Hello, everybody, and welcome to The AES Corporation Q1 2025 Financial Review Call. My name is Emily, and I'll be moderating your call today. I will now hand the call over to Susan Harcourt, Vice President of Investor Relations to begin. Susan, please go ahead.

Thank you, operator. Good morning, and welcome to our first quarter 2025 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 Andrés Gluski, our President and Chief Executive Officer; Steve Coughlin, our Chief Financial Officer; Ricardo Falú, our Chief Operating Officer; and other senior members of our management team. With that, I will turn the call over to Andrés.

Good morning, everyone, and thank you for joining our first quarter 2025 financial review call. Today, I'm very pleased to reaffirm both our 2025 guidance and long-term growth rate targets, which reflect our strong execution to date as well as the resilience of our business overall. I will discuss this in more detail and provide an update on the robust growth program at our U.S. utilities. Following my remarks, Steve Coughlin, our CFO, will provide additional color on our financial performance and outlook. Beginning on Slide 3 with our first quarter results. Our financial performance was in line with our expectations with adjusted EBITDA of 591 million and adjusted EPS of $0.27. We completed the construction of 643 megawatts and signed or were awarded 443 megawatts of new PPAs, bringing our backlog to 11.7 gigawatts. We have achieved our asset sale proceeds target for the year, including the sale of a minority stake in our global insurance company, AGIC, for 450 million. Now turning to the resilience of our business model and portfolio. Our execution is proceeding as planned, and we expect to hit all of our financial metrics for the year. We have positioned ourselves for success even in the face of uncertainty around tariffs, changes to the Inflation Reduction Act, or potential recession. Our business model is based on long-term contracted generation with creditworthy offtakers as well as growth in our U.S. regulated utilities. Our contracting, financing, and supply chain strategies have all been designed to minimize the impact of economic conditions, including inflation, interest rates, energy prices, and tariffs. As a result, we have clear visibility into our future financial performance. I'll first discuss the performance of our renewable business and then address the ways we have ensured that this business is resilient to macroeconomic and policy shifts. Turning to Slide 4. A major driver of our renewables EBITDA growth this year is the approximately 3 gigawatts of new projects we expect to bring online. I'm pleased to say that we are fully on track with more than 600 megawatts already completed, including the 250-megawatt Morris Solar project in Missouri serving Microsoft. Our remaining projects under construction for the year are now approximately 80% complete. Our 1 gigawatt Bellefield 1 project, which includes 500 megawatts of solar and 500 megawatts of storage, is virtually complete, and we will be fully operational this summer. This is the first phase of what will be a 2 gigawatt project and the largest solar-plus-storage plant ever built in the United States, all of which is contracted with Amazon. Moving on to Slide 5. Our supply chain strategy provides us strong protections from any current or potential future tariffs as well as from the impact of inflation. Of the 7 gigawatts in our backlog scheduled to come online in the U.S. between 2025 and 2027, nearly all of the CapEx is protected with zero exposure to tariffs as the equipment is already in the U.S., in transit, or contracted to be produced domestically. Our tariff exposure is limited to a small quantity of batteries that are being imported from Korea for projects coming online in 2026 with a maximum potential exposure of 50 million, which we are actively working to further mitigate. This represents just 0.3% of the total U.S. CapEx and is well within the normal project contingency. I would like to emphasize that our U.S. supply chain protects us from any potential tariffs that could be announced, including reciprocal tariffs. We also serve our corporate customers outside the U.S. where we continue to see substantial demand. Contracts that we are signing outside the U.S. are benefiting from lower equipment prices as a result of the increase in international equipment supply, with solar panels typically one-third the cost in Chile versus the U.S. Turning to Slide 6. Our business is also well protected from possible changes to U.S. renewable policy for several reasons. First, we are the top electricity provider to premier corporate clients, including data center customers that require capacity that can come online relatively quickly. We have signed agreements for 9.5 gigawatts with data center companies, more than anyone else in the sector. There are a few others in the industry who can develop, build, and