very unlikely. Something more likely what happened to NAFTA, where it became the USMCA, and actually was, quite frankly, updated and improved in some areas. So, that's where we se the market right now.

Andres Gluski:

You're welcome. Thank you.

Richard Sunderland:

Hi, good morning, and thank you for the time today.

Steve Coughlin:

Hi, Rich.

Andres Gluski:

Okay, look, that's a great question. But we will give you more color on that as time passes, because these are multiple agreements with multiple clients. And we'd really like to see how it shakes out. We're certain that there's going to be a lot of load added, a lot of transmission assets added. But this is between two utilities, between multiple clients. So, right now it's a little bit too early for us to give too much in term of exact load growth by business.

Richard Sunderland:

Understood. Thanks for the color there. And then, your language in the slides on maximizing megawatt quality over quantity; that message has certainly been clear. But I'm curious if this is consistent with your raise per turn assumptions, I think that was back in 4Q. Or do you see further upside potential to returns given the supply and demand dynamics currently?

Richard Sunderland:

Great, thank you for the color there. I'll leave it there.

Operator:

The next question comes from Antoine Aurimond with Jefferies. Please go ahead.

Andres Gluski:

Good morning.

Steve Coughlin:

Yes. So, as I said, credit metrics are definitely continuing to improve and so I see that as a possibility in a matter of years, not this year, that will be have those metrics. So, we don't have a specific target to share with you at this point, but I expect to be higher than last year and I expect it to continue to improve. As the installed base of our growth continues to grow and add cash. Today, we do carry construction debt that's not yet yielding. But relative to the base, the base is increasing every year significantly in this moment that we are in. So, yes, I think that's very possible, but I don't have a specific date to share with you at this point.

Steve Coughlin:

Yes, and actually, I guess we'll keep going here because I have just that reminds me of another topic really here. Keep in mind that 80% of our debt is nonrecourse to the parent, and nearly all of that is amortizing investment grade rated subsidiary debt. So, it's a very high quality structure, and the agencies are seeing that. So, I think this, both the quantified metrics as I've mentioned as well as Andres said in the quality and looking at the debt structures, amortizing investment grade, it's a very, very robust, healthy structure.

Steve Coughlin:

End of the time period, like 2027 you're speaking?

Steve Coughlin:

Okay. Look, I'd say we can I think there's a transformation in terms of, we're moving more towards U.S. dollar based investment grade off takers? So, yes, there's going to be heavier weighting towards the U.S. We do have opportunities to serve the same type of clients outside the U.S., with your investment grade dollar contracts, many times with the same, with the same client. So, if we serve hyperscalers in the U.S. and they want the same services, say, in Chile or in Mexico, then we can service. And that is a competitive advantage we have.

Andres Gluski:

Look, when I put it this way, we have a backlog of more than 12 gigawatts of signed PPAs we have to deliver. The majority of that will be within the period of by 2027. So, that gives you -- that that's a guaranteed build out that we have to do over the next three years. So, over time, assuming we're signing somewhere about 4.5, 5.5 gigawatts of new PPAs, those numbers have to converge. Unless, we grow the number of megawatt, PPAs that we're signing, and then it'll take a little bit more time to converge. But given -- that gives you sort of the run rate. Yes. We'll be 4 plus in coming years just from the backlog we have today, and expect that to grow over time past that period of time of 2027.

Andres Gluski:

Thank you.

David Arcaro:

Hey, good morning. Thank you. Maybe back on the utility side of things, it's great to see all that load growth opportunity coming. When do you think you'd have an opportunity to relook at the CapEx outlook? And then at a high level, how do you think about financing, upsides in the utility CapEx trajectory?

David Arcaro:

Got it. That's really helpful. Thanks for that. And then, just appreciate the comments on the supply chain outlook on the renewable side. I was just curious if I could get your sense, like how much line of sight do you have right now for that domestic supply in 2026, just as we think about navigating some of the tariffs on solar panels and battery storage? How are you feeling right now in terms of the line of sight for both of those supply chains?

David Arcaro:

Okay, great, understood. Thanks so much.

Steve Coughlin:

Thanks, Dave.

Unidentified Analyst:

Hi, good morning. Thanks very much for taking my question. So, I guess just first quickly on renewable execution, really great to see the guidance update in terms of EBITDA with tax attributes. I guess, could you maybe just talk about, given the backlog, the PPA signing cadence, the ability to bring projects online, how does your EBITDA excluding tax attribute would trend, I guess given where it is now year-to-date? Seems a little light, but just wanted to see how should we think about it going deeper into the year? Thanks.

Unidentified Analyst:

Got it. No, that's very helpful. I guess second, we noticed a comment on being able to bring the majority of the backlog online by 2027. I guess with this year, 2024, a targeted 3.6 gigawatts of new projects online, could you talk about the cadence on bringing new projects online -- just on this front, from this year through 2027, and what kind of lumpiness should we expect coming out of it?

Unidentified Analyst:

That's great. Really appreciate the colors from both. Thanks.

Steve Coughlin:

Thank you.

Michael Sullivan:

Hey, good morning.

Michael Sullivan:

Yes. Hey, Andres. A couple of questions, I know there's been some on the utility growth, but 50% plus load growth seems pretty eye-popping, and I'm just curious, like, how you're feeling about the supply side and ability to serve that. Like, for example, if I just look at, you have an AES Indiana, I don't know, I mean, there's like a planned conversion, and then a handful of renewables, and a lot of load growth coming. And then, obviously, in Ohio, you have less control over the supply, and we got a data point on that earlier this week. I guess, yes, just how explosive load growth, how are you feeling about the ability for generation to serve that in those two states?

Steve Coughlin:

Yes. And I would just add to Andres' point in Indiana, where generation will be part of the solution keep in mind, we have multiple existing gas sites. So, we have the conversion at Petersburg, but we also have space for additional gas at Eagle Valley, at Harding Street, and at the Georgetown site. So, we are seeing the whole package being able to support datacenter growth there. In Ohio, of course, you mentioned that that's a distribution transmission. We have a very attractive area for datacenters, our service territory is quite large, a lot of available cheap land, very centrally located to fiber networks and data load, accessible water. So, it is a very appealing area. You can see from the -- I think you're referring to the PJM capacity auction, was quite high, demonstrating how significant demand has increased. But within PJM, I think our territory in Western Ohio is one of the most attractive areas, if not the most.

Andres Gluski:

Yes, look, right now we have no appetite for generation in Ohio directly, but again, this represents opportunities for our renewables team. So, I would say stay tuned, but certainly we feel that these targets can be met, but again realize this is going to happen over time, as Steve had said in his comments.

Andres Gluski:

No, that's already embedded in our guidance.

Michael Sullivan:

Great. Thank you.

Operator:

The next question comes from Willard Grainger with Mizuho. Please go ahead.

Andres Gluski:

Yes. Good morning.

Andres Gluski:

Look, we have been saying, again, for several years that we were seeing shortages developing, just looking at the corporate demand, especially for renewables, and the ability of suppliers to ramp up to meet that demand. So, to some extent, what is happening in the market is what we expected. This is not going to make any difference to our plans. Again, we have contracts, we have sites, we've already locked in financing, et cetera. So, equipment prices, so it doesn't make any change to our plans. What it does, I think, signal is the value of our existing assets are going to go up as this shortages materialize. So, no effect in the, generally, in the shorter term, but in the longer term, it means that our assets are more valuable, and to some extent, it's what we've been planning for. So, it's not, of course, a specific option, we don't intend to be clairvoyant, but the general direction of the market that's unfolding is what we expected.

Andres Gluski:

Okay. Thank you.

Angie Storozynski:

Thank you. So, I have lots of questions. So, first, maybe in this low interest rate environment, I'm just, I'm actually wondering. So, first, again, so does that actually help further boost the profitability of the projects that are yet to be built? Meaning, I mean, you have embedded certain assumptions about interest rates for like construction financing, for cost of debt, et cetera. So, do I get actually an incremental benefit now that we're seeing seemingly in a lower interest rate environment?

Andres Gluski:

Obviously, we are highly contracted for future cash flows. So, lower interest rates means a lower discount rate. It means those cash flows are worth more. But the benefits on a sort of new contract basis will be for new contracts being signed, but not for the backlog.

Andres Gluski:

That's a great question. The way I would put it is their preference is renewable power. Right? So basically, you're talking about situations where they have no other alternative. So, they're not happy to suck up coal power from the grid. They basically will either have offsets with a VPP or by RECs, and quite frankly, in most cases, will require that renewables come online in the future. So, you have to put it like this is the last alternative. And so, obviously, if you have a datacenter, the most important thing is to have power. So, if you have no other alternative, you will not go for renewables. But they do have the renewables goals, and they do want that power to be as low carbon as possible. So, that's in terms of the demand. Now, let's look at the supply. If you look at what's in the interconnection queue, almost all of it is renewables, if you include batteries. So, the fact is what can get built, let's say, over the next five years, for sure, is going to be very heavily weighted towards renewables. As Steve mentioned, you have to combine these in the lowest carbon way possible. And if that means adding some gas plants, that will be done. But I think that the direction is clear, because I remember you on one call said that it's all going to be nuclear. And I kind of laughed, we both laughed and said, tell me what the price of an SMR is? How can we sign a PPA with embedding nuclear? Second of all, the regulatory hurdles to bringing on nuclear are still very significant. And we really don't have price certainty on it. So, renewables are going to be the bulk of that add-on. That's what they want. Again, yes, they will make deals for the short run if that's the only alternative. But it's not their preferred route.

Andres Gluski:

Yes, I think it depends on the client, quite frankly. Some clients are much more stringent. Some clients actually want hourly-matched renewables. Some clients require additionality. Most of them require additionality. So, it's not just one-size-fits-all. I think the renewable standards will differ among them. But the direction is very clear. So, I don't see anybody sort of walking away from it at this point. And quite to the contrary, they're under pressure a lot because as they ramp up very significantly their datacenters and they're taking some power which is not renewable, their total carbon footprint goes up, and that's something that they've had to address. So, I would say that, yes, they're being pragmatic. But in terms of their goals and desires, those remain unchanged. And it's not uniform across all of them. It's not one-size-fits-all.

Steve Coughlin:

Yes. So, I'll just add on to what Andre said. So, in almost all these cases, even you're talking about, Angie, not to say, yes, these are resulting in renewable PPAs, some cases in the same location or nearby locations, and others where they're focused on time to power going to the grid, but then also contracting for renewables perhaps further away. Most of what we are doing is I would say you would call more of a co-location regionally where we're supplying energy, including most of what we signed recently in the same grid and relatively close to the datacenter. So, that is by and large what we've seen most looking for. But when time to power is, of course, a priority, they're looking for alternatives. But the great thing is that in all cases, the additionality of renewables, whether it's direct or through RECs, is a top demand from these customers.

Andres Gluski:

I would say, look, first, we have the lowest rates in the state. So, we're starting off from the best position of anybody. Second, realize that our new additional growth, these are people who, again, the most important thing is to find a good location and to have the power and the other services that they need. So, that does not concern me in terms of, let's say, saying, well, this growth will not happen because the capacity prices went up. And as I've said before, to some extent, not this particular auction, not the extent of this one-time jump. But we had been expecting this. So, this is not something that's like out of left field and we have to scramble. We have been talking about, and you can hear from all our earnings calls, and we've been saying, look, there's going to be a shortage. And returns are going to improve over time. And so, directionally, this is very much what we expected.

Andres Gluski:

All right. Thanks, Angie.

Biju Perincheril:

Yes, thanks for taking my question. A question on domestic content bonus, can you talk about when your projects might -- when you're targeting your projects to be eligible for that and maybe the implications for your returns? And if you could talk to separately the solar and storage projects, that would be great. And then, I have a follow-up.

Steve Coughlin:

And I would just add, keep in mind that the adder is across the entire capital cost of the project once you meet the threshold for the certain components that have to be domestically sourced. So, it's a 10% across not just those components, but the whole thing, which is really attractive.

Steve Coughlin:

Right.

Biju Perincheril:

And is your expectation that you would be able to retain most of that or you would have to pass along that in terms of PPA pricing, just trying to understand the impact to your returns?

Biju Perincheril:

Okay.

Biju Perincheril:

Got it. My follow-up was -- and we talked about a lot about sort of time to power. So, for renewables projects, can you talk about sort of the advantages or what you bring to the table specifically from a technology perspective? I think last quarter you sort of talked about DLR and batteries and that almost that or there are other solutions that you could bring to the table in terms of addressing that concern for your end customers.

Biju Perincheril:

Okay. Thank you.

Operator:

Those were the questions we have time for today. And so, I'll turn the call back to Susan for any closing remarks.

Operator:

Thank you everyone for joining us today. This concludes our call. And you may now disconnect your lines.

Susan Harcourt:

Thank you, operator. Good morning and welcome to our First Quarter 2024 Financial Review Call. Our press release, presentation, and related financial information are available on our website at aes.com. Today we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements which are disclosed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer, Steve Coughlin, our Chief Financial Officer, and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our first quarter results and our 2024 guidance and parent capital allocation. Following that, I will provide a deeper dive into our low-risk, highly-efficient capital structure, which is important for everyone to understand. Turning to Slide 13, adjusted EBITDA with tax attributes was $863 million in the first quarter versus $641 million a year ago. This was driven primarily by contributions from the roughly 600 megawatts of new renewables we brought online. Turning to Slide 14, adjusted EPS for the quarter was $0.50 versus $0.22 last year and in line with our expectations. Drivers were similar to those of adjusted EBITDA with tax attributes but also included higher parent interest expense and a lower adjusted tax rate. These results include approximately $0.08 of tax benefits consistent with our expectations, which were associated with steps we took this quarter to transition to a more U.S.-oriented holding company structure that is better aligned with our significant U.S. growth. In the future, we may recognize further benefits from our revised simpler structure, although likely of a smaller magnitude. We continue to expect an adjusted tax rate of 23% to 25% for the full year, excluding the impact of tax credit transfers, which we are showing at the SBU level for simplicity. I'll cover the performance of our SBUs or strategic business units on the next four slides. Beginning with our renewables SBU on Slide 15, higher EBITDA with tax attributes was driven primarily by contributions from new businesses but was partially offset by lower renewable resource in Panama and Brazil. Higher adjusted TTC at our utilities SBU was mostly driven by favorable weather in the U.S., as well as higher revenues from investments in our rate base. This was partially offset by interest expense on new borrowings to fund future growth. Relatively flat EBITDA at our energy infrastructure SBU primarily reflects prior year higher LNG transaction margins and the sell down of our gas and LNG businesses in Panama and the Dominican Republic. This was partially offset by higher revenues recognized from the accelerated monetization of the PPA at our Warrior Run plant. Finally, higher EBITDA at our new energy technologies SBU reflects continued margin improvement at Fluence. Now turning to our guidance on Slide 19. We are reaffirming our 2024 adjusted EBITDA with tax attributes guidance of $3.6 billion to $4 billion and 2024 adjusted EBITDA guidance of $2.6 billion to $2.9 billion. We expect to continue to see strong growth in our renewables and utilities businesses partially offset by short-term dilution from continued execution on our $3.5 billion asset sale target through 2027. We are also reaffirming our 2024 adjusted EPS guidance of $1.87 to $1.97. Our earnings will have similar drivers to adjusted EBITDA with tax attributes but will also be impacted by a lower adjusted tax rate and higher parent interest. We anticipate a more even distribution of cash and earnings throughout the year with nearly half of earnings expected to come in the first half versus only 25% in 2023. Now to our 2024 parent capital allocation plan on Slide 20. Sources reflect approximately $3 billion of total discretionary cash including $1.1 billion of parent-free cash flow, $900 million to $1.1 billion of proceeds from asset sales, and $900 million to $1 billion of planned parent debt issuance. As a reminder, we limit any parent debt issuance to a level consistent with our investment grade credit metrics. We continue to be very pleased with the great progress toward our $3.5 billion asset sale program, which will limit and may eliminate any need for future parent equity issuance throughout our long-term guidance period. On the right-hand side, you can see our planned use of capital. We will return approximately $500 million to shareholders this year, reflecting the previously announced 4% dividend increase. We also plan to invest approximately $2.6 billion toward new growth, of which 85% will go to renewables and utilities. One of our strengths is the flexibility we maintain in our capital plan across both sources and uses. As we have for many years, we will continue to execute on opportunities to rotate capital across the portfolio in a manner that creates shareholder value. Next, I want to take a moment to discuss how we manage our balance sheet on Slide 21. First, we utilize non-recourse debt to fund our growth. Approximately 82% of the debt on our balance sheet is non-recourse to AES Corp., meaning it is only secured at the relevant subsidiary level. This important structural component limits our risk at the parent company to the equity we invest in our subsidiaries. We further insulate our financials from interest rate movements, with nearly 90% of our long-term debt being fixed rate or hedged. In addition, nearly $4 billion of the debt on our balance sheet is under designated construction facilities, which are also non-recourse to the parent company, but are backed by projects that don't yet generate earnings or cash. When a project reaches commercial operations, approximately half of this construction debt will be repaid with cash generated from the monetization of tax attributes, leading to a significantly lower long-term leverage profile on projects in operation. As a result, recourse debt to the AES parent is only 18% of total leverage. Using an example of a typical U.S. solar plus battery project on Slide 22, we've centered our strategy around a capital-efficient model which quickly recycles cash, enabling the rapid growth we've achieved in recent years. First, when we place a project in service, we pay down at least 40% of a project's capital cost with tax equity partnerships and tax credit transfers. Our projects typically benefit from the investment tax credit, which provides an attractive upfront cash return on our investment and significantly reduces net parent cash requirements. We fund an additional approximately 40% using fixed-rate, amortizing, non-recourse debt, which is investment-grade rated. In order to insulate project returns from changes in interest rates, we pre-hedge this expected debt issuance when we sign a PPA. We currently have nearly $9 billion of outstanding interest rate hedges on our balance sheet, most of which relate to our U.S. renewables business. With respect to equity requirements for U.S. renewables, our development partner, Alberta Investment Management, or AIMCO, contributes 25% of equity capital needs. Once a project is completed, we typically bundle it into an operating portfolio and sell down a large minority stake at an attractive premium and recover most, if not all, of the upfront parent equity investment in the project. The end result is a material ownership in a high-quality, long-term renewables project with little net cash invested and de minimis risk to our balance sheet. This model allows us to grow rapidly while maintaining an investment-grade credit rating and ensures our financial results are not sensitive to changes in interest rates. Now, turning back to our first quarter results, we've had a tremendous start to the year, making significant progress toward all of our financial targets. We expect to continue the momentum in the year to go as we complete our remaining 3 gigawatts of new projects and continue growing the rate base at our U.S. utilities while maintaining a low-risk, highly efficient capital structure and funding plan. With that, I'll turn the call back over to Andres.

Operator:

Thank you. [Operator Instructions] Our first question comes from Nick Campanella of Barclays. Nick, the line is yours.

Andres Gluski:

Yes. Well, thanks for the question. Look, historically, I believe we've always overachieved our asset sale targets. So last year, we overachieved by about $600 million, so we're coming into this year with some tailwinds. So we don't comment on any specific asset sale until they're closed, but we feel good what has been disclosed is, for example, we have already sold the Vietnam asset and are just waiting government approval. So that's quite a large sale that it's already, let's say, it's not closed, but the sale is done. We just have the final government approval. So we feel good about it. So the general statement is that if you look over our tenure of the last decade, we've been very frugal about issuing new equity. We've actually, in the net, bought back shares. We've also paid $3 billion worth of debt. So we've been able to do this transformation, being very, very stringent about issuing any new equity. So depending on how the asset sales goes and our growth programs and our partnerships, we feel that we may be able to do this without any additional equity issuance. We've always talked about it being in the later years of our guidance period. And we've also mentioned that we would never do it at current valuations. So I hope that provides as much color as we can, but I think it gives you a clear notion of what our intent is.

Andres Gluski:

Look, I think that we identified several things some years ago. So first, just looking out, as I've said many times in our meetings or calls, that we saw a shortage, eventually a shortage of renewable projects, giving the increase in demand. So we had somewhat of a lag in 2020 due to tariff issues, but that there was basically going to catch up. So what we were seeing is that there was going to be more demand, quite frankly, than supply for renewables, number one. Number two, we very early on identified data centers and technology companies as really our sweet spot in terms of future deals. And we've been working with them. So we have innovated coming up with things like hourly matched carbon-free energy with the data centers. So we've already done six gigawatts. So we're out ahead. These are actual projects that have been done. So we have very close relationships with them. And I would say that, coming up with the various ways of us helping them meet their needs, certainly things that we have been discussing for some time. So our real focus is on meeting their needs. And what we see is that things like pipeline, and we started building up this pipeline again several years ago, really thinking about what they would need. So finding the sites. And, I'd say the most strict about when we talk about backlog, it's a signed contract. It's not something we expect to sign. When we talk about pipeline, it's actual having some degree of land control, and it's being in the interconnection queue. It's not we're prospecting in this area. We've had some discussions. So, you know, we feel very good about our ability to meet these clients' needs, and I think understanding very well what those needs are. So, I don't see this really just as a zero-sum game. What we see is that, the deal that was announced in the last week, an international deal is good. It's good because there's a lot of demand out there, and we're not going to be able to satisfy it all by ourselves. And second of all, I think it shows the value of having an international presence and the value of being in diversified markets to be able to satisfy their needs. So, I think there's been a lot of focus on the specific technology, not enough focus on how do you satisfy the needs of those clients. So, that's what we've been focused on. But quite frankly, this is nothing new to us. We've been doing this, almost five years.

Durgesh Chopra:

Just maybe, can I get your thoughts on potential tariffs? There's been talks of some anti-dumping tariffs and just how you position there, if something were to take place.

Durgesh Chopra:

And that is very clear, Andrew. Thank you. And then maybe can I just follow up on Nick's question regarding asset sales? Just as we think about the cadence of announcements here for the rest of the year and into 2025, do you see potential for a large deal, a large asset sale, or maybe a large one buyer or a large buyer in place of like, multiple small buyers or multiple small deals that you've done in the past? Maybe just can you discuss that?

Steve Coughlin:

Yes. And I would just add, Durgesh, as Andre said, we have a long track record. So it's not just about the goal. It's also about securing the best value and exiting properly. So we have a lot of pathways to do that. We have 3.5 billion is a conservative number and it's a combination of our coal exit, our simplification of our international portfolio, monetizing some of our technology businesses, and the renewables recycling. So there's a number of ways. And so it allows us the luxury of ensuring that we get the appropriate value. And we're looking out in the market on all of these and transacting when we see that appropriate valuation. And, we were ahead, as Andre said, by over $600 million last year. So we feel great.

Andres Gluski:

Let's see. I think that what we're seeing is they're very concerned about getting power. They're talking about time to power. How fast your renewable projects can come online. I think that the market's beginning to realize that this growth in data center demand will be mostly powered by renewables. They are the cheapest energy, and they're going to be the fastest time to power. There was a lot of talk about, say, something like nuclear. So while existing nuclear plants can be recontracted and provide power, they aren't additional. They aren't decreasing the total carbon footprint of the system, number one. And it takes years to bring new nuclear online. So, while I'm a believer in nuclear in the long run, it's like, okay, time to power, I'm bringing data centers on in the next three years. How am I going to power them? And that's really where renewables will play a key role. Now, what do I think? I think those people who have advanced pipelines are going to be in the best position, who have the supply chain and have the projects. And the other thing that I find very interesting is that I think pipelines are extremely valuable, and I don't think people are valuing them enough. And I would say, just think about if you were coming in from zero to create a pipeline of, say, 50 gigawatts in the U.S. How much would that cost you? And those pipelines aren't just for projects in the next two to three years. Those pipelines are going to be serving projects, certainly within the next five and beyond that. So I think that, to answer your question, there is a lot of pipeline in the States. There's a lot of interconnection. The question will be those developers who will be able to bring them on in time for the data centers. And I think it will require flexibility. So I hope that answers your question. And this view has not changed. What we have seen, I would say, is that, data center growth, certainly in the last year has accelerated. But we saw a huge corporate demand coming and data centers being part of that.

Richard Sunderland:

Maybe picking up on that last question from Durgesh, I'm curious if you could speak a little bit more to transmission constraints and how that's being impacted by this accelerating pace. You obviously have interesting perspective, both on the commercial side and on the utility side. I'm curious, again, how you position from an interconnection perspective the pipeline for value there, and if there are ways to maybe realize even more of that value through unlocking transmission.

Richard Sunderland:

Now, that's very helpful color, and appreciate all the context to that. Maybe switching gears, hydrogen overall been an active focus area for you, featured heavily in some of your updates last year. Just curious to get a temp check on that front, what you're focused on now, what we should be watching in terms of updates on the hydrogen front over the balance of the year. Thank you.

Operator:

Our next question comes from David Arcaro of Morgan Stanley.

Steve Coughlin:

Yes. I'm not sure the data you're looking at, but we had actually quite a very good quarter. I think it was 1.2 gigawatts signed in the quarter, David. So we're very, very pleased and also very pleased that we were able to announce Amazon as our Bellefield customer, which is really a total of two gigawatts with Amazon, including the first phase from last year and then the second phase. And so that's an example of the things we've been doing with data centers on a very large scale. So we've done a lot in the first quarter. We've been active not only in signing but also in executing and spreading our execution throughout the year, as I mentioned. So we had many more megawatts installed in this quarter. And as such, our earnings for the year will be much more balanced. But no, we feel really good about our signings target. The demand is stronger than ever. And I think the deal announced earlier this week with Microsoft, as Andre said, is just one example of what we've been saying is that the renewables is where these folks come first. And that was a 10-gigawatt agreement. And so it dwarfs anything that's been signed with like a nuke or things like that. But as Andre also said, this is not a zero-sum game. And there is much more demand here and continuing to come. And so we feel really good about our pipeline and the maturity of it and where it's located and its positions in the queues. So no, I think our signing progress has been excellent and still feel really good about where we're headed for the rest of the year.

Andres Gluski:

Well, I think that's sort of a framework agreement. And I think what we've been doing is negotiating big deals and I would say with several of the hyperscalers. So we're not just solely focused on one. And so we're looking at how to solve their demands. And quite frankly, they have slightly different preferences where they're going. We have data center deals with Microsoft in Chile, for example. What they're looking for is people who can provide, of course, U.S., the biggest, the fastest growth. But I think they're very interesting international opportunities. And it depends where you have your footprint. So I believe the deal that we're talking about in Brookfield, they have more Asia and European capabilities. And quite frankly, we have decided not to be in those markets.

Angie Storozynski:

So I know we talked about it in the past, but I just wanted to go back to this. How much it really costs to develop these renewables and how seemingly little of an EBITDA and cash recreation you guys are going to get from it. And even using your math, right, with this, the financing of CapEx and the amount of money that you were planning to spend on renewables from the analyst day, and you would end up with like about $2.7 billion of your equity contribution and say $350 million of free cash flow on the back of it. Just again, using the target return. Isn't that, I'm just wondering if that's enough. I mean, is it time to maybe add these return expectations, or is it just simply, that's how competitive the market is and you just have to accept the terms. All I'm trying to say is that it doesn't seem like it generates enough EBITDA or free cash flow from the amount of investment that those renewables require.

Steve Coughlin:

Yes. I would just add, Angie, also on the EBITDA profile, the EBITDA in the U.S. is growing significantly. I think you're not seeing it in part because of some of the things happening in LATAM around the El Niño, where we've had lower hydro generation, for example, in Panama, as I had in my comments. Brazil's had very low wind in the first quarter. And then, frankly, Q1, and even in the U.S., is a very low solar irradiation quarter. So you won't see the EBITDA growth to the same degree. But within that number, there's substantial U.S. growth throughout this year. But it is somewhat offset by a couple of those other factors outside the U.S. So the EBITDA is strong. And the other thing I'd mention in terms of developing renewables, we've been perfecting this machine for many, many years. So the development has gotten quite efficient. We are able to drive high success rates through our development process. And so that cost continues to come down relative to bringing projects successfully online. So we can go into more detail, perhaps, separately. But it is a very attractive profile for this business.

Steve Coughlin:

Yes, Angie, it's all good points. And so you're absolutely right that the proximity is important within the region. Now, the co-location, I think, is overblown in terms of you're adding a new load to the interconnection and approval, regardless of where this data center is. But what are they really looking for? As Andre said, they're looking for renewables, and they're looking for additionality, meaning new renewables. And so you do want to do that in a smart way by minimizing your transmission charges. So you want them to be within a region of the data center. And then you want to be able to add batteries in many cases. And we see tremendous upside. We've been developing battery storage, both technology and Fluence, as well as battery storage projects in our portfolio for a very long time, a decade plus. So that's a huge advantage for us in being able to meet their carbon-free needs throughout the entire day. And so being able to have those battery sites in the region with the solar, with the wind sites is key. And having that flexibility. So it's not a market you can tap into just by jumping into this. You have to have had foresight for five years plus to be advanced in developing all these technologies within these regions to do that. And then, the other thing I would say is that because and we've talked about this, the data center locations are expanding more towards the middle of the country. And so it's opening up many more locations, which have much more land availability for solar, for wind, into regions like MISO, into ERCOT, less congested in the coast. And so that's an advantage in terms of ensuring you're locating your data centers close to your generation sites as well.

Operator:

Our final question comes from Michael Sullivan of Wolfe Research. Michael, please go ahead.

Andres Gluski:

Let's see. What I had mentioned in my speech is that certainly that as we're involved in these negotiations with hyperscalers due to transmission and other attributes that, there is interest in our two utilities for possible locations. Now, this would be outside of the IRP, per se, because this would be an additional demand that would be put onto our systems.

Andres Gluski:

We have nothing specific to announce at this time. We just thought it was important because when we talk about it, we've talked about what we've done purely. We haven't talked about, well, this is the first time we mentioned, for example, the megawatts that we're doing and actually providing that energy for other utilities to four data centers, and we might be able to do some for ourselves.

Andres Gluski:

In closing, Steve brought up a very good point that, what we're seeing is growth in corporate demand. It's not just data centers. So what you're seeing in our service areas is, for example, a reindustrialization of the U.S. So you have on-shoring, whether it be EVs, battery manufacturing, panel manufacturing, other things, which is growing very substantially. And then, you have to add in the load for electrification, because people have been talking about, EVs as if they're not selling. But the fact is they're growing very fast, charging stations are growing. They're just growing less than some of the forecasts that people had put out there. But if you look at, for example, China, 50% vehicles sold are EVs. So what we see is an increased demand from corporations, from all of these sources. We have particularly focused on tech companies and data centers as really our sweet spot. But, internationally, it's the same. What we want is long-term, dollar-denominated contracts with investment-grade offtakers. And, again, we're doing well on both. So very optimistic about the sector.

Andres Gluski:

We don't comment on that, quite frankly. And, Fluence has its call later in the week, or next week. So we can't give any further color on that.

Susan Harcourt:

All right. We thank everybody for joining us on today's call. As always, the IR team will be available to answer any follow-up questions you may have. Thank you and have a nice day.

Susan Harcourt:

Thank you, operator. Good morning and welcome to our fourth quarter and full year 2023 financial review call. Our press release, presentation and related financial information are available on our website at aes.com. Today we will be making forward looking statements. There are many factors that may cause future results to differ materially from these statements, which are disclosed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer, Steve Coughlin, our Chief Financial Officer and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our 2023 results and capital allocation, our 2024 guidance, and our updated expectations through 2027. As Andres mentioned, 2023 was AES's best year on record as we met or exceeded all of our strategic and financial targets. We beat our adjusted EPS guidance range of $1.65 to $1.75 and our parent-free cash flow guidance range of $950 million to $1 billion. We also recorded strong adjusted EBITDA well above the midpoint of our inaugural guidance range of $2.6 billion to $2.9 billion. Turning to slide 14, full year 2023 adjusted EBITDA with tax attributes was $3.4 billion versus $3.2 billion in 2022, driven primarily by contributions from new renewables projects, as well as the recovery of prior year's purchase power costs at AES Ohio included as part of the ESP4 settlement. These drivers were partially offset by lower contributions from the energy infrastructure SBU. Turning to slide 15, adjusted EPS was $1.76 in 2023 versus $1.67 in 2022. Drivers were similar to those for adjusted EBITDA with tax attributes. In addition, there was a $0.06 headwind from parent interest on higher debt balances primarily used to fund new renewables projects. I'll cover our results in more detail over the next four slides, beginning with the Renewable Strategic Business Unit or SBU on slide 16. Higher adjusted EBITDA with tax attributes at our renewables SBU was primarily driven by contributions from the 3.5 gigawatts of new projects that came online in 2023, as well as higher margins in Columbia, but partially offset by the sell down of select U.S. renewable operating assets. At our utilities SBU, higher adjusted PTC was primarily driven by the recovery of prior year's purchase power costs at AES Ohio included as part of the ESP4 settlement, as well as rate-based growth in the U.S. Lower adjusted EBITDA at our energy infrastructure SBU reflects significant LNG transaction margins in 2022, lower margins in Chile, and the sale of a minority interest in our Southland combined cycle assets. These drivers were partially offset by the higher revenues recognized from the accelerated monetization of the PPA at our Warrior Run coal plant. Finally, at our new energy technologies SBU, higher adjusted EBITDA reflects improved results at Fluence, which achieves positive adjusted EBITDA in their fiscal fourth quarter of 2023. Fluence also guided to positive adjusted EBITDA for their full fiscal year 2024. Now let's turn to how we allocated our capital last year on slide 20. Beginning on the left-hand side, Sources reflect $3 billion of total discretionary cash. This includes parent-free cash flow of just over $1 billion, which increased nearly 11% from the prior year to just above the top end of our guidance. We also significantly surpassed our asset sale target with $750 million in net asset sales proceeds to the AES parent after subsidiary level debt repayment, reinvestment, and taxes. And we issued $900 million of parent debt in May of last year. Moving to Uses on the right-hand side, we invested more than $2.1 billion in growth at our subsidiary, of which approximately two-thirds was in the U.S. We also allocated more than $500 million of discretionary cash to our dividends. Overall, I'm extremely pleased with our financial performance throughout 2023. Now let's turn to our guidance and expectations, beginning on slide 21. Today, we're initiating 2024 adjusted EBITDA with tax attributes guidance of $3.6 billion to $4 billion, driven by over $500 million in contributions from new renewables projects and from rate-based growth at our U.S. utilities. We have also incorporated a $200 million partially offsetting impact from asset sales we either closed in 2023 or plan to close this year. Excluding the $1 billion in tax attributes we expect to recognize in 2024, adjusted EBITDA is expected to be $2.6 billion to $2.9 billion. The increase in tax attributes versus the prior year is partially due to our continued use of tax credit transfers, which results in earlier recognition of tax credit than typical tax equity structures. In addition, last year's increase in new project completions will drive higher tax attribute recognition in 2024. As a reminder, we will recognize approximately one-third of tax attributes generated on 2023 projects in the 2024 fiscal year. Looking beyond this year, our head start on asset sales gives us greater visibility toward our longer-term growth and puts downward pressure on our capital budget. We expect EBITDA to increase each year through the remainder of our long-term guidance period. Turning to slide 22, we expect 2024 adjusted EPS of $1.87 to $1.97, which represents a 9% increase year-over-year and puts us on track to achieve our 7% to 9% long-term growth target through 2025. Growth will be primarily driven by our renewables and utilities businesses and will be partially offset by higher parent interest. We also expect an 8% headwind from asset sales. Our construction program this year is more evenly spread than in recent years. As a result, we expect approximately 40% of our earnings to be recognized in the first half of the year and 60% in the second half. And we will have greater visibility throughout the year into our expected construction completion. Turning to slide 23, as Andres mentioned, our very strong market position in providing tailored solutions to corporate clients, including large data centers, has allowed us to realize higher returns on our renewable’s projects. In addition, as our renewables business continues to scale, we anticipate further realization of productivity and scale benefits. Based on these factors and our 2023 results, we now expect AES's U.S. renewables returns to be in the 12% to 15% range. These higher returns in the U.S., along with productivity benefits, are directly accreted to our earnings and cash flow, and as a result, we are increasing our expected long-term adjusted EBITDA growth rate to 5% to 7% and our long-term adjusted EPS growth rate to 7% to 9% through 2027 off of base of our 2023 guidance midpoint. Now, turning to our 2024 parent capital allocation plan on slide 24, beginning with approximately $3.1 billion of Sources on the left-hand side. Parent free cash flow for 2024 is expected to be around $1.05 billion to $1.15 billion. We expect to generate $900 million to $1.1 billion of net asset sale proceeds this year. By the end of this year, we expect to be more than halfway toward the $3.5 billion gross asset sales target we announced on our third quarter earnings call. Although we expect an increase of approximately $1 billion of parent debt this year, our business is well insulated from changes in interest rates. Our new projects are funded primarily with fixed rate or long-term hedged self-amortizing debt with tenors similar to the length of our PPAs, and more than 80% of our outstanding debt is non-recourse to AES Corp. Our exposure from floating rates and future issuances is managed with nearly $8 billion in outstanding hedging. Looking at the impact of a 100 basis point shift in rates on our future issuances, refinancing’s and outstanding U.S. floating rate debt, we have only one penny of EPS exposure from interest rates in 2024. Now to the Uses on the right-hand side. We plan to invest approximately $2.6 billion in new growth, of which about 85% will be allocated to growing our renewables portfolio and utility rate base. More than 90% of this will be directed into the U.S., with the remainder going to growth projects in Chile and Panama. We expect to allocate approximately $500 million to our shareholder dividend, which reflects the previously announced 4% increase. Turning to slide 25, our long-term sources of parent capital through 2027 reflect the accelerated asset sales target we introduced on our third quarter call. We also expect higher organic cash generation as a result of our increased long-term growth rates. As a reminder, we will not issue any new equity until 2026 at the earliest, and we'll only do so in a way that creates value on a per share basis. Now to slide 26. Uses through 2027 reflect more than $7 billion of investment in our subsidiaries, primarily to grow our renewables and utilities businesses. We also expect to allocate more than $2 billion to our dividend. Given our surplus of attractive investment opportunities and our desire to minimize equity issuance as a source of capital, we now expect to grow our dividend at 2% to 3% annually beyond 2024. We believe this provides an optimal balance between an already attractive dividend yield and strong earnings and cash flow growth throughout our planned period. In summary, 2023 was an extraordinary year for AES. We demonstrated our ability to adapt to the current market and execute on our growth commitments while we further advanced our competitive position. As we continue to perfect and scale our renewables machine, we expect to have another record year in 2024 and to deliver on our now higher long-term growth target. We have positioned AES to achieve our strategic priorities and grow our business in a way that's highly value accretive to our shareholders. With that, I'll turn the call back over to Andres.