operate the projects we offer, which are often large, geographically diverse, and with customized commercial structures. Furthermore, with our extensive history of working with large corporate customers, our development projects are tailored to meet their specific needs. We believe our customers will have strong demand for renewables in any scenario. Through the end of the decade, Bloomberg New Energy Finance sees increased electricity demand requiring at least 425 gigawatts of new capacity. While AES is committed to serving our customers with an all-of-the-above strategy, including new gas generation, we see renewables as the primary source of new energy to serve this demand for the following reasons. First, they offer the fastest time to power, given their short construction period and advanced permitting and interconnection queue positions. Second, the fact that they are a low-cost source of power, particularly considering the rapidly rising cost of gas turbines and long lead times. And third, the price stability that they offer customers once contracted, unlike thermal power, which is subject to fluctuating fuel prices. In addition, roughly one-third of our backlog is in international markets where we develop, build, and operate renewable projects without tax credits, usually with higher returns than in the U.S. In the absence of tax credit, projects have higher net capital needs, but PPA prices are also higher to account for this funding structure. In these cases, we earn higher EBITDA per megawatt and are able to achieve our financial targets with fewer projects. Turning to Slide 7. Another reason for our confidence in the resilience of our business is that nearly our entire U.S. backlog has Safe Harbor protections. Once a project starts construction or incurs 5% of the cost of materials, the project has Safe Harbor protections and has a period of four years to be placed in service and begin receiving tax credits. For example, any project that reaches start of construction milestones in 2025 is Safe Harbored through 2029. Turning to Slide 8. We're also resilient to any economic downturn. Our business is heavily contracted with approximately two-thirds of our EBITDA coming from long-term contracted generation, essentially all of which are take-or-pay and not tied to underlying demand conditions. Looking to the future, nearly all of our growth through 2027 is already secured through our 11.7-gigawatt backlog of signed long-term contracts. At the same time we sign our PPAs, we contractually lock in all major capital costs, EPC arrangements, and hedge our long-term financing. This approach gives us clear line of sight to our future EBITDA. We have also achieved our asset sale proceeds target for the year with the sale of a minority interest in our captive insurance company, and we have closed the sell-down of AES Ohio. Furthermore, with our March debt issuance, we have successfully completed all financings needed to address our 2025 debt maturities, and we have hedged 100% of our benchmark interest rate exposure for all corporate financings through 2027. Next, I'll discuss the robust growth program we're undertaking at our U.S. utilities on Slide 9. We are executing on the largest investment program in the history of both AES Indiana and AES Ohio as we work to improve customer reliability and support economic development. This year, we're on track to invest approximately $1.4 billion across the two utilities to support areas such as hardening the distribution network, smart grid, new generation, and transmission buildout for data centers. We signed agreements for 2.1 gigawatts of new data centers in AES Ohio's service territory. We are beginning construction on new transmission to serve this load. This summer, we'll be breaking ground on the $500 million transmission investment needed to serve a new Amazon data center in Fayette County. Additionally, last month, we completed the sale of a 30% stake in AES Ohio for $544 million to CDPQ, a global investment partner that also owns 30% of AES Indiana. This partnership helped support capital requirements for their substantial growth programs while also strengthening our balance sheet. Now turning to AES Indiana. We're continuing to invest in new generation to support our customers with affordable and reliable power. In March, we brought online the Pipe County Energy Storage project, which includes 200 megawatts of installed capacity and 800 megawatt hours of dispatchable energy, the largest operational battery project in MISO. We continue to make progress on the Petersburg Energy Center, a 250-megawatt solar and 180 megawatt hour energy storage facility, which we expect to be operational by the end of the year. And in April, we received final regulatory approval for the 170-megawatt cross-buying solar-plus-storage project, which we expect to bring online in 2027. With that, I would now like to turn the call over to our CFO, Steve Coughlin.