Operator:

Thank you. [Operator Instructions] Our first question comes from Nick Campanella with Barclays. Your line is open. Please go ahead.

Steve Coughlin:

Yes. Hey, Nick. It's Steve. That's right. It's primarily because we're ahead on the asset sale target significantly from 2023. We had the $1.1 billion versus the $400 to $600 guidance. That's why the asset sale drag, as there's a lag to when we redeploy the capital and it's yielding again, is about $200 this year. A little higher than what we would have anticipated a year ago. Overall, good news for the [Technical Difficulty] but it is offsetting the growth that's coming from the rate base and utilities in the renewables projects. That's right.

Steve Coughlin:

Yes. Definitely. The investment grade is a top priority. We designed the plan to meet the investment grade targets that we have. We built cushion into the metrics themselves, but also keep in mind that the quality and the duration of the cash flows in the business is transitioning dramatically. We're going to a much longer duration, average duration of contracts, more than -- is 20-year contracts. This is Clean Energy, no carbon risk. These are U.S. dollar contracts with large corporates, many of which are data center customers, big tech companies, very high-quality credit. It's both the solid credit metrics as well as the quality and profile of the cash flows that's evolving. We don't count on that when sizing the new debt. We count on the metrics, but the quality is improving as well. In terms of levers, the asset sale target is, as it's always been, has multiple ways that it can be achieved. There's some conservatism built in over the total. We have fully anticipated any temporal dilutive impacts in the numbers that we've given, as I said, but there is some flex there as needed. On the debt side, the investment grade is a top priority.

Operator:

We now turn to David Arcaro with Morgan Stanley. Your line is open. Please go ahead.

Andres Gluski:

David, I'd say it's a combination of things. First and foremost is the returns that we are [Technical Difficulty] on prior PPAs that we signed. So that's the first. We are seeing that we're getting higher returns. Second, what is driving these higher returns? You may recall for some time, maybe like three years ago, starting three, four years ago, I started saying that in select markets, there would be really a shortage of good renewable projects. These are markets like California, like PJM, New York. What we started to do was position ourselves and actually enter the queue, buy land rights, etcetera, to have projects to be able to fulfill this. I think that part of it is in these select markets, you are starting to see the shortage of renewables that we had been seeing. I think this is something that will spread market to market. It's not going to be true for all markets. Out West, there's a lot of land. There's not that much demand, but in select markets, you will be seeing that. I think that's also part of the result is that we are positioned in the right markets. The third thing I would say is that we're becoming more efficient in our construction and in our development process. Stay tuned. I think that will continue to improve. Realize that 2021, you had a lot of supply chain disruptions. Those are well past us and we're really getting to optimize that. Based on our greater efficiency, what we're seeing is that we are getting higher returns. We've also positioned ourselves, this is about our fourth year, fifth year of really positioning ourselves with large corporate customers. Those corporate customers have very strong demand growing very quickly. If you ask me from a sector point of view, I think the real question is, can we meet the demand that they have for Clean Energy in all of these markets? By the way, I would add Chile is a similar market to California where there's a real shortage of projects. There's a very strong demand from our customers and that we're very well placed. This is not like a catalyst. We had several pieces which are played out as we expected them to play out.

David Arcaro:

Okay, thanks. That's good to hear. Then in terms of the higher growth rates that you've outlined today, wondering if we could just unpack that a little bit. Is that all coming from the renewables segment in terms of the higher returns that you're seeing or is the utilities business or energy infrastructure also experiencing higher EBITDA growth outlooks here?

David Arcaro:

Okay, great. Thanks so much.

Operator:

Our next question comes from Julian Dumoulin-Smith with Bank of America. Your line is open. Please go ahead.

Steve Coughlin:

Yes. So, I would say, I think the mix roughly be maybe a little bit more on the renewable side, we're seeing the higher returns. So maybe that's above the 45 50-ish. So, it's going to be higher on the renewables. I think the utilities, as Andres said, will be a little bit more of a share. On the energy infrastructure, we did communicate that, that was going to shrink as we execute on the coal exit plan. Although for just a handful of assets, we extended that to 2027. So that dilution from those coal exits, this is the smaller portion, will be spread out over more time, which overall, I think, is a good thing in terms of the -- in the financials as well. So a little more renewables, a little more utilities and then the energy infrastructure is shrinking a little bit less, but it's still in that same range.

Andres Gluski:

Let me sort of give a big picture, and then I'll pass it off to Steve. Look, what we're going after, really, as I said in my script, is really going after those projects, which provide the best financial benefits. You've known me for a while, I've never gone for growth for growth's sake. So really, what we want to do is maximize shareholder value on a per share basis. So really, this is an upgrading of the quality of the growth, more than a greater numeric growth. Now I do think that it's very important to understand sort of what market segments we're in. We're in the corporate segment, but we're also very heavily into the data center segment. And this is something, again, we've been working on for many years. We have really very good relationships with key clients, and that is a demand that's growing very quickly. And certainly, that we don't mention in our speech, quite frankly, because it's very early times. But we're really going to go after artificial intelligence as an efficiency improvement in the company. And we have a big kickoff meeting that we're going to have in the next couple of months. But this is something I think we've taken in a very sort of strategic line. Inderpal Bhandari, who was the global Chief Data Officer for IBM until 2023 has just joined our Board, and somebody who is very knowledgeable in the area. We also have Janet Davidson, who's also a PhD in computer science. It's interesting. I mean, right now, with Inderpal, we have 5 PhDs on our Board, which has got to be one of the highest percentages in things that run from computer science to finance to economics of business. So that's what I wanted to put it in. What we're pursuing is returns, we're pursuing value per share. And I think we've been very systematic now for many years in positioning ourselves in a given sector and learning about and preparing ourselves for the new technologies which are coming. So, there's a lot of buzzwords of AI. Well, what's behind this is 5, 6 years of getting ourselves in a position to really utilize the data and have the understanding of the company. So, with that, I'll pass it off to Steve to answer the other parts of your question.

Cameron Lochridge:

Got it. Awesome, guys. Thank you very much.

Operator:

Our next question comes from Durgesh Chopra with Evercore ISI. Your line is open. Please go ahead.

Andres Gluski:

Yes. Hi, Durgesh. That's a good question. Look, 2023 was a dramatic year where we increased construction, 100%. And we've been saying, look, we're not going to grow it at 100% per year. Now we've been signing over 5 gigawatts a year of new PPAs. So eventually, these two have to somewhat converge. I mean, at some point, we have to be cutting the ribbon on around 5 gigawatts. But that's not going to happen likely next year, just because of the timing of some of the projects. We also have a developing transfer project as well, and that's not part of our backlog, but it's part of the signing. So that also is part of the reason for that. So -- this is not a signal of anything. It just has to be the particular timing of the projects that we have. And again, we feel this year, very good about commissioning them all on time and on budget. We have 100% of the major equipment already secured and 80% of it is on site, which is we've never been that good this early in the process. And I think another thing important that Steve said, this is going to be reflected in our earnings profile, whereas we were very back-end loaded last year because of this very rapid growth. As growth enters a more steady state, we're going to have 40% of our earnings in the first half and only 60% in the second half. So, this is something we also worked very hard to achieve. So qualitatively, we feel [Technical Difficulty] here is 2024, 2025, you're going to have a catch up to the amount of PPAs that we're signing.

Steve Coughlin:

Yes, I had no problem to guess. So we had a solid year end on the credit metrics. So our thresholds are at 20% FFO to debt and we were roughly at 22% approximately. We do keep atleast a very strong cushion that’s very healthy. And going forward that ratio is actually improving over time in our plan. So for the end of 2024 I would expect it to be at least at 22 if not a little bit higher that. So the leverage of the company overall, we do get a lot of questions about it, but it is important to keep in mind we have a recourse, not recourse structure. And particularly in the non-recourse debt this is amortizing debt. I think not everyone is doing it that way and so our project debt is really amortizing and it serves by the cash flows from the projects. The parent debt level is actually going to be, it will come up a little bit over the planned period, but not a lot. So, it's $4.5 billion now. And as I said in my comments on the slides, maybe another 1 to 1.5 over the 4-year period, but it's going to be pretty stable.

Steve Coughlin:

Thank you.

Angie Storozynski:

Thank you. So I was just wondering, are you guys seeing any degradation in either EBITDA or cash flow generation of existing assets? I mean, we're seeing examples of -- especially on the wind side -- that wind assets are having some issues with both OpEx and CapEx, hence re-powerings. But just wondering if there's obviously this positive momentum on the new build side, but is there any offset from existing assets?

Angie Storozynski:

Okay. And then the second question. So I remember in the past, you were mentioning that the slightly delayed coal plant retirements could be a lever for actually both earnings and cash flow. So is there an update there?

Andres Gluski:

Yes. And I'd like to add that we still plan to be out of coal by the end of 2027, and that we -- after 2025, we'll have somewhere about 1 gigawatt plant. And part of this is driven by the fact that these plants are still needed to for stability of the system, so we are not allowed to shut them down in part. I just wanted to clarify. So the strategic objective remains the same, it's just slightly delayed in time.

Andres Gluski:

Well, I think, look, a rising tide lifts all boats. So I don't think this is a situation where there's just going to be like one technology that solves all the needs. So I don't see that any future where there's not, quite frankly, a shortage of renewable projects in the key markets. I know it takes a long time to permit nuclear plants. To my knowledge, excuse me, no new nuclear plants have been built, maybe even in the last decade, anywhere near budget. So on the one hand, I do think nuclear is part of the long-run solution, because I do agree. There's only so much land, so much interconnection. On the other hand, I think that the nuclear renaissance has yet to prove itself and it has yet to build out. So the demand from these clients is so strong. I mean, they are taking second best. Sometimes they can't get -- they want to require additionality because they really want to be part of the solution to climate change. Well, there are circumstances where they will take no additional audit and basically have recontract nuclear power today, at least 0 carbon. But the truth is that squeezing the balloon. That's taking 0 carbon energy off the grid. So I don't think -- I'll put it this way, I feel it's extraordinarily unlikely that the growth in renewables will stop and be replaced with nuclear power. And it's certainly in the next 5 years, I don't see it, and I see it very difficult in the next 10 years.

Andres Gluski:

Thank you.

Ryan Levine:

Good morning. Given the scarcity of data center projects, how are returns for these projects compared to the projects for other customers?

Ryan Levine:

Okay. And then how did you arrive at the 2% to 3% long-term dividend growth is the right growth rate from a financial policy standpoint? And what are factors that could cause that policy to continue to evolve?

Ryan Levine:

Okay. And why start that in 2025 as opposed to another year from a timing standpoint?

Ryan Levine:

Thank you.

Operator:

Our final question today comes from Gregg Orrill with UBS. Your line is open. Please go ahead.

Steve Coughlin:

Yes. So it will grow. And it's not timing so much as it's just the success of the business. As Andres said, we doubled our construction last year. And keep in mind that not all of the credits are recognized in year one in tax equity structures. It's roughly 1/3 get recognized in the second year. So that's boosting the credit this year as well as all of the projects that will come online this year, the new projects on top of that. The other thing that's driving it is the transfer of credit does get recognized earlier, essentially almost all in the first year. And so there's a greater mix of credits transferred in this vintage this year as we -- that grows as a component of how we monetize the credits. So that's driving it higher. But I don't expect this to have dipped, I think it will continue to rise as we head into the years ahead, as the growth program continues. And then keep in mind that we are benefiting from the energy community adder and a significant portion, which increases the credit. And our wind projects are all qualifying for domestic content also going forward. So that all else being equal, is driving the credit value up. And what's important for everyone to understand is the credit is cash and earnings. And the great thing about these -- particularly the investment credits, which is the lion's share of our mix of tax attributes is upfront. So you're getting a return on your capital investment of a significant portion, at least 30%, in some cases, up to 50% right away, which is a fantastic cash profile as well as an earnings profile.

Operator:

This concludes our Q&A. I'll now hand back to Susan Harcourt, Vice President of Investor Relations, for final remarks.

Operator:

Ladies and gentlemen, today's call has now concluded. We'd like to thank you for your participation. You may now disconnect your lines.

Susan Harcourt:

Thank you, operator. Good morning, and welcome to our third quarter 2023 financial review call. Our press release, presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Stephen Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our third quarter results, our 2023 guidance, how we are flexing our plans to adapt to current financial market conditions and how we minimize our exposure to interest rates. Turning to our financial results for the quarter, beginning on Slide 10. I'm pleased to share that we had a strong third quarter and are fully on track to achieve our full year guidance. Adjusted EBITDA with tax attributes was just over $1 billion versus $991 million last year, driven primarily by higher contributions at our Renewables SBU, the recovery of prior year's purchase power costs at AES Ohio included as part of the ESP4 settlement and improved results at Fluence. These drivers were partially offset by the absence of the significant LNG transaction margins, which we earned last year. Tax attributes earned by our U.S. renewables projects this quarter were $18 million versus $60 million a year ago, in-line with our expectations of a higher share of renewable projects coming online in the fourth quarter. Turning to Slide 11. Adjusted EPS was $0.60 versus $0.63 last year. In addition to the drivers of adjusted EBITDA, we saw higher parent interest expense this quarter as well as a higher adjusted tax rate. I'll cover the performance of our strategic business units or SBUs in more detail over the next few slides, beginning on Slide 12. In the Renewables SBU, we saw higher adjusted EBITDA with tax attributes, driven primarily by higher contributions from new projects brought online in the last 12 months, as well as higher margins in Colombia. This was partially offset by lower tax credit recognition as a result of fewer new projects placed into service this quarter versus a year ago. Our business continues to make strong progress, not just with construction, but also the financing of new projects. We continue to see a robust market for tax credits. This year, we have already raised $1.8 billion in tax capital financing. The market for tax attributes is also greatly expanding as a result of the tax credit transfer option that has brought many more participants to the market. Importantly, tax credit transfers get recognized in operating and free cash flow, which further enhances our financial funding flexibility. Going forward, we will increasingly use tax credit transfers as a means to monetize tax credits including for nearly 500 megawatts of projects in 2023. At our Utilities SBU, higher adjusted PTC was driven by the recovery of prior year's purchase power costs at AES Ohio included as part of the ESP4 settlement, which have been recognized as an expense in the third quarter of last year. I'd now like to take a moment to discuss the continued progress of our utility growth program on Slide 14. In August, we received commission approval at AES Ohio for our new Electric Security Plan, or ESP4, which includes timely recovery of $500 million of grid modernization investments at a 10% return on equity, allowing us to further improve the quality of service. As a reminder, we plan to grow the combined rate bases of our U.S. utilities at a 10% average annual rate through 2027. 80% of our planned investments through 2027 are either already approved or under FERC formula rate programs. We are executing on this plan and with our investment programs across the two utilities, we are on track to increase our capital expenditures by over 35% year-over-year as we work to modernize and invest in system reliability. As we previously discussed, our utilities in Ohio and Indiana continue to charge the lowest residential rates of all electric utilities in both states. Turning back to our third quarter results, with our Energy Infrastructure SBU on Slide 15. Lower adjusted EBITDA primarily reflects significant LNG transaction margins in the prior year, partially offset by prior year onetime expenses in Argentina and higher revenues recognized from the monetization of the PPA at our Warrior Run coal plant. Finally, at our New Energy Technologies SBU, higher adjusted EBITDA reflects continued improved results at Fluence. Fluence has continued to demonstrate improving margins and strong pipeline growth, and they have indicated their expectation to be close to adjusted EBITDA breakeven in the fourth quarter of their 2023 fiscal year. This year-over-year improvement would be reflected in our own fourth quarter results. Turning to Slide 17. I'm very pleased to highlight that we now expect to achieve the top half of both our 2023 adjusted EPS guidance range of $1.65 to $1.75 and our parent free cash flow range of $950 million to $1 billion. This reflects the strong performance of our renewables construction team whose excellent execution this year means that we expect to exceed our construction target of 3.4 gigawatts by at least 100 megawatts. Now to Slide 18. We are reaffirming our full year 2023 adjusted EBITDA guidance range of $2.6 billion to $2.9 billion. Including the $500 million to $560 million of tax attributes we expect to realize in 2023, we expect adjusted EBITDA with tax attributes of $3.1 billion to $3.5 billion. The additional U.S. projects we expect to bring online this year should allow us to exceed the midpoint of the tax attributes estimate we provided at Investor Day. Now to our 2023 parent capital allocation plan on Slide 19. Sources reflect approximately $2.4 billion of total discretionary cash, including $1 billion of parent free cash flow, $400 million to $600 million of asset sales, and the $900 million parent debt issuance we completed in Q2. With the agreement to sell down a minority interest in our gas and LNG business in the Dominican Republic and Panama, we have secured the entirety of our external sources of parent level capital for 2023. Turning to Slide 20. Since our Investor Day in May, financial market conditions have changed, and AES will flex its near-term and long-term plans accordingly. Looking ahead, we will continue to prioritize our strong credit profile and investment-grade ratings, hitting our financial metric growth targets, funding our growth primarily in U.S. renewables and U.S. utilities and advancing on our decarbonization and portfolio simplification goals. We have a number of levers to adjust that will keep us on track with these objectives. First, and to be clear, we will not issue equity at or near current share price levels and not until it is value accretive to our shareholders on a per share basis. As such, we are increasing our asset sale target to at least $3.5 billion for the 2023 to 2027 timeframe and accelerating our plan to achieve $2 billion of asset sale proceeds in 2024 and 2025. With this change, we will not issue any equity until at least 2026, and the amount anticipated has been reduced to $500 million to $1 billion through our guidance period. Second, the tax credit transferability option that we now have creates added flexibility to monetize the tax value of our U.S. renewables projects with a broader base of market participants while also increasing free cash flow and the capacity to fund growth. Third, while we still intend to exit all of our coal businesses in a few of our markets, our coal assets will be temporarily needed to support the energy transition beyond 2025 as renewable deployments and transmission have not progressed as quickly as required. We still intend to exit the majority of our remaining coal businesses by the end of 2025. However, we have the flexibility to delay the exit of a few select plants through 2027 to support continued electricity reliability. This delay would yield continued financial contributions from these assets during this period. For 2024 and 2025, we expect to fund our remaining parent capital needs entirely with asset sales and planned debt issuances. We feel confident that we can achieve the $2 billion asset sale target in these years, as we have already held discussions for a large portion of the assets in this program. We anticipate competitive processes that will yield attractive valuations with minimal dilution to earnings and cash beyond what had been incorporated in our plan. Our sales program is designed to meet our strategic objectives to simplify and decarbonize our portfolio while funding our core growth investments in U.S. renewables and utilities. Finally, turning to Slide 21, we are largely hedged against future increases in interest rates. Looking at the parent company, our long-term debt is entirely fixed and we hedge our exposure to refinancing risk over a five-year window. Our nearest maturities in 2025 and 2026 were previously hedged at a rate of approximately 3%. Approximately 80% of our consolidated debt is at the subsidiary or project level and is non-recourse to the parent. We typically pre-hedge future project debt issuance for the full tenor when we sign a PPA, insulating our expected returns from future rate movements. The amortizing structure of our project debt rather than bullet maturities allow the project to support higher leverage. As we grow, our long-term debt balances will increase proportionally to the underlying cash flow of our businesses, enabling us to maintain steady leverage ratios and investment-grade credit metrics. At the end of the third quarter, we had approximately $6 billion of interest rate hedges outstanding at an average rate of 2.9%. Looking at the impact of a 100 basis point shift in interest rates on our future issuances, refinancings and U.S. floating rate debt, we have under $0.01 of EPS exposure from interest rates in 2024 and $0.03 to $0.04 of exposure in 2025. Unhedged floating rate debt is primarily located outside the U.S. where inflation indexation in our PPAs provides a natural hedge against rising rates. In summary, as we approach year-end, we've made excellent progress on achieving our financial and strategic objectives for 2023. Our balance sheet is strong, and we are flexing to adapt to current financial market conditions. With line of sight to our future growth funding needs, we will create value from our excellent market position while continuing to prioritize maintaining investment-grade credit metrics and achieving our financial commitments. With that, I'll turn the call back over to Andres.

Operator:

Thank you. [Operator Instructions] The first question will be from the line of David Arcaro with Morgan Stanley. Your line is now open.

Andres Gluski:

What we're seeing is very strong demand from our target customers. So we have not seen a weakening. And as we said, it's -- I think it's very important to distinguish what markets you're operating in. So markets like California and New York, PJM, there is very strong demand. And there's very strong demand from corporations, especially from the tech companies in the data center business. So we have not seen a slowing down. Now, if you're talking about WEC and auctions for public utilities, et cetera, we're seeing a lot more competition for those projects. But for the -- our target customers in our target markets, we're seeing demand very firm.

Andres Gluski:

Okay. So I think that's sort of two parts of the question. So a lot of the asset sales are selling out or selling down a specific businesses as we have been doing for the past decade. Our businesses continue to perform very well. So we see that there is interest in these businesses, because it's not -- again, not all businesses are created equal and we have very favorable positions in these markets. We're also seeing great interest for people to partner with us. And that also includes our existing partners for greater participation. So those are things which decrease the equity needs over the next four, five years. So I think that's very important to see that we're balancing both. I think the question regarding the sell-down of renewable projects, I'll pass over to Steve, so he can give you an update on that.

Operator:

The next question will be from the line of Durgesh Chopra with Evercore ISI. Your line is now open.

Steve Coughlin:

Yes. So a portion of it, Durgesh, so we did guide to 100 megawatts over at least this year, so the 3.4 to 3.5. So just a portion of that $0.10 is included. And the good thing is we have a very clear line of sight at this point to that increase as mechanical completion has been achieved on 93% of the new capacity. That means everything is all built out. We're just in final synchronization of equipment and systems. And so, we feel very confident in the year-end number. That which does not come online this year of that upside will be in the first half of next year.

Steve Coughlin:

Yes. So one thing I would point out is that the credit metrics do fluctuate some during the year as we have higher construction balances in the middle of the year. We also have a higher level on our corporate revolver as projects come online towards the end of the year, paying down construction balances, and then we have the corporate revolver used to manage timing and distributions from our subsidiaries. The other thing to keep in mind is that we are in a high-growth mode. So at any point in time, we do have construction debt that's not yet yielding and that's all non-recourse. And it's also used to finance the tax credit value as well. So there's very quick paydowns on that debt once these projects come online. But no, we feel -- we're in regular contact with all the rating agencies. We feel very good about exceeding -- not just meeting but exceeding the thresholds. The other thing to keep in mind is that our leverage is amortizing. So most of our project level debt is amortizing over the PPA period. So this is a very low risk structure. It's non-recourse and it's not subject to significant bullets and it allows us to maintain a leverage ratio that will grow just proportionately -- our debt will only grow proportionately to the cash flows of the business.

Steve Coughlin:

Yes, absolutely. This is a top priority metric in all of our planning. So maintaining investment credit is at the top. And so as we look at the asset sales -- keep in mind, we already had a significant amount, $2.7 billion to $3 billion considered in our Investor Day numbers. And we are prioritizing assets that both hit our strategy, but as well are minimally dilutive on earnings, cash and credit. So I'm very confident that we will not impact our credit metrics negatively with the plans that we have.

Andres Gluski:

At this point in time, I would say that we feel that we will sell at least $3.5 billion through end of 2027, but a lot of these, again, are partial sell-down, sell-down of renewables, our plan to exit from coal. So if you look in the past, we've done a multiple of this number. I'd also point out that I'm not aware of any time that we have set a target for asset sales and not achieved it or exceeded it. So we feel very confident in achieving those asset sale numbers.

Angie Storozynski:

Okay. So first, I wanted to -- you mentioned about -- you mentioned transferability of tax credits. I just wanted to make sure that were not in a sense window dressing and trying to solve for a certain credit metrics, but this is actually driven by economics. So when I look back to your Analyst Day, you financed your renewables in the U.S., 40% tax equity, 40% project level debt and then 20% equity. So I just wanted to make sure that, that structure is still in and we're not trying to basically boost credit metrics by levering these projects more? And again, just explain to me that why we're moving from the traditional credit -- tax equity structures, which allowed you to monetize accelerated depreciation, among others to the transferability?

Angie Storozynski:

Okay. So that's treatment so that the FFO uplift under those structures, you already considered that when you quantified your equity needs during the Analyst Day?

Angie Storozynski:

Okay. But again, it's -- you're still sticking with solar ITCs. Again, that financing structure that I mentioned at the beginning, doesn't change, right? So you're not increasing leverage of the project, okay.

Angie Storozynski:

Okay. And then secondly, you mentioned the attractiveness of renewables versus other sources of power based on the levelized cost of electricity, so i.e., new-builds for renewables versus new-builds for thermal assets. But -- and not everywhere, do you have to actually add incremental generation sources, right? And then the pushback that we are hearing is that the PPA prices have now slightly exceeded forward power prices, be it on peak for solar or around the clock for wind. So again, I understand the distinction with tech clients, but how about any other locations and any other off-takers for new renewables?

Angie Storozynski:

Okay. And then the last question about the -- some flexibility on the retirement of the coal plants. I understand the reliability needs of local grids, et cetera. But this is not your renewables coming online later than expected. It's just more of the market backdrop in which the coal plants operate. Is that correct?

Operator:

The next question will be from the line of Richard Sunderland with JPMorgan. Your line is now open.

Andres Gluski:

Yes. It's a good question. I would think that, again, it's over a two-year period, but I would expect some important announcements in the first half of next year. And again, we tend to announce things when they're very firm. So the negotiations, et cetera, are ongoing. It's several assets. But yes, I would expect to be able to say something in the first half of next year.

Andres Gluski:

What I'd say is, yes, I really can't comment on that. I would say stay tuned, and we will make announcements in that regard. But it's mostly assets that we have designated as noncore over time. So it's more of an acceleration or perhaps a deepening of some of the sell-downs.

Andres Gluski:

Well, what I'd say is see what we've done in the past. So for example, if you look at when we made a big move into renewable energy, we -- our first big acquisition was sPower and we brought in a new partner and that relationship has evolved over time. So we're in a number of fields, which are very attractive right now. So I think it's an interesting time to see what our partners want to do or if some additional partners want to come in. But we're really sitting in a privileged position, especially for a lot of the new growing fields.

Julien Dumoulin-Smith:

First question here, I'm going to take it and play in every direction. All right, deal. $3.5 billion here. You talk about coal exits of selective assets in '27. To me, I hear that, and I'm asking well, how much does that delay some of the loss of contribution in the plan out to '28, i.e., the earlier targets that you gave through '27 contemplated full divestment of these assets. Now I get that you're raising the asset divestment target. So in theory, there's going to be fewer assets at the end. So in theory, you should be sacrificing some of the net income to the plan. But obviously, by selling some of the coal assets in '27, you're delaying or deferring some of the chunkiest lowest multiple assets potentially and the loss of the contribution into '28. I just want to like kind of hear how you think about that '27 versus '28, are you effectively pushing out a little bit of an earnings impact from '27 into '28 if you think about it or from '25 into '28?

Julien Dumoulin-Smith:

No. Look, I get it. It makes sense. And just to clarify, the select assets, though, those are the ones that the PPAs are expiring or the -- otherwise been regulatory issues, right? Again, I think that's a nice catch all, right? If that's the way you're framing it, one or the other?

Julien Dumoulin-Smith:

Right. Yes, indeed, right. There's a couple of them that stand out, if you will, that would seem to fit that right?

Julien Dumoulin-Smith:

I know you don't want to be too specific [indiscernible]. I'm sorry, I'm trying to be less specific here. Quickly, if I can pivot here real quickly. Yes, go for it.

Andres Gluski:

Yes. as I said, it's a small part of the 3 that's remaining.

Andres Gluski:

We can't call for much that we haven't said already. I mean what we've said is that we are really as an accelerator of new technologies. We create a lot of applications together. They help us. That's why we're the leader, I think, in the premium markets. But over time, we will monetize the positions. It's not just Fluence. We have other investments as well. And those new technologies have progressed very well. So we have other companies besides Fluence. But I'm not -- we really can't provide any further color on that.

Andres Gluski:

Sure. I mean -- there are different ones of levels of maturity. But of course, you have Uplight, which is, I think, proceeding well and incorporating more product offerings and becoming part of Schneider Electric's energy efficiency offerings. But then we have other ones that are in earlier stages. And whether they will create a lot of value outside of what they create for us. So certainly, one of the more exciting ones is the building of solar farms with robotics, I think, has a lot of promise. If you look at a longer term sort of four years out there, I would expect a lot from that. There's a lot -- we're doing a lot with AI operationally for us. I mean today, we use AI on the operations of our wind farms of next-day predictions for energy demand and weather. We're also using -- Fluence is using on its bidding engines, but there's much, much more. We have collaborated with some of the technology companies on things like grid visualization, et cetera, which I think will become part and parcel of how ISOs manage their build-outs and dispatches and reaction to natural catastrophes. And we do have a -- we would receive part of the royalties from the sales of the technology companies because we co-created them with them. So these are all things that are not in our numbers, but I think we'll we will be able increasingly to have significant cost savings and greater efficiencies from applying them. And in some cases, we'll be able to monetize these over time at the right time when market conditions are right.

Andres Gluski:

Look, we -- I think you have to -- when you think about what we're doing is we're making -- creating the most value of the different assets we have. So we did our first sale of -- in the pipeline, if you will, with the DTA, where we actually don't build the project, but we sell a development project because we felt that, that was the greatest creation of value. So sometimes from our pipeline, we may be doing this because that's the best use of that pipeline. As I said in the past, probably the most attractive thing for us to do is to acquire late-stage development projects when -- especially when we have a premium customer who needs that energy. And why? Well, because -- well, you have a development project, it's some cost if you have to invest to create that development project. And so you don't know what is the conversion rate of your pipeline. So if you have something that's in late stage your conversion rate is basically one if you have the client. So it's a very good risk-adjusted rate of return. So we're going to be doing all those things. In the case of one of our utilities, they're buying one of the projects that have been developed by somebody else. We're selling one from the pipeline. Others are going to be repowering. So, we'll use all of the means at our disposal to create shareholder value. So I don't think it's -- the way to think about this correctly, is just pipeline, greenfield through final delivery is the best way to create value. I think it's really -- the most important really is having the right projects in the right markets and the right clients and thinking about how can you best satisfy what the clients' needs are. So I just mentioned that we can talk about it off-line. But quite frankly, what we're seeing is that all things being equal, acquiring late-stage projects, and it is a buyer's market now. It is one of the most attractive businesses for us.

Michael Sullivan:

I wanted to start with, can we just confirm if there's been any change to your levered returns targets in the current environment up or down? And then maybe also just you alluded to it a little bit, but just a sense of like how much LCOEs or PPA pricing on new projects have changed?

Steve Coughlin:

Yes. So I would say, generally in the States with our corporate clients, in particular, where we're doing structured products, we are seeing the higher end of that return range. And also, it's important, while PPA prices have been increasing, over the past one to two years, they've actually leveled off and are starting to come back down. We've seen significant reductions in solar module pricing this year. We've seen significant reductions in the commodities going into batteries and battery pricing coming down. So we're starting to see levelized costs come back down, which is also supporting the activity and the demand going forward. So I think we're in kind of past the difficulties of the supply chain past the impacts of the inflation and back to a declining curve in the key technologies we're using.

Michael Sullivan:

Okay. One quick last one. Just -- can you give any thoughts on just the initial intervenor testimony in the Indiana rate case and what the path looks like from here to whether it be settlement or final order?

Operator:

Thank you. That concludes today's Q&A session, and I will turn the call back over to Susan for final remarks.

Operator:

That concludes today's conference call. Thank you all for your participation, and you may now disconnect your lines.

Susan Harcourt:

Thank you, operator. Good morning, and welcome to our second quarter 2023 financial review call. Our press release, presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our second quarter results, 2023 parent capital allocation and 2023 guidance. Turning to our financial results for the quarter, beginning on Slide 13. I'm pleased to share that the second quarter was fully in line with our expectations, keeping us well on track to achieve our full year guidance. Adjusted EBITDA with tax attributes was $607 million versus $722 million last year, driven primarily by lower margins at AES Andes and higher costs at our renewables SBU due to an accelerated growth plan, but partially offset by new renewables coming online and higher availability at select thermal businesses. Tax attributes earned by our U.S. renewables projects were relatively flat at $38 million in the second quarter of this year, in line with our expectations. Turning to Slide 14. Adjusted EPS was $0.21 versus $0.34 last year. In addition to the drivers of adjusted EBITDA, we saw higher parent interest expense this quarter. As a reminder, our year-to-date EPS is fully in line with the breakdown that we outlined earlier this year, in which we noted that roughly 25% of our earnings would come in the first half of the year and 75% in the second half. I'll cover the performance of our strategic business units or SBUs in more detail over the next 4 slides, beginning on Slide 15. In the renewables SBU, we continue to execute on our strategic priority to triple our portfolio by 2027. For the second quarter, as expected, we saw higher adjusted EBITDA with tax attributes driven primarily by higher wind generation and new projects coming online, partially offset by higher business development and fixed costs due to our accelerated growth plan. At our utilities SBU, we saw higher adjusted PTC driven by lower maintenance expenses, but partially offset by higher interest expense from new debt. We continue to expect strong utilities earnings for the second half of the year driven by typical second half demand seasonality and the pending August decision on ESP 4 at AES, Ohio. With this pending decision and the great progress in renewables growth at AES Indiana, we are continuing to pursue our strategic priority to increase rate base by an average of 10% annually through 2027. Lower adjusted EBITDA at our energy infrastructure SBU, primarily reflects lower margins at AES Andes in line with our phase out of coal, partially offset by higher availability at select thermal units. As we execute -- our third strategic priority to exit coal and complete the transformation of our portfolio, although not every quarter, we generally expect to see annual year-over-year declines in energy infrastructure as we discussed at Investor Day in May. Finally, at our new energy technologies SBU, higher adjusted EBITDA reflects continued improved profit margins at Fluence. Fluence has shown year-over-year improvement for 3 straight quarters, and we are very pleased with the strong results they are delivering this year. Now to Slide 19. We are on track to achieve our full year 2023 adjusted EBITDA guidance range of $2.6 billion to $2.9 billion. Growth in the year to go will be primarily driven by contributions from new businesses including growth at our U.S. utilities and contributions from new renewables projects coming online. As a reminder, the 3.4 gigawatts of new renewables we expect to add this year represents an increase of over 75% compared to the 1.9 gigawatts we added to our portfolio last year. This amount also represents a doubling of new renewables in the U.S. versus 2022. This growth will be offset by approximately $200 million of LNG sales we've recorded primarily in the third quarter last year, which we do not expect to recur this year. In addition to our adjusted EBITDA, we expect to realize $500 million to $560 million of tax attributes in 2023, bringing our total adjusted EBITDA plus tax attributes to $3.1 billion to $3.5 billion for the year. Turning to Slide 20. We are also reaffirming our full year 2023 adjusted EPS guidance range of $1.65 to $1.75. As a reminder, we expect our adjusted EPS to be heavily fourth quarter weighted due to the late year seasonality of our U.S. renewable project commissioning. Now to our 2023 parent capital allocation plan on Slide 21. Sources reflect approximately $2.4 billion of total discretionary cash, including $1 billion of parent free cash flow, $400 million to $600 million of asset sales and a $900 million parent debt issuance we completed in Q2. For more information on our debt issuances at the parent company and our subsidiaries, please refer to the appendix of the presentation. On the right-hand side, you can see our planned use of capital remains largely in line with guidance, with higher parent investment reflecting our recent acquisition of the 2-gigawatt Belfield project in the U.S. At our Investor Day in May, we outlined our capital allocation plan through 2027, including asset sales, along with debt and potential future equity issuances. We appreciate all of the feedback we've received, and I want to take a moment to clarify that we will only raise and invest capital in a way that's value accretive to our shareholders. Any potential future equity issuances would have to yield accretive value to shareholders for us to pursue equity as a source of capital. We are also committed to improving our credit profile over time and further bolstering our investment grade rating. We have a number of other levers to pull to support our growth such as increased capital recycling through asset sales and sell-downs. Given our strong asset sales track record and recent success, it is possible that any future equity issuances could be materially lower than the 5-year figure we previously shared. As always, our Investor Relations team is happy to take additional feedback and to follow up on additional questions or data requests. In summary, we're continuing to make progress on transforming AES' portfolio while delivering strong growth in adjusted EBITDA, earnings and parent free cash flow. Our businesses are executing successfully and delivering on their commitments. We will continue to allocate our capital towards our high-growth renewables and utilities to maximize shareholder value. With that, I'll turn the call back over to Andres.

Operator:

[Operator Instructions] We will take our first question from Durgesh Chopra with Evercore ISI. Durgesh, your line is open. Please proceed.

Andres Gluski:

Sure, Durgesh. Good to talk to you. Look, we signed 5.2 gigawatts of new PPAs last year. So what we're seeing this year is we already have 2.2 signed. We have visibility into just 2 projects, which would be another about 2.4, right? Which would put us 4.4. And of course, we have other projects in the pipeline. So we're not really setting out an official target, but I'm saying that we believe that we should be similar to last year. And we do have a couple of what I call these whales, the 1 gigawatt plus targets, but we feel very good because we see a lot of demand for our products. We have people coming to us with products. So it's really looking at how do we best allocate our money where we get the highest returns and best allocate our teams.

Andres Gluski:

Sure. Look, I would say that we feel very good about our construction program. So -- versus -- this was the big challenge of this year to grow our construction program in the U.S. by 100%. We feel very good about it. Unfortunately, a lot of these are slated to be commissioned towards the latter part of the year. So we should have a good view in -- on the Q3 call of where we stand. And whether we're going to do more of these projects this year. But in general, we're very pleased with the supply chain, with our construction teams. The team has really stepped up to the task, and I'm very proud of them.

Steve Coughlin:

Yes. Look, I mean, as I said in my remarks, Durgesh, this is just a function of multiple levers. And we're seeing a lot of great progress on our asset sale program and the $3 billion that we put out at Investor Day was well below the total universe of opportunities. So -- what I wanted to point out is that we're only going to issue equity in the future, and that could be far in the future to the point that it's value accretive to shareholders, and we haven't also tapped other sources that we intend to tap, which is our asset recycling program. So as you saw with where you run, as we've seen, as we've executed on the renewable sell-downs, as we exit further coal assets, we have a lot of upside in that asset sale number. So at this point, it's indefinitely into the future and our share price would need to be substantially higher than where it is today, and it would have to be value accretive to shareholders on a per share basis.