Thank you, Andrés, and good morning, everyone. Today, I will discuss our first quarter results, our 2025 full year guidance, and our parent capital allocation plan. Turning to Slide 11. Adjusted EBITDA was $591 million in the first quarter versus $640 million a year ago. This decline was anticipated in our guidance and was primarily driven by prior year revenues from the accelerated monetization of the Warrior Run PPA and the sale of our 5-gigawatt AES Brazil business but partially offset by growth in our renewables and utilities businesses. Turning to Slide 12. Adjusted EPS for the quarter was $0.27 versus $0.50 last year and was also in line with our expectations. Drivers include the prior year Warrior Run PPA monetization, the timing of U.S. renewables tax attribute recognition, higher parent interest, and the prior year tax benefit associated with our transition to a more U.S.-oriented holding company structure. This was partially offset by higher contributions from our utilities SBU. I'll cover the performance of our SBUs or strategic business units on the next four slides. Beginning with our renewables SBU on Slide 13. Higher EBITDA of approximately 45% year-over-year was driven primarily by contributions from new projects, which includes projects brought online over the prior four quarters. In addition, the renewables segment now includes all of our renewables in Chile which were a part of the energy infrastructure SBU in prior years. This change was offset by the EBITDA impact from the sale of AES Brazil in the fourth quarter of last year. With this quarter's results, we are fully on track to achieve our full year renewables SBU guidance of $890 million to $960 million. Our construction program is proceeding on schedule. Cost savings measures have been implemented, and we have already seen hydrological conditions in Colombia normalize year-to-date. In other words, our main segment drivers are greatly derisked, and we're well on our way to achieving 60% renewables growth year-over-year. Turning to Slide 14. Higher adjusted PTC at our utilities SBU was mostly driven by tax attributes from the completion of the Pipe County Energy Storage project, new rates implemented in Indiana in May of last year, demand growth, and favorable weather in the U.S. Lower EBITDA at our energy infrastructure SBU primarily reflects prior year revenues recognized from the accelerated monetization of the coal PPA at our Warrior Run plant as well as Chile renewables moving to the renewables segment. Finally, lower EBITDA at our new energy technologies SBU reflects lower contributions from Fluence in the first quarter. Now turning to our guidance beginning on Slide 17. We are reaffirming our 2025 adjusted EBITDA guidance of 2.65 billion to 2.85 billion. We continue to see strong growth in our renewables SBU and expect our utilities businesses to grow approximately 7% this year despite the sell-down of AES Ohio. The cost savings actions we announced on our February call have already been implemented. We expect 150 million in cost savings in 2025 will primarily benefit the second half of the year, and we remain on track to achieve a full run rate of over 300 million of cost savings next year. We are also reaffirming our 2025 adjusted EPS guidance of $2.10 to $2.26. As you can see on Slide 18, we expect growth in the three remaining quarters of this year to be driven by adjusted EBITDA growth in renewables and utilities and monetization of tax attributes on new renewables projects, partially offset by higher interest and a higher adjusted tax rate. Now to our 2025 parent capital allocation plan on Slide 19. Sources reflect approximately 2.7 billion of total discretionary cash, including 1.2 billion of parent free cash flow, which represents more than an 8% increase versus 2024. We also expect 700 million of planned parent debt issuance and closed the 450 million sell-down of a minority interest in our global insurance business earlier this week. Our captive global insurance business is a valuable asset within the AES portfolio that consistently produces attractive cash flow while managing property and business interruption risk within our operating portfolio. This structured transaction allows us to monetize a minority portion of this valuable business to support growth capital for renewables and utilities businesses. With this transaction, we have achieved our entire asset sale target for 2025. 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 2% dividend increase announced last December. We also plan to invest approximately 1.8 billion toward new growth and have already repaid roughly 400 million of subsidiary debt. With the sell-down of a minority interest in AES Ohio at the beginning of April, we now have CDPQ as a 30% partner in both of our U.S. utilities. This partnership is another example of how we use private capital to help fund growth and reduce parent investment requirements into our subsidiaries. Finally, turning to Slide 20. Our credit metrics are progressing in line with our expectations, benefiting from the actions we've taken since the beginning of this year. With the sell-down of our global insurance business, we have locked in our asset sales proceeds for the year. The sell-down of AES Ohio and subsequent debt paydown enabled S&P's recent one and two-notch upgrades for DPO Inc. and AES Ohio, respectively. We have also refinanced this year's parent debt maturity and have already fully hedged the benchmark on all expected parent financing through 2027. Additionally, we implemented cost efficiencies and resized our development business to generate over 300 million in annual savings by next year. These actions provide us with a fully self-funded plan through 2027. In summary, I am very pleased with our results this quarter, which were fully in line with the guidance we gave in February. We expect significant growth in the year to go that will come from projects that have already been brought online but which are still ramping to their full EBITDA, rate base investments that have already been made, and cost reduction actions already implemented. I am confident we will achieve our guidance regardless of changes in the economic environment or changes in policy due to our focus on regulated utilities and long-term contracted generation, which has minimal volume interest rate for foreign currency exposure. I look forward to providing an update on our progress on our second quarter call. With that, I'll turn the call back over to Andrés.