Operator:

Our next question comes from David Arcaro from Morgan Stanley. David, your line is open. Please go ahead.

Andres Gluski:

Well, of course, the final rules haven't come out. What I would like to say is that our Felix project -- our project in Texas is -- really would meet the very strictest criteria. So it is additional. It is hourly matched. It is regional. So it has the very lowest carbon footprint technically feasible in the U.S. So I'd like to put that right out there that our project is not dependent in any way about how the rules come out. Now having said that, I do believe that additionality is important. I also believe that we have to move to early matching, in part because we need green hydrogen projects to be tradable goods. So these are the rules in Europe. I also think regionality is important, so we don't add further congestion. So really, what we want is that the new rules come out help us create a market, but they also help lower our total carbon footprint. So we don't want to just be squeezing the balloon, taking off renewable energy from the grid to produce green hydrogen. And we can get into more specifics there. So I do expect that the rules will come out, we'll incorporate some of these factors. But I want to say that our projects are very solid. We have committed off-takers, which I think is the key because this market for green hydrogen is developing. So to have early-on projects, I think the key is not only have a great project, and it -- with a very low carbon footprint. So you get all of the benefits of the IRA, but to have a committed offtaker.

Andres Gluski:

Well, look, I think transmission constraints are affecting the market already. So we got out early, and we started getting a filing for interconnections on a big way 3 years ago in key markets like PJM and CAISO. So I think we're in a good position there. I think right now, we have a new industry here. And so I think we have to come to terms with the new definitions. What is pipeline? So for us, pipeline is projects that we already have, either land rights, interconnection rights, real prospects to make a project. And then, of course, there are different phases. Some projects are far more advanced shovel ready and some are more at the beginning of the Q. I think having looked at a lot of say, proposals from other developers, they count pipeline things that are -- we would call prospects. And I think we have to move towards a common definition, I mean, a little bit perhaps like the oil sector, which has possible reserves -- has probable reserves and has proven reserves, right? And I think what's very important is that the -- to get a pipeline, you have to invest and you have to have money. So some of the new changes, for example, on the interconnections will make it a little bit more costly just sort of spurious flood the zone request for interconnections. So maybe Steve can give you some comments on how that is progressing, which would be favorable to us. We don't see any sort of short-run effect of it. But in the long run, it's favorable to us because I think we've been the most, I would say, stringent about what we consider pipeline. And what we're very interested in doing is maximizing the conversion rate. But I do also want to emphasize that if somebody comes to us, a client and ask us to complete on advanced stage development project, that's the best of all worlds because we get to conserve the pipeline. We weren't investing money when it was at the highest risk stage and can bring it online more quickly and satisfy that client.

Andres Gluski:

And I say, look, we're also taking sort of technological a look at how we can improve transmission for our projects. So this is like using the grid stack to be able to baseload transmission lines, which were really peakers. This means dynamic line rating. This means using our prefab solar, which takes about half the space to be able to put higher loads where we have a good interconnection. And you also noticed that we're putting large battery projects where we have interconnections from our decommissioned coal plants. So we're looking at this problem rather holistically. And again, I think we're in a very good position to take advantage of what's going to be an increasingly congested grid.

Richard Sunderland:

Circling back to the data center commentary from scripts. Curious how much of a near-term change in C&I demand you're seeing from this subsector specifically? And any indications of upside just on that ramp over the next 1 to 2 years relative to what you were seeing maybe 6 months or a year ago?

Richard Sunderland:

And then just wanted to parse the kind of backlog pipeline conversation a little bit more finally for the hydrogen. It sounds like the 1.4 gigawatts for Texas could come in this year. Could you just speak a little bit more to your confidence level there for '23 specifically, and what you're focused on there? And then thinking about the balance of the hydrogen opportunities, when could those come in over the next few years?

Richard Sunderland:

And then just one final one for me. The Belfield project, you've been very clear in a lot of the messaging around how that came together. I'm just curious in terms of considerations around Phase 2 versus Phase 1, just Phase 1 your return thresholds on a stand-alone basis. How do you think about the progress to signing Phase 2? Anything you can offer there would be helpful.

Operator:

Our next question comes from Angie Storozynski with Seaport. Angie, your line is open. Please go ahead.

Andres Gluski:

Angie, and thanks for that question. And I think you got it spot on. Look, this is, quite frankly, a symptom of strength in our case. We have the hottest management team in the market. And so of course, people are going to be being made offers. And if people are obviously -- if they want to go to private equity and bet on a longer-term IPO, that's their right. But this in no way affects our business whatsoever. And I think the best proof of that is after the departure in clean energy, we've signed more PPIs. So we're doing very well. I don't expect it to have any impact on the business. And I expect the same in U.S. utilities. I don't expect this will have any impact whatsoever. But it is a sign of that, yes, we have a strong team, we have a deep bench, and we'll continue to identify talent and prepare it and move it up. Again, let's say, where AES was in, say, in 2012 or something, our team wasn't the honest in the business, people wouldn't be trying to poach it. So it is what it is, but I feel very good about where we are, and it doesn't change our plans whatsoever. And I think the teams are very motivated on executing on the plans that we laid out.

Andres Gluski:

Well, I can say categorically, absolutely, under no uncertain terms, we have no such projects in our backlog. I want to make very clear because maybe some other people are doing that. I think that's not transparent. I would not recommend anybody to do it. In our case, whatever we have in the backlog, we are -- we have the project, we are committed to delivering it on a certain date for a certain amount of time, and our clients have an obligation to take that energy -- a certain amount of energy for a certain amount of time. So this is binding for both sides. And the fact that 43% of our backlog is currently being built, we have ordered all the equipment for our '23 through '25 backlog, and about 3 quarters of them will come online by 2025. So I want to make very clear that's a good question. I wouldn't recommend anybody to do that. And I can say, categorically, we would never do something like that.

Steve Coughlin:

Yes, Angie, this is Steve. So look, we have, as you know, have been selling down our renewable projects after they've come online and we package them together in portfolio. So we have seen some, I would say, relatively small uptick in return requirements there, but nothing outside the range of what we expected within our plan in terms of -- this is -- these are very low-risk assets. They're solar coupon, essentially, no fuel costs, very low maintenance. So these are very predictable, and the demand for these assets continues to be very strong. So we don't see any impact to the plan for how we sell down from sort of where rates are in the market today. Does that address your question?

Steve Coughlin:

Yes. And on top of that in site -- so just as Andreas pointed out, with the new project, we have the energy community adder for that project. And actually, most -- all of our wind projects going forward, we expect to qualify for the domestic adder as well, Angie, so there's some significant offsets to the cost of financing that we've been achieving too.

Julien Dumoulin-Smith:

I know a lot has been said here already, but let me follow up on some details here, just on the year-over-year comparisons here as we go to the back half of the year, if I may. Look, I'd love to talk about -- I think you have in your slides here, $0.24 of positive net impact in the back half of the year from renewables and year-over-year comps on LNG if I rewind here, I think you said in the back half of the year that -- I mean, last year, it was like $0.30 contribution from LNG. Just as I think about that, that seems like a pretty big step-up year-over-year renewables. Can you talk about what renewables assumptions you're baking in as sort of a discrete item in -- especially in the back half of the year to sort of make up for what you need to get to your guidance? And then if I think about the start of the year, right, in terms of what you talked about renewable contributing, I think we talked about $0.27 for the full year. So -- it seems like what's implied here again, I'm curious that renewable is actually contributing more than what we thought at the start of the year and maybe what that says for future years as well. But please, by all means, respond accordingly.

Julien Dumoulin-Smith:

Is there a use on that -- sorry, go forward.

Steve Coughlin:

Yes. Yes, this is -- I think we're right at 25% on the EPS, Julian, year-to-date. So this is -- what we're seeing, although the year-over-year in the quarter is lower, that's primarily due to coal retirements in Chile as we've done the green blended extend, some of the coal that's still there, the margins have come down, which was all expected. So we're exactly on track. And also, to your point, there is some potential upside, as Andres noted, we feel really good about being on track with the construction program and there still remains the upside on the 600 megawatts potential.

Steve Coughlin:

Yes. Let us get back to you on the exact number because I don't have that math in front of me, but the renewables contribution is looking at least on track, is what I would say.

Andres Gluski:

So on the first point, no, it's not fair. Characterization is not fair. So what -- look, all right, we have partnerships in all of our businesses. So we don't necessarily have to do it on the new projects. So we can bring in partners to -- money is fungible. So if we monetize a different business, that means we have more money available for renewables. We will -- as we have in the past, we can choose to optimize the return on invested capital. And I think that we're doing a very good job of how we exit coal. I think the Warrior Run monetization, I think is probably better than people's expectations. And so we continue to manage that. So all I'm saying is that -- we never -- as Steve said in his script, we didn't -- we put this out as a 5-year plan. And in the 5-year plan, we had a certain amount of asset sales, a conservative number, and we had a sort of range for potential equity issuance as well. So the 2 somewhat offset each other. So if we do better on the asset sales, we will need less equity and we do better in terms of bringing in partnerships. So what we're saying at these levels, we do not feel comfortable issuing equity. But I think it's been very clear from our presentation that we have tremendous demand for what we're doing. And that is a once-in-a-lifetime market opportunity. So we want to create the most value for our shareholders from that opportunity. So obviously, if we don't have -- what we feel is correctly valued equity, we'll have to use other levers. And this should be nothing new to you guys. We have financed a remarkable change in this company without issuing equity. We did it by selling down assets. We got into wind by bringing in partners. So what we're saying is nothing like a promise for the future. It's just more of the same. So we will use whatever the levers creates the most value for our shareholders, and we will continue to do so.

Steve Coughlin:

No, there's no -- there's no specific Maritza process underway, Julien, at this point. So still evaluating different pathways for Maritza.

Ryan Levine:

A couple of specific follow-on questions. Is your Fluence take core to your portfolio? And I guess secondly, on the financing side, are you still open to considering the convert market to help offset equity issuance?

Ryan Levine:

The question is that core, is that core?

Ryan Levine:

Core.

Ryan Levine:

Okay. And then on the convert option?

Ryan Levine:

And then last question. In terms of Puerto Rico, what's your strategy there from existing assets and future development perspective?

Operator:

Our final question comes from Gregg Orrill from UBS. Gregg, your line is now open. Please go ahead.

Steve Coughlin:

Yes. Gregg, it's right on track with what we assumed in our guidance. So the decision has been put on the agenda for next week, August 9, that was just published, I believe, yesterday. So right on track in terms of when we assume the decision to be made. And we still feel really good about where that is likely to come out. As a reminder, once the decision is made, is to put in place, then the new rates that were decided upon last year immediately go into effect. And as we've laid out, the riders would go into effect and then the frequent quarterly recovery on our distribution investments going forward, would start to be put in place. And so this is a business really pivoting to a very different phase from where we've been delevering and setting that business up for a more normalized structure. This is an important pivot point for Ohio to really pivot to growth, and there's a lot of room for growth as there's the lowest rates in the state there in all customer classes. And even with the ESP 4, the new rates, we expect it to continue to be the lowest rates in the state for the foreseeable future. And we have, as Andres noted, 10%-plus rate base growth expected going forward. So we're very excited about this and look forward to the decision next week.

Operator:

I will now hand back to Susan Harcourt for any closing remarks.

Operator:

This concludes today's conference for everybody. Thank you very much for joining. You may now disconnect your lines. Have a great rest of your day.

Susan Harcourt:

Thank you, operator. Good morning, and welcome to our first quarter 2023 financial review call. Our press release, presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our first quarter results, 2023 guidance and 2023 parent capital allocation. Turning to Slide 10. As Andres mentioned, in the first quarter, we launched our new Strategic Business Units or SBUs. This new organizational structure reflects AES very focused and simplified portfolio. It also aligns our management teams by business line to maximize our operational synergies and to continue delivering excellent customer experiences across all our markets. Our new SBU reporting segments highlight our rapidly growing renewables and utility businesses and facilitate simplified modeling of AES, which will benefit current and new potential shareholders and analysts. Our new SBUs include renewables, which includes our solar, wind, energy storage and hydro businesses, utilities, which includes AES Indiana, AES Ohio and AES Salvador, Energy infrastructure composed of our thermal generation and LNG infrastructure businesses and new energy technologies, which includes our investments in energy technology businesses such as Fluence and Uplight as well as our green hydrogen business line and future new business innovations which support our mission. In addition to the SBUs, we also have a corporate reporting segment, which includes our corporate G&A our parent level debt and associated interest expense in our captive insurance program called AGC. Turning to Slide 11. Adjusted EPS for the quarter was $0.22 versus $0.21 last year. Our business was favorable year-over-year, which I will discuss in more detail shortly. Our results were also impacted by higher parent interest expense and a lower adjusted tax rate. Now to Slide 12. We are fully on track to achieve our full year 2023 adjusted EPS guidance range of $1.65 to $1.75. We expect a significant contribution from new renewables of at least $0.27 this year. This is partially offset by lower contributions from LNG sales, as we have previously mentioned, higher parent interest expense from incremental debt and higher rates on our revolving credit facility and a marginally higher tax rate this year. As is typically the case, our earnings are heavily weighted toward the second half of the year. This year, we expect approximately 3/4 of our earnings to occur in the second half. Growth in the year to go will be primarily driven by contributions from new businesses including over 3 gigawatts of projects in our backlog coming online, which remains solidly on track for completion. We are also reaffirming our expected 7% to 9% average annual growth target through 2025. Turning to Slide 13. As you may have seen in our press release, while we continue to report adjusted EPS, today, we are also introducing adjusted EBITDA as a new reporting metric. As the renewables portion of our business grows at an extremely high rate, we believe adjusted EBITDA is a very informative metric in understanding our business results. First, it aligns well with the performance of our underlying business and operating cash generation. And second, adjusted EBITDA is reported before the impact of U.S. renewables tax attributes so that investors and analysts can separate renewable operating earnings from the very valuable tax incentives for U.S. renewables. Beginning this quarter, I will discuss our new SBU financial results using adjusted EBITDA, with the exception of our utilities SBU, which will be measured using adjusted pretax contribution, or PTC, to facilitate comparisons with other utilities. We will provide full year guidance by SBU during our Investor Day on Monday. Adjusted EBITDA was $628 million this quarter versus $621 million in the prior year. This was driven by higher first quarter LNG sales and growth in renewables, but was partially offset by the impact of warmer than normal weather at our U.S. utilities. I’ll cover the performance of our new SBUs in the next 4 slides. Beginning with our renewables SBU on Slide 14. Higher EBITDA was driven primarily by a higher level of generation at our facilities in Panama higher wind generation and contributions from new businesses. This was partially offset by higher spend as we continue to ramp up our renewables development and lower power prices impacting our Bulgaria wind facility. Lower PTC at our Utilities SBU was mostly driven by warmer-than-normal winter weather and higher interest expense, but partially offset by higher revenues as a result of our continued investment in the rate base. Higher EBITDA and our energy infrastructure SBU primarily reflects higher LNG sales, partially offset by lower margins from coal PPAs, the retirement of our coal plant in Hawaii last year and lower availability at Southland Energy. Finally, higher EBITDA at our New Energy Technologies SBU reflects a significant improvement in operations and gross margins at Fluence. Now to our 2023 parent capital allocation plan on Slide 18. Sources reflect approximately $2.1 billion to $2.6 billion of total discretionary cash, including $950 million to $1 billion of parent free cash flow, $400 million to $600 million of proceeds from asset sales and $700 million to $1 billion of planned parent debt issuance. On the right-hand side, you can see our planned use of capital. We will return nearly $500 million to shareholders this year. This consists of our common share dividend, including the previously announced 5% increase as well as the coupon on the equity units. We plan to invest approximately $1.7 billion toward new growth, of which the majority will go to renewables and utilities. In summary, we’ve made great progress on our financial commitments for the year. At our Investor Day on Monday, we will provide detail on the strategy and future of AES overall and for each of our new SBUs. We will also provide long-term growth rates through 2027 for adjusted EPS, adjusted EBITDA and parent free cash flow. I look forward to talking with many of you then. With that, I’ll turn the call back over to Andres.

Operator:

Thank you [Operator Instructions] The first question comes from the line of David Arcaro with Morgan Stanley. You may now proceed.

Andres Gluski:

Yes, honestly, we don’t see any risk whatsoever. First, it in the past, I believe the setting was 56 votes, and that was -- the President will be to it. And by the -- we have all the panels that we need for this year, and expect to have for next year, by June of next year when the tariff, let’s say, tariff holiday rolls off. So we’re in very good shape for 2023 and 2024. And after that, we expect to have supply coming in from the U.S. We’re having no problems from our suppliers getting through under the UFLPA. So really, I think we’re in the best shape of anybody. We have not delayed a single project due to solar panel supply issues to date. And I think that’s something -- I don’t know if anybody else can say that.

Andres Gluski:

Look, as I said in my script, we are progressing well we have the supply chain. Everything is in place. But look, we won’t know until the fourth quarter of this year, and they’re going to fall in this year and they’re going to follow in next. But I would remind everybody that’s not value issue. If they come in a couple of weeks later, it doesn’t affect the profitability of the project at all. It is an accounting issue. But as of now, we we’re doing well, but we can’t say -- give you any particular update with greater clarity and probably until the fourth quarter of this year.

Steve Coughlin:

Yes, hi, this is Steve. There is definitely earnings from this. And so effectively, we’re monetizing the remaining 7 roughly years of the PPA this year. And so we’ll recognize earnings this year, and we expect to have an obligation for capacity through the middle of next year. So the earnings over this termination agreement will be recognized over roughly 11, 12 months following when the commission approval comes in. So say if it comes in, in June, probably about half this year and half next year. And there’s very little debt to pay down here. So this is -- these proceeds will likely -- this is a 7-year payment stream, but we’ll likely monetize that this year. And then that’s captured in our asset sale in terms of our capital sources this year, if you saw on that slide. So that will be used to fund the growth of the business.

Operator:

The next question comes from the line of Angie Storozynski with Seaport Global. You may now proceed.

Andres Gluski:

Sure, Angie. Well, thanks for the question. Look, first, I’d say, we continue to provide adjusted earnings per share guidance. And as we said, we’ll be providing adjusted earnings per share guidance through 2027 on Monday. So I want to make that perfectly clear, but we’re adding as an additional indicator which is adjusted EBITDA that we’re going to be giving. And partly, it’s to give greater clarity into our performance of our renewables and partly that has to do with sort of the lumpiness of the projects. So that’s the real reason that we’re giving an additional one. It also helped people to do so, for example, if some of the parts of our different businesses, renewables, utilities, infrastructure. So I want to make very clear that we are providing adjusted earnings per share through 2027. Regarding the other questions that you have, I’m going to go ahead and pass that to Steve.

Agnieszka Storozynski:

Okay. And then you can also help us how to allocate the corporate leverage across -- I mean, again, if we are trying to move to the sum of the part valuation from an EBITDA perspective, we need to figure out how to allocate the corporate debt, right, among these subsidiaries.

Agnieszka Storozynski:

Okay, okay. See you guys on Monday. Thank you.