Thank you, Steve. In summary, our long-term contracted business model continues to demonstrate its resilience to tariffs, economic policies, and business cycles. Our first quarter results are in line with our expectations, and we are reaffirming our 2025 guidance and long-term growth rate targets. Demand from our core corporate customers remains very strong, and we're seeing no slowdown in the energy needs of hyperscalers in any scenario. As a result of our strategy to be a first mover in creating a domestic supply chain and working with existing suppliers to onshore imported equipment, the tariff exposure on our 11.7-gigawatt backlog is negligible. Similarly, our construction program of 3.2 gigawatts this year is on track and well advanced. We have completed construction of 643 megawatts, and we are 80% complete for the remaining 2.6 gigawatts, including 99% complete on the 1-gigawatt of our Bellefield project, which will be the largest solar-plus-storage project in the U.S. Our two utilities are among the fastest growing in the country, and we continue to make progress on attracting new data centers to our service territory. And lastly, we have already completed all of our major asset sales and financings for the year, solidifying our commitment to self-funding through our long-term guidance period. With that, I would like to open up the call for questions.

Thank you. We will now begin the question-and-answer session. Our first question comes from Julien Dumoulin-Smith with Jefferies. Please go ahead, Julien.

Hi, good morning, team. Thank you guys very much. I appreciate the time and the opportunity here. Nicely done on this insurance transaction. Actually, if I can just start off a little bit of housekeeping there. How do you think about that transaction just in terms of the prospective EBITDA impact, just when you think about the financials here? I mean again, innovative idea in how to raise kind of equity indirectly, right, from private capital as you say?

Good morning, Julien. I'm going to pass that question to Steve.

Yes, good morning, Julien. The EBITDA impact is expected to be in the 25 million to 30 million range. So overall, given that we've raised 450 million, we're reinvesting that in returns of 13%, 14%, 15%. It's very accretive for us, so very pleased. This was an opportunity that we have seen quite a while ago. It had been part of the universe of potential asset sales. And so we've anticipated for some time, we did include it in our guidance in February. And it's effectively the low-cost equity financing that supports growth while also meeting our credit goal. So very happy to complete this early this year.

Awesome. Yes. Nicely done, Steve, I got to say. Neat idea. If I can turn more substantively, right, just to clarify your earlier comments. First, just on the tariff exposure, is it principally that you've got a recovery from your suppliers, i.e., they are taking the risk when you guys provide this 0.3% that effectively the risk burden is effectively put on the vast majority of your suppliers versus going back to your customers? I just wanted to clarify that. And then related, just given the 400-and-change megawatts of origination this quarter given the backdrop today, would you say that this is kind of what we should be expecting for this year? Or could you see some sort of more meaningful uptick? I'm just trying to get a sense of what that cadence should be against setting expectations for further down the line?

So I'll have Ricardo answer the first question and then I'll take the second.

Thank you, Julien. I think let me provide a bit more context on our supply chain. Three years ago, we made the decision of basically building a reliable and U.S.-made supply chain. And guided by that sort of decision, we implemented three actions. The first one was that we entered into strategic partnerships with suppliers with manufacturing capacity outside of China. That was the first action. The second action was that we were a first mover, as Andrés mentioned, in supporting U.S. manufacturing to secure solar batteries and wind components. And third, to bridge the gap as local manufacturing ramps up, we accelerated the import of all the equipment coming from abroad required to support our backlog through 2027. And as a result of these actions, apart from the small quantity of batteries that Andrés mentioned that are for a few projects coming online in 2026, we have no impact on tariff for our 2025-2027 backlog. I think with respect to who bears the exposure, these contracts are with a Korean supplier for a very few projects. Of course, this tariff was not in place at the time we signed the contract and what we are doing, the $50 million represents the full exposure to be shared between the parties. And of course, the first action, as Andrés mentioned, is to actively reduce that exposure, which we've been so far very successful, and for the remaining impact to be shared evenly. So we expect the overall impact to be well below that $50 million that is the total exposure that Andrés mentioned. Other than that contract, we have no exposure to tariffs, yes.