Richard Sunderland:

Hi, good morning and thanks for the time today. Maybe I’ll pick it up where Angie left off on the new SBUs. Turning to the new energy technologies, SBU, can you speak more to the green hydrogen side. Curious if this represents a shift in thinking of where you like to be involved in hydrogen? Or are you just specifically calling out the breakout there relative to the renewables feeding in?

Richard Sunderland:

Got it. That’s very clear. Sticking with the SBU theme, energy infrastructure, are you able to disclose how much of that is called today?

Richard Sunderland:

Just this on an EBITDA contribution basis or a percentage of SBU basis?

Richard Sunderland:

Got it. Very helpful. And then just one more for me. in consideration of the Warrior Run termination relative to the $400 million to $600 million asset sale target, where are you currently with announced and closed transactions relative to that range?

Richard Sunderland:

But just on the numbers -- sorry. Sorry, Andres.

Richard Sunderland:

Got it. Thank you. But just on the Warrior Run $357 million, $400 million is the low range of the 23 targets that gets you most of the way there? And then did you receive any proceeds on the quarter? Or is the rest either, I guess, Jordan or future announcements?

Richard Sunderland:

Perfect. Well thank you for the time today. See you on Monday.

Operator:

Thank you Mr. Sunderland. The next question comes from the line of Durgesh Chopra with Evercore ISI. You may now proceed.

Andres Gluski:

Well, thanks for the question. It’s a great question. Look, we feel very good. And the one thing is, if you recall from last year, I believe we had a lot of signings in the last quarter. And so what we’re seeing here, these things are lumpy. So we have been ranked 2 years running as the largest developer of renewable projects for corporations. And so when you’re dealing with these corporations, these are big projects. So one project can easily be a giga. For example, the just another case, our green hydrogen project in Texas, that’s 1.4 giga. So these are lumpy. So I’m not the least bit concerned about meeting our growth targets. We’re seeing a lot of interest. We’re in advanced negotiations. But they don’t count until you sign them. So we feel good about them. No cause for concern. And that’s one of the issues we have, that they’re lumpy. But when you’re going for big contracts, as an example, the project -- the green hydrogen project in Texas, that’s 1.4 gigawatts just in one. And we have others that are in that range. So it’s going to be lumpy, but we’re not concerned because we will land enough of these to keep us on track.

Andres Gluski:

Look, we have no update for cost. It’s still going to be in the range of around $4 billion, the whole project. We think it’s, again, it’s going to be the lowest carbon project in the states. As you know, you have a $3 per kilogram subsidy, if you have below a certain threshold of carbon intensity. So we feel we’re well within that. If you have less than that, for example, if you’re taking energy from the grid, then it drops to $1. So we feel very good about that. In terms of the costs, what I’d say is what they announced on their Neon project. And again, I’m just repeating what they put on there that they were going to make some more capital investments to lower operating costs. So it’s the Neon project in Saudi Arabia which is very good for us because they are using a very similar project to this one but it’s at more advanced, so we can learn from that project jointly learned from that project. But no, we have no updates, but we have no reason to think that there’d be any additional cost overruns at this point in time.

Andres Gluski:

See you on Monday.

Julien Dumoulin-Smith:

Hey good morning team. Thank you guys for the time and the question here. Look, I just wanted to follow up on the ITC, PTC conversation we’ve been having of late. Just curious, are you guys still pretty committed to using ITCs. I know some of your peers have been evolving towards PTCs, you guys focused on the Eastern U.S. Can you talk about the thought process and philosophy there? And then also to follow up back on Angie’s question to the extent to which that you are using ITCs. 70-30 split is still good. I know that, for instance, here in the quarter for tax cut, it’s fairly low. So I just want to make sure that ITC heuristic of 70-30 in year 1, year 2 still applies.

Julien Dumoulin-Smith:

Right. But the point is your ITC, you’re still vastly weighted towards ITC versus PTC, right, as you have been and you don’t intend to change that necessarily, especially given your commentary here. I just want to make sure there’s been some concern otherwise.

Andres Gluski:

The one thing I would add on the... Julien, so we’ll be doing more wind in the states, which will be PTC. So for example, the project in Texas is 900 megawatts of wind. So yes, we’ve been more towards ITC partly is because we’ve been very heavily in solar. We’re very strong in solar. Over time, we expect more of a balance.

Andres Gluski:

Yes. I mean in our case, not really. I think I would point to that. It’s just we’re in some negotiations for some whales. And when we land them, it will come through. What did happen last year because of the OXi tariff circumvention case that did delay projects. It did delay projects and set them off into, let’s say, a longer time horizon than would otherwise. But again, since we do a lot of bilateral negotiations, and we haven’t had any problems with our supply chain. That is not what’s driving it. Where the domestic content issue does come in is in terms of the $6 billion contract we have for domestic manufacturer of solar panels here in the states. And so obviously, what’s key there before sort of sitting on the dot line is what is domestic content. And the main difference is how granular it’s defined because if it’s more similar to what has been done, for example, for wind, then it’s much easier to comply with initially. But our plan is to move up the supply chain and have more and more of the inputs made in the states, including some of the more basic minerals, et cetera, coming in. We already have with our suppliers, the wafering is moving out of China, which was the last sort of main component. We’re already buying panels that were made outside of China. And of course, all the wafering etcetera was done in Eastern China, not Western China. So we feel very good about that, and we’ve had no issue thus far.

Steve Coughlin:

Yes. I would say some of these are definitely upsides, Julien. So all else being equal, yes, there’s upside. Unfortunately, as is the case, I think, with most utilities, the warmer winter weather was somewhat of an offset to those upsides for the first quarter. So we still see the potential for upside above even the midpoint of our guidance, but that’s not -- it remains to be seen how the rest of the year goes.

Operator:

Thank you Mr. Julien. The next question comes from the line of Gregg Orrill with UBS. You may now proceed.

Steve Coughlin:

Yes. No, it’s Steve. So sure. So we’ll definitely talk some more about the longer-term financing plan through 2027. So I think that will give additional color. So we’ll hold for that. This year, I think as I laid out on the slide, we will raise additional parent debt capital largely to fund growth in the renewables segment. And then we have the asset sale program in addition to the close to $1 billion of parent free cash flow coming up from the existing business. So there’s no plan for equity this year. Looking ahead, we’ll talk some more about that in the plan for Monday. What I would say there is, certainly, we have we’re well positioned for growth. We’re in a leadership position, and we want to grow beyond 2025. But certainly, through 2025, we would not need equity to meet our 2025 commitments. However, we would expect to start investing in growth, including things like the green hydrogen project, which would get started before 2025 to support the second half of the decade. But we’ll share more detail on that on Monday.

Operator:

Thank you Mr. Orrill. The next question comes from the line of Ryan Levine with Citi. You may now proceed.

Andres Gluski:

I would say, look, part of it is that, that’s what the most of our peers are using. And what we felt was most transparent is to provide EBITDA and also then the tax attributes. And so if for comparison purposes, you need to add the two, you can do so. But it was really try to make it easier on everyone by using what’s most used in the market.

Andres Gluski:

I think -- we’ve got a 3-year extension. It’s -- those assets -- those locations are extremely valuable for the grid. So we’ll see what developments there are. But right now, 3 years going forward, it’s pretty good.

Andres Gluski:

Thank you.

Susan Harcourt:

We thank everybody for joining us on today’s call. We look forward to seeing many of you at our Investor Day on Monday. As always, the IR team will be available to answer any follow-up questions you may have. Thank you, and have a nice day.

Susan Harcourt:

Thank you, operator. Good morning and welcome to our fourth quarter and full-year 2022 financial review call. Our press release, presentation, and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning everyone. Today, I will cover the following key topics. Our financial performance during 2022, our parent capital allocation, and our 2023 guidance and expectations through 2025. As Andres mentioned, our results for 2022 demonstrate the strength, resiliency, and flexibility of our portfolio as we surpassed our guidance range of $1.55 to $1.65. Overall, our portfolio was well structure to perform in the current market environment and is well-positioned for growth as AES continues to lead the global energy transition. Turning to Slide 13. Full-year 2022 adjusted EPS was $1.67 versus $1.52 in 2021, driven primarily by a significant volume of LNG sales in our increased ownership of AES Andes. These positive drivers were partially offset by unplanned outages, several one-time expenses we recorded at our U.S. and utilities and South America SBUs, a higher share count as a result of the 2021 accounting adjustment for our equity units, and higher parent interest stemming from higher debt balances. The $1.67 per share also includes approximately $0.12 of losses from AES Next. Primarily from our ownership in Fluence, which served as an additional drag year-over-year. We expect Fluence's results to significantly improve beginning this year as they discussed on their recent earnings call. Turning to Slide 14. Adjusted pretax contribution or PTC was $1.6 billion for the year, an increase of 149 million and a 11% growth over 2021. I'll cover our results in more detail over the next four slides, beginning with the U.S. and utilities SBU on Slide 15. Lower PTC in the U.S. was primarily driven by the recognition of one-time expenses from previously deferred purchased fuel and energy costs at our utilities. Outages at Southland Energy and AES Indiana in the second quarter and lower contributions from Clean Energy and the retirement of our coal plant in Hawaii. Partially offset by higher contributions from our Southland legacy assets in the third quarter. Higher PTC at our South America SBU was primarily driven by our increased ownership of AES Andes and higher margins at both AES Andes and AES Brazil, but partially offset by a prior year gain related to an arbitration at Alto Maipo, outages at AES Andes and a one-time regulatory provision in Argentina. Higher PTC at our MCAC SBU reflects the benefit from a large volume of LNG sales redirected to the international market. As I'll discuss later, we do not expect an opportunity of the same scale recur this year and anticipate lower PTC from MCAC in 2023. The LNG sales were partially offset by the full-year impact from the sale of our coal plant in the Dominican Republic in 2021. Finally, in Eurasia, adjusted PTC was relatively flat year-over-year with an overall net decline driven by higher interest expense, but partially offset by higher energy prices earned at our wind plant in Bulgaria. Now, let's turn to how we allocated our capital in 2022 on Slide 19. Beginning on the left hand side, sources reflect 1.3 billion or total discretionary cash. This includes parent free cash flow of $906 million, which was near the top end of our guidance expectations. Asset sales were below our expectations for the year, but we still expect to achieve our goal of $1 billion in proceeds by 2025. Given the delay in asset sales, we accelerated the issuance of some parent debt, which is within our long-term expectations. Moving to uses on the right hand side. We invested more than 700 million in growth at our subsidiaries, of which approximately two-thirds were in the U.S. We also allocated nearly 500 million of our discretionary cash to our dividend. Turning to our guidance and expectations, beginning on Slide 20. Today, we are initiating 2023 adjusted EPS guidance of $1.65 to $1.75. This year, we expect to commission approximately 3.4 gigawatts of new renewables, which is the largest year-over-year increase in AES history. This growth further validates AES' position as a leader in renewables and highlights the outstanding efforts of our commercial and operations teams in our markets. Roughly 65% of this new renewable capacity is located in the U.S. More than half our total 2023 adjusted PTC will come from the U.S. this year as we execute on the transformation of our portfolio. As I discussed last quarter, our U.S. renewables projects benefit from both investment tax credits and production tax credits. Our 2023 guidance includes approximately 500 million of adjusted PTC from tax credits generated and recognized by new U.S. renewable projects coming online this year, which is approximately double the amount from 2022. Tax credits are an important component of our renewables business earnings and cash flow and we intend to provide updates on our 2023 tax credit expectations throughout the year. While the midpoint of our 2023 guidance range is below our long-term annual growth target, we are reaffirming the 7% to 9% growth rate through 2025. 2023 growth is lower than the long-term trend for a few reasons. First, we've taken a conservative approach to modeling renewables projects expected to come online in 2023. Our renewables construction is typically concentrated in the fourth quarter and this year will be no exception. As a result, construction delays of only a few days could cause a project to shift from 2023 to 2024 and negatively impact this year's results. This is particularly relevant for our U.S. renewables projects where we recognized significant earnings from investment tax credits in the year a project is placed into service. Of the 2.1 gigawatts we plan to complete in 2023, two-thirds are expected to come online in the fourth quarter. Our guidance assumes that an additional 600 megawatts of projects currently scheduled to come online in December slip into 2024. If some or all of these projects are completed on schedule, this will create up to $0.10 of upside to our 2023 guidance. It's also important to note that even if there are delays to next year, this is only a timing issue with no material value impact. And would support higher growth in 2024 with no impact on our long-term growth rate expectation. Second, we expect to see lower contributions from our MCAC SBU on a year-over-year basis, primarily driven by more than 200 million of adjusted PTC from LNG sales we executed in 2022. Our commercial team was able to leverage the optionality embedded in our LNG supply contracts to capitalize on high international gas prices by redirecting Henry Hub-linked LNG cargoes to the international market. Although LNG sales will continue in 2023, we do not expect the same magnitude of opportunity as the spreads between Henry Hub and international gas prices have compressed and more of our gas supply this year is linked to TTF international prices rather than Henry Hub. Third, we expect to see lower margins at our Chile business this year, particularly in the first half of the year, which is a temporary impact of our Green blend and extend strategy to transition our customers from coal power to renewables. Several coal PPAs have or will expire this year as we proceed with our intent to fully exit coal by 2025, and others have been restructured to be priced off renewables that are still under construction. We view this as a short-term cost of decarbonizing our portfolio and do not expect any impact to our 7% to 9% long-term growth rate. Looking ahead, our teams are working on commercial solutions to mitigate the dilution as the portion of our earnings from coal continues to decline. Based on the drivers discussed, we expect our 2023 earnings to be significantly second half weighted with approximately three quarters recognized in the second half of the year. While we typically have had about two-thirds of our earnings in the second half, the increase in seasonality this year is driven by the significant volume of new U.S. renewable projects coming online in the fourth quarter. Now, turning to our 2023 parent capital allocation plan on Slide 21, beginning with approximately 2.2 billion of sources on the left-hand side. Parent free cash flow for 2023 is expected to be 950 million to 1 billion, in-line with our annualized growth target. In addition to parent free cash flow, we expect to generate 400 million to 600 million in asset sale proceeds this year. This includes our previously announced sale in Jordan, as well as the pending sell-down of some of our operating renewables in the U.S. I also want to point out that we intend to relaunch the sale process for our Mong Duong coal plant in Vietnam to better align with the approval requirements that became clear during the initial sale. The remaining portion of our 2023 asset sales is expected to come from additional sell-downs and sales supporting our decarbonization goals. Now, to the uses on the right-hand side. We plan to invest approximately 1.7 billion toward new growth, of which about two-thirds will be allocated in the U.S. to renewables and to increase our utility rate base. We expect to allocate approximately 500 million to our shareholder dividend, which reflects the previously announced 5% increase. In summary, we exceeded our financial commitments for 2022 and are confident in this year's guidance and the long-term outlook for AES. The energy transition provides tremendous investment and innovation opportunities, and I believe no company is better positioned than AES to lead this transition. As we execute on our strategy, we will continue to deliver on our financial commitments to maximize per share value for our shareholders. With that, I'll turn the call back over to Andres.

Operator:

Thank you. [Operator Instructions] So, our first question comes from the line of Angie Storozynski. Your line is now open. Please go ahead.

Steve Coughlin:

Yes, Angie, hey it's Steve. So yes, and that's because, as Andres shared in his remarks, we are intending to update you on our new business segments. And so when we issue that level of guidance, it will come in the Investor Day.

Steve Coughlin:

Yes. So Next, in total, Angie, was roughly a $0.12 drag last year. We have to be careful because Fluence is a separate public company, and we can't get ahead of their disclosures. They haven't specifically guided to earnings, but on their last call, they did guide to a significant improvement in margins this year. So, Next is a positive driver this year, and I would say, to a material extent, but I can't say specifically because I can't get ahead of them on their earnings disclosures. But we are expecting it to be much better. They've made a ton of progress on all of the operational and commercial improvements that they've been outlining. And as I've said previously, the Next portfolio we expect to be neutral to earnings by 2024, and I still expect that.

Steve Coughlin:

No, it would be lumped into that second column with the negative – it would be an offset in that negative $0.15, basically.

Steve Coughlin:

The corporate does include AES Next, under our current segments. And so, we'll be talking more at Investor Day about the future, but I can say, it's largely parent interest on the revolver, where we've had higher balances and of course, higher rates going into the revolver, as well as the incremental drag from AES Next.

Steve Coughlin:

Sure. So, look, first of all, we're very happy to have the optionality from the IRA on choosing ITC or PTC newly for solar, as well as having the ITC for storage. So, typically we're going to choose the tax credit structure that yields the highest return in the project. So, it's great to have that optionality. I would say, going forward, the ITC – there is a difference in the earnings profile. There's an upfront recognition of the ITC versus the PTC is spread out over 10 years, but other than that, you'd expect the lifetime earnings roughly to be the same if the credit structure yielded roughly the same returns. So, in this case, we have about – in AES’ case, about one-third of our pipeline, we believe, will qualify for the energy community adder. And so, we feel that we're going to be very competitively positioned to get at least the 40% level for about one-third of our pipeline. So, that's a good thing. I would say in terms of where the credit accrues, I think it's going to be a mix of things. Certainly, there's been higher costs that the industry has absorbed on the order of 30%. I think part of it goes to absorbing that impact of higher costs in renewables. I would say some will go to competitiveness in terms of bidding for the PPAs. And largely, as Andres has talked about before, we see there being more of a constraint on the supply side in the renewables market. So, we do see that continued strong demand, but that there's going to be constraints on the supply side of projects being ready to meet that demand and that will have some upward pressure on returns.

Angie Storozynski:

Great. Thank you.

Unidentified Analyst:

Hi, good morning. Thanks for taking my question. This is [indiscernible] for Nick today. First, a quick question on the Analyst Day. Can we just get some color on your thoughts on the timing? I know you mentioned spring, but what are some of the specific drivers to determine the timing of the Analyst Day?

Unidentified Analyst:

Okay. That's helpful. Thanks. And just maybe just on the asset sales proceeds. I know you're feeling some of the add to sales proceeds with the parent debt issuance, but as we think about the [79] [ph] CAGR currently, can you just – are you able to continue to bridge this growth rate without any additional common equity? Just want to check in on that.

Steve Coughlin:

Yes. Yes. And with regard to the debt, it's really just – it's somewhat fungible. We look at both our sales program, as well as our debt capacity, always holding to our investment-grade metric, plus a cushion as a minimum, but it's really just timing. So, there's just flex between when we determine to issue the debt within our expectations and when those asset sales come in. So, it's just executing somewhat of a flexibility on the timing of the asset sales and the debt, kind of flex back and forth.

Operator:

Our next question comes from Durgesh Chopra of Evercore. Your line is now open. Please go ahead.