Yes. I'd like to clarify that what we did was we imported all of the equipment, the vast majority of it. So we have all that equipment that we need, for example for 2025 with the exception that we pointed out already in the U.S. and most of it on site. And we have a lot of the equipment for 2026 that's imported as well. So in 2026, we expect to shift over to domestic supply. So when we say that the exposure is negligible, we really got ahead of this. Now I will remind you this is what we did in 2020 as well. In 2020, we achieved all of our targets, and we're the only large developer who did not abandon or significantly delay any large project, and we intend to continue that track record. Now getting your question about the cadence of PPA signings. As we've been saying, look, we're concentrating on fewer, larger projects that are also more financially attractive. So the 400 megawatts is not a cadence that you should expect for every quarter. We are in final negotiations on a number of large projects. We expect it, 4 gigawatts roughly, that we have talked about prior to this year, to hit sort of the three-year target. We had talked about 14 to 17 gigawatts, so we remain on track. And we've always said these are lumpy, so it's not like we're doing a lot of small projects. We're doing a few large ones and sometimes they happen in a quarter, or they happen in the next quarter, or they come together. So there's nothing to be read in the 400 megawatts.

Got it. All right. Excellent guys. Thank you. I’ll leave it there.

All right. Thanks, Julien.

Thank you. Our next question comes from Nick Campanella with Barclays. Please go ahead, Nick.

Hi. Good morning, everyone. Thanks for taking my questions, and I appreciate all the color. I just wanted to come back to the insurance sale quickly. So I know you kind of disclosed the Class B dividends are like $145 million to $198 million. Is that like a yearly number or is that a cumulative number? And I guess if you hit that call option in 2030 to 2035, what is that strike price? And how should we kind of think of the cost of financing here that you just raised versus, I guess, deploying future CapEx at 13% to 15% returns? Maybe you could just unpack that.

Yes, Nick, it's Steve. Those numbers are based on the first five-year target distribution, which represents the total amount that needs to be met by the five-year call date. This aligns well with a conservative estimate of what this insurance business delivers. This business is captive but has reinsurance backing, allowing for predictable maximum losses before reinsurance coverage starts. It was conservatively structured to ensure we can service this financial framework even with maximum losses. Regarding the costs, I would consider them similar to a junior subordinated debt issuance at the parent level. Since this is treated as equity, it essentially represents low-cost equity financing that is quite beneficial. We expect target payments to be in the range of about $37 million to $40 million per year to the counterparty.

Okay, that's helpful. Appreciate that. And I’ll try not to butcher it but just the Cochrane buyout that you disclosed in the 10-Q. Can you just give us a sense of what you're purchasing? And how much you paid for it, either on like a multiple basis or cash and just the rationale behind that transaction?

Yes, look, I mean, this is an asset that we already own and operate. We have a minority partner that was looking to exit. So what we're doing is we're buying up the 40% minority and taking nearly complete ownership of the asset. It's very valuable. It's contracted well into the next decade, serving key customers for us in Chile. And the valuation was at a very low multiple, so it's quite accretive immediately this year and beyond. So we're pleased with it. It's one of the assets that we had already guided that would be extended beyond 2027. So it's no additional new capacity, just taking advantage of an attractive financial return on owning the entire thing as opposed to just the share that we had.

Okay, thank you.

All right. Thanks, Nick.

Thank you. The next question comes from David Arcaro with Morgan Stanley. Please go ahead, David.

Hi. Thanks so much. Good morning.

Good morning, David.

I was wondering on the AGIC sale, just one other follow-up there. You sold a minority stake. I'm just wondering, is there any strategic reason that you want to retain control in the remaining stake there? Or could that be a consideration for future asset sales out in the rest of the program, the financing plans going forward?

Yes. No, we want to maintain our control of this asset. And as Steve said, the financial metrics are very conservative, and we're coming in with considerable margin on this. So we do want to maintain it. It's been very successful. We've set this up about 15, 20 years ago. It was an independent business; it's a unicorn. So it's been very successful, lowered our insurance costs and improved the quality of our reinsurers.

Okay, great. And I was wondering if you could comment on just what you're seeing in terms of latest renewable demand trends. Has there been any pull forward ahead of potential IRA changes here or any just general change in customer demand levels that you're seeing?