Andres Gluski:

Okay. Hi, Durgesh. Listen, we feel good about the numbers that we're giving out there. We have all the equipment basically secured. And we're very – I'd say about what we have about 5.5 gigawatts under construction as we speak. Okay. Not all of them are going to come in line in 2023. But just to give you an idea, we feel very good about it. Now, the [600] [ph] megawatts that we said might slip into 2024. What are the issues? Well, for some of that, there could be equipment delivery. There could be interconnect timing, easement issues, [indiscernible] permits, the usual stuff that when you're doing construction. So, we're going to try very hard to get it done this year, but we feel it's prudent to say that these are going to slip most likely, slip into 2024. Now, what I would like to reiterate is that this really isn't a business issue. This is just an accounting issue from my perspective because we – all of those 600 megawatts, I feel very confident would get done, for example, by – certainly by March. So, there aren't any penalties involved and there isn't any significant change to the return of those projects. So, unfortunately, what you really have is given that we run on a calendar year. We have so much happening in the last quarter. But I want to really emphasize this is not a – we have – of all the renewable developers, we have not abandoned any project because of equipment delays or permit delays. We have delivered on [indiscernible]. So, we feel very good, but there is a timing issue, and we thought it prudent to say, look, these 600 megawatts, we think are most likely to fall into next year. But it's a matter of – it could be weeks. And we will nonetheless try very hard to get them done this year.

Andres Gluski:

I really don't think we'd have it honestly, by our Investor Day, to be frank. I think it'd be more by the summer that we would have more indications on particularly the project. This gets quite granular. [X projects] [ph] got a permit or something that was missing, but I don't really don't see that before that.

Durgesh Chopra:

Got it. And thanks, Steve. And just one last one. I noticed the 2023 to 2025 PPA finding is, again, very healthy 14 gigawatts to 17 gigawatts, but you're not, sort of giving us an annual number this year like you did in 2022, which was 4.5 gigawatts to 5.5 gigawatts and you came in right in that range. Are you expecting that 2023 to 2025 signings to be lumpy or should we still expect right, the new PPAs in the [indiscernible] range each year?

Durgesh Chopra:

Got it. Thanks guys. And congrats on the BNEF recognition again this year. I appreciate the time.

Operator:

Our next question comes from the line of Julien Dumoulin-Smith of Bank of America. Your line is now open. Please go ahead.

Andres Gluski:

Yes. I mean, look, let's say, we have a 12.2 gigawatt backlog, of which about 5.5% are under construction now. And a good portion of that is going to come online between now and 2025. So, there's no reason to think of a change. If anything, the market continues to grow, and we see a shortage. I don't know if – Steve, you want to comment...

Andres Gluski:

Yes. This is not a market that is not growing very rapidly. And we do see pent-up demand. What we do see is that because a lot of people did not deliver in 2022, we see pent-up demand. So, what we have to do is really make sure that we're getting the returns that we want and really going after the value-add on those projects, but it's not for a [indiscernible] of projects by any means.

Steve Coughlin:

Yes. So, the primary portion of that relates to the increase in the tax credit. So, a portion of the $0.27 is related to just that base of projects from 2022 coming into 2023. So that's part of it. But I would say the largest component is the increase in the tax credit to the range of about 500 million recognized this year, which is a little more than double what we recognize that last year. So, that's the largest component of the $0.27.

Steve Coughlin:

Yes. I was also just going to say, and that's partly why we're calling out this additional 600 megawatts because it's largely – in fact, it's all investment tax credit-based projects. So, as Andres described in the most extreme, even if you just had a project that was commissioned on January 1 instead of December 31, you would move that tax recognition over a calendar year. So that's why we're calling out that as potential upside and the sensitivity to the tax credit, and it's just timing is all it is.

Steve Coughlin:

Exactly.

Cameron Lochridge:

Got it. Okay. That would do for us. Thank you guys, both.

Richard Sunderland:

Hi, good morning. Thanks for the time today. Just one last one on this 2023 versus 2024 [on 600 megawatts] [ph]. It sounds like if the $0.10 looks to 2024, this clearly should be additive to the prior growth outlook [meaning] [ph] attitude to the 7% to 9% CAGR. Is that the right frame of reference for whether the 600 megawatts [indiscernible] in 2023 and brings you kind of back to the original range or 2024 pushes you above?

Richard Sunderland:

Okay. Got it. Very clear. Thank you. Turning to Ohio, you asked before, any sense on the backdrop in conversations there after all the time and engagement around the [ASI] [ph] rate case?

Richard Sunderland:

Understood. Understood. Thank you. And then you reference changes around the Vietnam requirements for sale and relaunching that transaction. Could you just parse that a little bit more in terms of what you're expecting there now? Do you see a quicker path to divestment under a second go, anything else would be helpful here?

Richard Sunderland:

Got it. Thank you for the time today.

Steve Fleishman:

Yes, thank you. Andres, maybe could you give us just some overall color on how things are proceeding on panel supplies and particularly you flip up implementation issues. And is that kind of a key variable in the timing of these projects or is it more other issues?

Steve Fleishman:

Okay. And then just – I know this was discussed on the last call, but just how are you making the decision between on U.S. projects, ITC versus PTC. I guess, -- so PTC, I think you had talked about still having a lot of value in the tax equity and the depreciation, but just – do you see that starting to shift at some point in the – as you execute on future projects?

Steve Fleishman:

Okay. Thank you.

Gregg Orrill:

Hi, thanks for taking my question. I just wanted to, sort of confirm where the credit goals are, sort of with the guidance update and the segment – the new segments that you're thinking about? Sorry, if I'm getting ahead of my [indiscernible].

Andres Gluski:

I think the credit rating, right?

Andres Gluski:

Yes. So Gregg, in terms of the credit rating, we're already more than 50% of our earnings are coming from the U.S. and a higher and higher percentage is coming from renewables. So, we already have a – if we're growing 7% to 9%, that includes the dilution from getting out of coal. So, actually, our renewables are growing at a much higher rate, more like 10% to 12%. So, to put that in context, all of those things point to an improvement, as Steve was saying, in terms of the quality of the numbers beyond the metrics. So, again, we feel very confident in what we've said. This is a red line. We're not going to drop below investment grade, and we're going to continue to strengthen it.

Operator:

Thank you. Our next question comes from Ryan Levine of Citi. Your line is now open. Please go ahead.

Andres Gluski:

No. I mean we really think this is a culmination of what we've been doing in terms of moving into renewables. And our business is long-term contracted. And what we're seeing is a lot of this would make our business we feel more transparent and more comparable to other people's businesses. So, that's all I can say at this point, but it's something that I think you guys will welcome because it gives greater transparency. And I think it makes more and more sense as, again, we transition more to renewables.

Andres Gluski:

Well, I'll say the two elements. One is that we have less gas available to take advantage of that opportunity because we had a step down in our Henry Hub-based gas contracts. The second is, has to do with the spread between Henry Hub plus and TTF. So, those spreads have narrowed. It's been a very warm winter, especially in Europe. So, we'll see. So, that's an opportunity that exists there, but we're not – it would be smaller, smaller quantity. And we're not counting on it this year because right now, the spreads are not such that between all the transportation and the sharing of the upside with oil traders, et cetera, look particularly attractive, but the option is there, should the situation change.

Ryan Levine:

Great. And then last question for me. In terms of the asset sale process, to the extent some of these deals don't happen or get delayed, what tools do you have to alter your financing plan in light of looks like a choppy M&A market.

Ryan Levine:

Great. Thank you.

Angie Storozynski:

Thank you. Just one thing. So, the 600 megawatts that might slip into 2024, that's the growth number, right? What would it be adjusted by ownership?

Steve Coughlin:

Yes. I mean, so we do have [indiscernible] so this is the U.S. number. So, we have our partnership with Alberta Investment Management. And so, I would say, for the most part, it's about 75% AES is that number. And the – up to $0.10 that I mentioned, Angie, is AES' share. So, that's not the [indiscernible].

Operator:

Thank you. As there are no additional questions waiting at this time, I'd like to pass the conference back over to Susan Harcourt for closing remarks.

Operator:

Ladies and gentlemen, this concludes today's call. Have a great day ahead. You may now disconnect.

Susan Harcourt:

Thank you, operator. Good morning, and welcome to our third quarter 2022 financial review call. Our press release, presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andres Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andres.

Steve Coughlin:

Thank you, Andres, and good morning, everyone. Today, I will discuss our third quarter results 2022 parent capital allocation and 2022 guidance. Turning to our financial results for the quarter beginning on Slide 10. I'm pleased to share that our third quarter results are very strong, and we now expect to be at or near the high end of our full year 2022 adjusted EPS guidance range of $1.55 to $1.65. Third quarter adjusted EPS was $0.63 versus $0.50 last year, driven primarily by our LNG business, as Andres discussed. In addition, we also benefited from an increased ownership in AES Andes as well as higher margins in Brazil. These positive contributions were partially offset by onetime charges at our U.S. utilities in Argentina businesses. Relative to last year, we also had higher losses from our AES portfolio as financial results from Fluence were not reported in our Q3 numbers last year, higher parent interest stemming from higher debt balances as we increase investment in our subsidiaries and a higher adjusted tax rate due to a nonrecurring benefit in Q3 2021. I should also note that despite considerable macroeconomic volatility, we see very little impact on our financial performance. For example, the forecasted full year impact of foreign currency movements after tax is well under $0.01 of adjusted EPS due to our highly contracted and largely dollarized business, along with our very active hedging program. In addition, nearly 80% of our debt is either fixed rate or hedged against interest rate exposure and approximately 82% of our revenue is protected by inflation index for hedging. Turning to Slide 11. Adjusted pretax contribution, or PTC, was $569 million for the quarter, a $141 million increase year-over-year due to the drivers I just discussed. I'll cover the performance of our strategic business units or SBUs in more detail over the next 4 slides, beginning on Slide 12. In the U.S. and Utilities SBU, lower PTC was driven primarily recognition of onetime expenses at our U.S. utilities from previously deferred purchase fuel and energy costs. Including those related to an outage at our Eagle Valley plant from April 2021 to March 2022. We pursued and entered into a settlement for Eagle Valley and took a provision against a deferred fuel recovery asset at AES Ohio, which we will continue to pursue. These expenses impacted adjusted PTC by approximately $48 million in the third quarter. In addition, lower PTC was driven by lower availability in Puerto Rico. Our legacy Southland units provided significant energy margin contribution again in the third quarter this year, although this was not a material year-over-year driver. We are also very pleased that in the third quarter, the California State Regulatory Authorities formally launched the process required to further extend our Southland legacy units beyond 2023. Higher PTC at our South America SBU was mostly driven by our increased ownership of AES Andes and higher margins at both AES Andes and Brazil, but partially offset by a provision in Argentina. Higher PTC at our Mexico, Central America and the Caribbean, or MCAC SBU primarily reflects our commercial team's outstanding effort to redirect our LNG supply from Panama to the international market as discussed earlier. These LNG sales were enabled by the flexibility we built into our commercial structure and gas supply agreements along with favorable market conditions, which may be present going forward, although we expect to a more limited extent. Finally, in Eurasia, adjusted PTC was relatively flat year-over-year with an overall net benefit from higher power prices at our wind plant in Bulgaria. Now to Slide 16. As a result of our overall strong performance year-to-date, along with the significant contribution from LNG sales, we now expect to come in at or near the high end of our full year 2022 adjusted EPS guidance range of $1.55 to $1.65. Growth in the year to go will be primarily driven by contributions from new businesses, including roughly 500 megawatts of projects under construction coming online as well as further accretion from our increased ownership of AES Andes. We expect to recognize additional LNG sales in the fourth quarter, but the contribution will be much smaller than the benefit in Q3. We are also reaffirming our expected 7% to 9% annualized growth target through 2025, based primarily on our expected growth in renewables, energy storage and U.S. utilities. Turning to Slide 17. As Andres highlighted, the Inflation Reduction Act extended and expanded the tax incentives available for U.S. renewables and energy storage. Tax credits have been an important part of the economic value creation of our U.S. renewables portfolio, and the IRA provides clarity on long-term eligibility for these credits. As U.S. renewables become a larger share of our portfolio, I want to briefly touch on the way these tax incentives contribute to our earnings and cash flow. Our U.S. wind projects are typically eligible for production tax credits over the first 10 years of operations. Our solar and solar plus storage projects typically qualify for an investment tax credit generally recognized within the first 2 years, the project begins commercial operations. To ensure we take full advantage of the tax value of our U.S. renewables, we usually bring on partners that will invest in these projects to be allocated the majority of the associated tax attributes. These are called tax equity partnerships. It's important to recognize that as we monetize these tax credits, they create earnings and cash for AES. For full year 2022, we expect our projects to generate approximately $280 million to $310 million in new tax credits. After monetizing these credits through our tax equity partnerships, the earnings recognized by AES this year from new project commissioning’s will be approximately $200 million to $230 million, with the remaining earnings from tax credits to be largely recognized next year. Due to the late year seasonality of new project commissioning’s, approximately two-thirds of these earnings will occur in the fourth quarter. This year, we expect to commission more projects in the fourth quarter than in 2021 which will benefit our earnings in the year-to-go period, improving the year-over-year comparison of adjusted PTC in our U.S. and Utilities SBU by the end of the year. Now to our 2022 parent capital allocation plan on Slide 18. Sources reflect approximately $1.6 billion of total discretionary cash, including $900 million of parent free cash flow, $500 million of asset sales and $200 million of new parent debt. On the right-hand side, you can see our planned use of capital. We will return nearly $500 million to shareholders this year. This consists of our common share dividend, including the 5% increase announced last December and the coupon on the equity units. We plan to invest approximately $1.1 billion in our subsidiaries as we capitalize on attractive opportunities for growth. About half of these investments are in renewables, which represent the largest portion of our growth. Nearly a quarter of these investments are in our U.S. utilities to fund rate base growth with a continued focus on grid and fleet modernization. In summary, nearly 3/4 of our investments this year are going to grow AES' renewables businesses in our U.S. utilities, reflecting our commitment to continue executing on our portfolio transformation. In addition, approximately 70% of our planned future investments are targeted for our U.S. subsidiaries, which will contribute to our goal of more than 50% of our earnings coming from the U.S. in 2023. I look forward to AES continuing our strong performance this year and sharing updates with you on our fourth quarter call. With that, I'll turn the call back over to Andres.

Operator:

[Operator Instructions] We have our first question comes from Insoo Kim from Goldman Sachs. Insoo, your line is open.

Andres Gluski:

Yes. Insoo, what I'd say is that we're seeing very strong demand, especially in the U.S. market, especially among C&I customers. So really, I don't think it's an issue of demand. It's really an issue of having permitted projects that can meet our clients' demand in the different markets. So regarding the -- our growth rates, we feel very confident about achieving our 7% to 9%. The IRA is obviously a positive to this number. But we expect some adjustments in the market. So it's not only a question of growth. It's really a question of the profitability of those projects. So what we expect over the next, I'd say, months or year is there to be somewhat more, let's say, scarcity of projects as demand increases. So I think that's where people who have gotten ahead of this and really have a mature pipeline are going to be in a substantial benefit. Obviously, the IRA also has a $3 a kilogram incentive for green hydrogen, and this is also going to be a plus for the growth of renewables and the growth of AES. So all these things I see is positive. But right now, we're saying 7% to 9%. But we're seeing -- as the market becomes more favorable, it's not just a matter of how much you can grow, it's really making sure that you grow profitably.

Andres Gluski:

Yes. I mean, as we laid out, we have structured our contracts such that, for example, if it's a dry year, we have all of the LNG that we need to be able to fulfill our thermal contracts. However, if you have a wet year, then you are able to buy cheaper hydro and redirect those shipments. And I think what's very important is not only having the LNG, but having the capacity to ship that mostly to Europe and really get into the port because as you know, there are really bottlenecks in the port. So I think this really talks about the flexibility that we built in, the strategic relationships we have with LNG suppliers that allow us to take advantage of their position in these markets to move those shipments. So going forward, I mean, basically, when there's a La Nina in Panama hydrology, there's more water available. So we've -- so -- there's also a factor that where -- what's the level of the reservoirs. So it's -- right now, I'd say that we expect the conditions to continue. We -- it's really a matter of the spread between Henry Hub plus the shipping and what international prices are. So as Steve mentioned, we expect -- we have some additional contracts coming in, in the fourth quarter. And regarding next year, it's really are the conditions there? Is there water in the reservoirs? Is the hydrology positive? Is there the spread between Henry Hub, again, plus shipping and international prices? So those are the conditions given. So this is mostly an upside, let's say, going forward. We're not counting on it. And regarding the tonnage, we would expect somewhat less next year than we have shipped this year in terms of the actual volume. We can get back to you on the actual volume that was shipped.

Richard Sunderland:

I mean one of these broader play in inflation, thinking about the outlook through 2025 and the broader inflation backdrop, how do you see the cost savings opportunity through 2025 currently standing versus your Analyst Day plan?

Steve Coughlin:

This is Steve. I would just add also, if you look at the escalation of fuel prices on the thermal side, they've gone tripled in some cases. So renewables, although the costs have increased are relatively more competitive than they were before this current inflationary cycle. And then in addition, we have the benefit with renewables, we're largely firming up prices right around the time that we're also signing up our PPA. So you have a good sense of what your levelized cost is over the life of the project and very little variable costs, of course. So we are able to build in this into the market. And then, of course, the IRA bill in the U.S., certainly with the expansion and extension and re-upping of credits, does serve to offset some of these additional inflationary increases in the renewables capital cost. So that's as an opposing effect, helping bring prices somewhat back down off of what they otherwise would have been.

Steve Coughlin:

Yes. Certainly, transferability. I mean what we like about the IRA is it brings a lot of optionality, a lot of flexibility. It brings the production tax credit as an option for solar. And certainly, that could be a opportunity for high installation is in the southwest of the U.S., for example, may be the best option. So with transferability, it certainly adds more liquidity to, I would say, a more liquid market to monetizing the tax attributes. There are still some significant benefits to having tax equity partnerships, though, where you have the tax depreciation benefit in addition to the credit that you're monetizing as well as just in the way these projects get structured, there's a step-up in the value of the assets when they're contributed to a partnership and there's a benefit to the value of the tax attributes when that occurs as well. So it does add some optionality, flexibility. And so for us, it's good to have in our toolkit. And then down the road, we'll look to see as AES moves forward in time, we may be able to utilize some of these tax credits for our own account, but I wouldn't expect that until several years down the road.

Angie Storozynski:

So first, just one clarification. So Stephen, you talked about the ITC contributions from the new build this year and the carryforward for 2023. Is there some change here versus how you have been accounting for these? I mean, I'm just trying to make sure that it's not somehow related to the IRA and some different recognition of the tax attributes.

Angie Storozynski:

And secondly and probably most importantly, so I remember a couple of quarters back, you guys had the seemingly lost growth targets. 4.5 to 5.5 gigs of PPAs per year. It seems like you're tracking well against that. I'm just wondering if there's any upside to that number. And even more importantly, it seems like you guys have more than 5 gigs of capacity under construction. And so I'm just hoping to get some reassurance how you're coping with that level of activity? And if you -- if there is a possibility to increase it and how, again, like logistically, can you handle that many projects?

Angie Storozynski:

And my last question about the financing of that incremental growth, especially in this higher interest rate environment. So I mean, are you revisiting the past idea of more of like a systematic recycling of capital from your existing assets? Is there again, especially ahead of the announcement for green hydrogen projects. I mean I'm assuming that, that comes with a pretty aggressive capital outlays. So how do you finance it?

Operator:

Our next question comes from Nick Campanella from Credit Suisse. Nick, your line is now open.

Steve Coughlin:

Yes. No, happy to. This is Steve. We are being very strategic. And I'm sure you saw that we did file for an electric security plan for, so our ESP 4 very recently. So we are still awaiting the decision from the utility commission on the rate case that's outstanding. We are expecting that decision still before the end of the year. . But look, the issue at hand is whether rates need to be frozen while we currently have this rate stability charge that's been in place for about 20 years. We think there is broad support for the new rates that are -- have been asked for in the plan and the staff came out and supported those. So what we decided to do was go ahead and chart a path to moving on to a new ESP regardless of what this outcome is in this case. And therefore, that clock has already started ticking. As Andres said, we'd expect that to be resolved by middle to second half of next year on the ESP 4. And our focus is really on growing the utility. As Andres said, this is a utility where we have the lowest rates by far across all customer classes. We want to get to a place. There's a significant opportunity for upgrades and investments, and we want to have a healthy structure from which to continue investing in a healthy balance sheet for the utility. So the ESP 4 was filed to give that path there. We still believe in the case that we filed and that the stability charge can still be in place. But in the case that the commission decides they want to hold rates until that stability charge is retired, then we'll have this ESP 4 path -- it's already out there. It's already being in the process, and we'll have that then by the middle of next year as opposed to waiting for this to be decided and then going ahead and creating what's the next security plan. So that was our goal and our thinking here. And as I said, we still expect a decision this year on the case.

Julien Dumoulin-Smith:

Congratulations on the continued success here. If I can, just to pivot back to where we started with some of this conversation. I want to try to get back at some of the tax credit dynamics and how that plays itself out over the next few years. So clearly, you all have outperformed on continued backlog generation and bring into construction. Can we talk about some of the cadence of in-service here and how that translates back to credit? I appreciate the detail on '22 about what that means on an income basis. But can you talk a little bit relative to the earlier guidance, what was embedded as far as earnings expectations? And then try to transpose that against where we are against the current cadence of when is that construction progress going to reach in-service? When is that backlog effectively fully in service, right, i.e., over the next 2 or 3 years? I just try to reconcile prior versus today on the updated backlog as well as considering the pivot to a solar PTC from an ITC, which also may meet be something of an offset to the positives described here?

Julien Dumoulin-Smith:

Sorry, I know a lot take it as you will.

Julien Dumoulin-Smith:

And if I can, just to clarify, if you don't mind, just to jump in, the cadence by year rather not by intra-quarter kind of thing, but by year breaking down that 11 gig, if we can. Just -- again, I'm just trying to reconcile the older expectations versus newer and try to understand how many gigs per year you can kind of credibly expect?

Steve Coughlin:

Yes. And Julien, so I would say, also taking the number -- Andres said 4 gigawatts next year, that will continue to grow. This is our main growth business for us. It's 5 gigawatts, 6 gigawatts. We'll give more color on that next year as we update our guidance. And then I would look at that and say that roughly, on average, say, two-thirds of that is in the U.S. And then a larger share of that is solar and solar plus storage of that that's in the U.S. So say, roughly 75% today is solar, solar plus storage of the U.S. backlog. And so that's ITC qualified. We can't elect PTC now, as I said, we're looking at that where it makes sense for the returns, and that's typically where you have higher capacity factors, where the installation is high as, say, the Southwest of the U.S. The credits will continue to increase significantly. I think next year is on is going to be a big jump year-over-year because the level of commissioning is going way up next year. And it is heavily weighted towards the fourth quarter of the year. But as we continue to grow this business, the timing will become less of an issue as we get to more of a consistent state of additions year-over-year. But the credits are an important part of how it's monetized and wanted to show that given the IRA and also given how the U.S. Utilities SBU seasonality is becoming more shaped by the renewables, the clean energy business in the U.S. but it's important for everyone to understand what that looks like for modeling purposes.

Ryan Levine:

I wanted to follow up on some of the ITC clarifications. So as you're looking for the U.S. portion, what adders are you assuming that you'll be able to realize as you move forward with these projects? And specifically, are you seeing any low mineral income adders anticipated for your solar projects and both in your current portfolio? And then on a go-forward basis, are you looking to evolve what types of projects you're pursuing in light of the details of the IRA?

Ryan Levine:

Correct.

Ryan Levine:

And then in terms of the transferability comments, as you're looking to make decisions around whether or not to use tax equity partners or utilize the transferability feature. Has that fully been determined at this point? Or is there still some negotiation or analysis that needs to do to determine how you'll structure for future deals?

Operator:

We have our last question comes from Gregg Orrill from UBS. Gregg, your line is open.

Andres Gluski:

Yes. Gregg, I would say, look, -- what we said is that there are -- there is a continuation of this into the fourth quarter, a bit smaller. There's a possibility for next year. And that will depend on the spread between, again, Henry Hub plus prices that we get on our contracts and prices in Europe. So that's really the importance. I think in terms of the hydrology, we need continued good hydrology in Panama, and reservoirs are quite high. So we're going in, in a favorable condition. So it really is what will be the spreads that justify this making that shipment. And I would say also, we would expect less volume in any case next year than this year. So it would be an upside. We're not counting on a very large amount of LNG. So conditions, it looks like it's a possibility, but we're not counting on it. And those are the drivers. And so I think you can see how those drivers are moving and see there's a possibility for this.

Gregg Orrill:

Does where you end up this year? Obviously, you've said at or near the top of earnings guidance. Does that have an impact at all on how you think about giving '23 guidance? Does it serve as a base or some kind of reference point? Or are you still sort of pointing back to a different base?

Steve Coughlin:

Yes. And that was my -- yes. It's a very good year. I think there's more upside, as Andres said. But I wouldn't say it's such a new baseline because this isn't necessarily a recurring at this level thing.

Susan Harcourt:

We thank everybody for joining us on today's call. As always, the IR team will be available to answer any follow-up questions you may have. We will look forward to seeing many of you at the EEI Financial Conference later this month. Thank you, and have a nice day.

Susan Harcourt:

Thank you operator. Good morning and welcome to our second quarter 2022 financial review call. Our press release presentation and related financial information are available on our website at aes.com. Today, we will be making forward-looking statements. There are many factors that may cause future results to differ materially from these statements, which are discussed in our most recent 10-K and 10-Q filed with the SEC. Reconciliations between GAAP and non-GAAP financial measures can be found on our website along with the presentation. Joining me this morning are Andrés Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; and other senior members of our management team. With that, I will turn the call over to Andrés.

Steve Coughlin:

Thank you, Andrés and good morning, everyone. Today I will discuss our second quarter results 2022 parent capital allocation and 2022 guidance. Turning to our financial results for the quarter beginning on Slide 12. I'm pleased to share that we had a good second quarter in line with our expectations which keeps us well on track for our full year guidance. Adjusted EPS was $0.34 versus $0.31 last year, driven by growth in our core business segments higher margins primarily at AES Andes and a lower adjusted tax rate. These positive contributions were partially offset by the higher share count as a result of the accounting adjustment we made for our equity units, higher parent interest expense related to growth funding and onetime outages at select thermal businesses. These outages were primarily driven by turbine manufacturer component defects and the plants impacted are now all back online. There are two additional points I would like to highlight from the second quarter. First, we successfully closed several nonrecourse subsidiary financing, extending tenures at very attractive rates and expanding facilities that support our renewables growth. And second, our collections and days sales outstanding in all of our businesses remain strong reflecting our predominantly investment-grade rated customer base. Turning to side 13. Adjusted pre-tax contribution or PTC was $304 million for the quarter, which was relatively flat year-over-year consistent with the drivers I just discussed. I'll cover the performance of our strategic business units or SBUs in more detail over the next four slides beginning on slide 14. In the US in Utilities SBU, lower PTC was driven primarily by outages at Southland and AES Indiana as well as lower contributions from AES Clean Energy due to increased investment in renewables development. Contributions from new clean energy project commissionings will be more skewed to the second half of the year. Higher PTC at our South America SBU was mostly driven by higher contributions from AES Andes resulting from our increased ownership as well as higher margins, but partially offset by the outages I previously mentioned. Higher PTC at our Mexico Central America and Caribbean or MCAC SBU, primarily reflects favorable market conditions caused by better hydrology in Panama. As Andrés discussed the reduced need for thermal generation in Panama has allowed us to sell our excess LNG on the international market at higher prices, which will serve as a positive driver in the remainder of the year. Finally in Eurasia, while our business performance has been very strong the lower PTC reflects higher interest expense coming from additional non-recourse debt at one of our Eurasia Holdco. Now to slide 18. We are on track to achieve our full year 2022 adjusted EPS guidance range of $1.55 to $1.65. Our typical quarterly earnings profile is more heavily weighted toward Q3 and Q4 with about two-thirds of our earnings occurring in the second half of the year. We continue to expect a similar profile this year as we grow more in the US where earnings are higher in the second half based on solar generation profiles, utility demand seasonality, the commissioning of more new projects in the third and fourth quarters and higher demand at Southland and the peak cooling months in Southern California. Growth in the year to go will be primarily driven by contributions from new businesses including 1.4 gigawatts of projects in our backlog coming online over the next six months as well as further accretion from our increased ownership of AES Andes, higher LNG revenues and growth at our US utilities. We are also reaffirming our expected 7% to 9% average annual growth target through 2025 based on our expected growth in renewables energy storage and US utilities. Our guidance also assumes the recycling of capital from many of our thermal businesses into those three growth areas across our portfolio. Now to our 2022 parent capital allocation plan on slide 19. Sources reflect approximately $1.6 billion of total discretionary cash including $900 million of parent free cash flow. Due to timing uncertainty around our planned asset sales, we are now expecting to achieve the lower end of our $500 million to $700 million asset sales target within the year with the remaining sales expected to close in 2023. To fund our strong growth expectations until the asset sales are completed, we plan to issue approximately $200 million of new parent debt which was already included in the long-term capital allocation plan we laid out earlier this year. On the right-hand side, you can see our planned use of capital. We will return nearly $500 million to shareholders this year. This consists of our common share dividend including the 5% increase we announced last December and a coupon on the equity units. We plan to invest approximately $1.1 billion in our subsidiaries as we capitalize on attractive opportunities for growth. About half of these investments are in renewables reflecting our success in securing new long-term contracts during 2021 and our expectations for 2022. Nearly one-quarter of these investments are in our US utilities to fund rate base growth with a continued focus on grid and fleet modernization. In summary, nearly three-quarters of our investments this year are going to grow AES' renewables businesses in our US utilities, reflecting our commitment to continue executing on AES' portfolio transformation. We have made great progress on our growth investments so far this year and remain on track with our annual investment targets. We will continue to allocate our capital in line with our strategy to lead in renewables, grow our utilities by 9% annually and to recycle capital out of thermal assets to decarbonize our portfolio. With that, I'll turn the call back over to Andrés.

Operator:

Thank you. [Operator Instructions] Our next question comes from Insoo Kim from Goldman Sachs. Insoo, your line is open.

Andrés Gluski:

Yes. Good morning Insoo. Look what we're saying is that there is a number of very good opportunities, which would be certainly made more likely by the IRA bill. And one of them for example is green hydrogen in the US. We'd also expect greater demand from utilities and corporate customers as well. So it's generally. So rather than say we're going to exceed that it certainly would push us towards the higher end if these come true. So that's how I would think about it.

Andrés Gluski:

Yes. I mean, I think there will be discrete projects potentially in green hydrogen. And also you would see it in the number of renewables that we signed in the US.

Andrés Gluski:

Well, this starts in 2024. I would say that the major component is the security of supply. As we've seen this just this week, having a domestic manufacturing is very beneficial. You'll also see that Fluence came out with an announcement that they're going to manufacture their modules in Utah, here in the States. So, I'd say, look, it's large enough that it should be cost competitive and so this would be incorporated and we have to see what is the market clearing prices here in the US for solar projects. Now as we talked about in the past, most of our projects in the US are bilateral, negotiated with corporate clients. We're not just adding a generic clean kilowatt hours, we're you're also adding other features and more value for our customers. So, I think this will help us be more cost competitive. I think that -- but, the most important factor is that it will insulate us from any sort of trade restrictions in the future on the imports of solar panels from Asia. So that is the -- I think the main benefit.

David Arcaro:

Hi. Good morning. Thanks so much for taking my question. I was wondering on the pace of PPA signings here. What's the pace we should expect through the rest of the year? We've seen, I guess, a bit of a slowdown in the second quarter with the uncertainty around the tariff. But what's your confidence level right now in still achieving that 4.5 gigawatt to 5.5 gigawatt level by the end of the year?

David Arcaro:

Got it. Okay. No, that's great to hear. It sounds like active dialogue going on obviously. And then, I just -- I wanted to touch on foreign exchange. We've seen some sizable moves in the foreign exchange rates. But are you seeing -- or any way you could quantify the potential kind of drag there is some impact on future years? And if efforts are kind of underway to look for offsets and to manage that any downside exposure there?

Andrés Gluski:

Yes. I would add also that, part of that is Bulgaria.

Andrés Gluski:

Which is euros.

Andrés Gluski:

So if you look at between dollars and euros, you're probably getting to about 95%. So we're very much in strong currency. This is, again, a decade of work and with the great job that the finance team has done in shaping our portfolio, but also making sure that the new contracts we sign are primarily in dollars.

Andrés Gluski:

Thank you.

Durgesh Chopra:

Hey, good morning, Steve and Andrés. Breaking news in the 500 megawatts. Can you -- is that what, with one customer? Congrats, by the way. Is that with one customer or is that multiple customers?

Durgesh Chopra:

Excellent. Congrats on that. Okay. So I wanted to kind of dig in a little bit on the alternative minimum tax and how do you think that impacts you and your business. I mean, I think, the last time we talked about it, the headwind was offset by credits. Maybe just talk to that. And then, Andrés, I'd love to get your views on this transferability concept that is introduced in the bill. How do you think that works?

Andrés Gluski:

Yes. Regarding your question on transferability, this is being able to sell tax credits to third parties. We don't see like a major impact, but we see it as an additional tool in our cash management practices. So that's favorable.

Durgesh Chopra:

Got it, okay. I appreciate it certainly. So thank you for the discussion. Maybe just a really quick follow-up, Steve when you say several years out on the alternative minimum tax is that because of your U.S. businesses are not of that $1 billion threshold. Is that why it is, or when you say several years out, what does that mean?

Durgesh Chopra:

Got it. Thanks for the time guys.

Operator:

Thank you. Our next question comes from Richard Sunderland from JPMorgan. Richard, your line is open.

Steve Coughlin:

Yeah. So the $0.08 of renewables, yeah, I feel very good about both of these buckets frankly. So the renewables is both the growth in new projects as well as we do have some higher generation out of our hydro portfolio. As you recall last year was a poor hydro year. So that's in that bucket as well. And then, on the utilities and LNG side, as Andrés mentioned, we've had -- we've been really on the right side of things with the commodities this year. So LNG international prices are quite high. We have LNG position of course in our MCAC unit, specifically in Panama where we've had quite a wet year we've been able to not use that gas in Panama and redirect those cargoes and sell them on the international market. So there -- while that's not in the year-to-date, it is a year to go favorability. So that's a little over half I would say of that $0.08. We've got some additional utility growth baked in for the second half of the year. Those are the two primary components of that $0.08. And frankly, I see potential for even more upside. So that's -- and then, I think you asked about Ohio as well. So with Ohio where, -- as Andrés said in his comments, we don't yet have a decision. It's not something that we had a material contribution assumed from the new rates this year. So certainly we look forward to a decision continue to expect a constructive outcome. But it's not going to be a driver one way or the other for this year.

Steve Coughlin:

Well, as we said in the past we are looking at partnerships with producers of hydrogen to actually get more integrated in the whole production chain. So, what's very interesting is that the problem of producing cheap green hydrogen is very much like supplying 24/7 100% green energy or carbon-free energy to data centers. So, we think we have a leg up here. So, we're working on this. If the legislation passes then it's very likely to move forward. So, that's what we've been waiting for. In the meantime in Chile we have a different project which obviously does not depend on this. And that would be much more to supply the local market. And we have done a very good job of decarbonizing the Chilean system and the mining sector in particular. So, we feel good about both of these and these would be significant projects. So, they would accelerate the growth of renewables because of the additional demand.

Steve Coughlin:

Yes. So it was actually Southland and also it was the same root cause at Indiana. So, there are veins on the turbine compressor unit I understand. So, don't go to go into too much detail but they -- there's a failure of component related to manufacturing defect. And so those units both have replacements in Eagle Valley in Indiana and our Southland the New Southland combined cycles in the gas turbine. So, those have been replaced. They are both back online at this point.

Steve Coughlin:

Thank you.

Angie Storozynski:

Thank you. So, I wanted to go back to the Ohio rate case. I understand that it has no impact on the timing of the those decision on 2022, but it will have on 2023. I mean by all accounts it sounds like you will have to file an ESP. So, it might take time right to the final of the resolution? So, there should be an impact in 2023. And so in that context I mean can you -- I mean you mentioned that there is additional optionality around the LNG cargoes that could impact 2023. So, is it fair to assume that any impact by the shifting of the LNG cargoes also in 2023?

Andrés Gluski:

And Angie, maybe to describe a little bit the opportunity in Panama. We have hydro, but we also have the LNG re-gasification terminal being at Henry Hub prices. Of course, Henry Hub prices plus transportation liquefaction re-gasification. But nonetheless, it's kind of a one-sided bet, because we have enough cash to fulfill our contracts, but we had the opportunity, if there is a lot of water a lot of water in the reservoirs to not burn, and therefore ship those cargoes to international customers at obviously the international rates. So there's a very interesting arbitrage opportunity there. So it's a one-sided bet. If it stops raining, or if the reservoir levels fall then we'll just consume the gas and fulfill our contracts.

Andrés Gluski:

Yeah. So look, it's been raining a lot. So the rainy season has started. The reservoirs are full and that's why we're able to make these sell gas to international customers and get that arbitrage. What I'm referring to more really would be 2023 do these conditions persist, or does say 2023 start off being a very dry year. So for 2022, we're locked in. It's really a question of will this opportunity repeat in 2023.

Andrés Gluski:

Yeah. Well, of course, I think it helps repowering and add-ons. What we have to see is that, we already have contracts in these places. And so the question is, do we negotiate an additional contract from that location based on – we've done repowering already we're starting to – we've been repowering units in California at Mountain View, and also we plan to do some in Maryland at Laurel Mountain. So this helps those to happen, and you're right. It does -- one does have to look at what you have existing and what additional opportunities there, but since we are on the renewable side pretty much fully contracted then the question would be that additional energy do you -- is there an adder that you could add to the same client to keep it simple, or what are the opportunities there? But you're right, this is an upside that's smaller so we haven't talked that much about it.

Andrés Gluski:

Sure. You noticed it was in our press release. First, so I'd say, look this is a -- we're in Vietnam. We're helping the Vietnamese come up with a plan to decarbonize their grid. So we do have the LNG terminal project there. And we are -- have been talking about bringing in energy storage and other renewables. So, to eliminate the need for additional coal plants. So at this point, I'd say, this was more sort of an exploratory issue. We will be very disciplined and committed to all the goals that we've given 50% US, 50% renewables. Now whenever we get into a new technology, we'd obviously have to partner with somebody. So we haven't done any offshore wind, because it didn't make sense economically. The markets we're in like the US, there's still plenty of land and it just really wasn't cost competitive. But we have nothing, let's say, against the technology itself. But of course, we would have to partner with somebody who has a long experience. And so we're not going to get into a new technology in a large scale on our own at this time. And so this was -- again, this is not an announcement from us and what we guarantee is we're going to stick to the exact goals that we have given you.