Yes, great question. Look, what we are seeing is continued strong demand. We're not seeing any sort of temporal shifts as a result. So our data center customers continued strong demand. I think the key word is time to power. And that's why we mentioned that certainly, for the next five years, the predominance of this is going to be renewables because it's the fastest to power. It's also very cost-effective. And so you can combine this with gas, in many cases, to reach the optimal solution. I think there's too much discussion about the technology and not really what the customer wants. So we combine ways of producing energy in a way that satisfies our customers. So look, we're not seeing any pull forward. We are seeing, I would say, some of the contracts that we're signing today that have provisions for, say, changes in law, changes in tariffs, etcetera, to take that into account. Now for our backlog, as I said before, we have imported the materials or have domestic supply. We have the EPC and we have the financing. So all that's locked in.

Okay, sounds good. Thank you.

Thanks, David.

Thank you. Our next question comes from Durgesh Chopra with Evercore. Please go ahead, Durgesh.

Thank you. Good morning, team. Thanks for giving me time. Steve, congrats on this transaction. Maybe just a little bit more detail. You talked about the cash distributions being conservative. Can you just frame for us the $40 million or so average distributions a year? What is that as a percentage of total cash generated for that business?

Yes, it varies by year but is typically around 35% to 40%. This business generates approximately $100 million in cash, even with normal losses, and accounts for some amortization of the instruments, which allows it to be self-amortizing over the entire 20-year period. Unlike certain convertible portfolio financings that have been mentioned regarding other yieldcos, this does not involve significant economic ownership changes. We have the option to call it at year five, but there is no strong incentive to do so, as it maintains the same economic terms throughout the full 20-year potential. The pricing is akin to a junior parent note, enabling us to access affordable equity capital. We can retain this arrangement unless we find a more cost-effective option in the future. Overall, this approach is a solid method to unlock value from an asset that may be undervalued. Previous disclosures have shown distributions to the parent from this asset, and this capital will be used to achieve mid-teens returns. Overall, it appears quite favorable.

Got it. Thank you for that clarity. Accretive transaction there. Just digging on the financing topic, there's been a lot of discussion around transferability. Some legislation recently proposed or is probably doesn't get much traction. But just in terms of thinking about risks, can you talk about like in an event the transferability is eliminated, do you go back to tax equity and perhaps even frame for us what percentage of your plan is being provided by cash financing, is being provided by transferability? Thank you.

Yes, absolutely, Durgesh. So look, first of all, transferability has only been around for a little over two years since the IRA was passed in 2022. It has been very good for the industry as it's opened up a broader participation in the market for monetizing tax value. And it is typically a little bit more efficient in transferring most of the tax benefit savings on to customers just because there's less friction in these types of transactions. But that said, for the IRA, we did tax equity. The majority of what we continue to do is still through tax equity partnerships. And in fact, we continue to form the partnerships anyway because we need to monetize the tax depreciation to maximize the opportunity even when we are doing transfers. So we can continue to do the tax equity partnerships for all of our future projects if this were removed. We don't think it will be because we think it goes with the tax credits in terms of getting the most benefit of the tax credits to the cost of the end consumer of the energy. And then effectively, the cash benefit to AES is the same. So we bridge the tax financing with debt during construction, as I walked through on the February call. And then we immediately, when the tax value comes in, either from the transfer counterparty or from the tax equity partner, we immediately monetize that at the place and service date and pay down a significant portion of the debt, typically more than 50% at that point. So you have a significant deleveraging from this. The fundamental cash and credit profile is really exactly the same. So I think it's been good, a lot more for some smaller developers and to sort of democratize the participation in the market. But as a large-scale developer with deep relationships with sophisticated tax equity partners, we still feel very comfortable that we can monetize all of the tax value that we create with the tax equity venue if needed.

Thanks, Steve. Appreciate that discussion. Just real quick, sorry, this is my third question, I understand and realize. Just the hydrogen project that was canceled in Texas, are we still pursuing other customers for contracted power generation that I believe it was over 1 gig?

The answer is yes. I mean, that was a very attractive asset of development. It's all on private land on one farm, and it's very well located for the grid and for anything else. So yes, we're continuing to pursue it. It's part of our pipeline, so yes.

Thank you, Andrés.

Thank you, Durgesh.

Thank you. Our next question comes from Michael Sullivan with Wolfe Research. Please go ahead.

Hi, good morning.

Good morning, Michael.

Wanted to just ask on where we stand on the longer-term asset sale target. Are you still shooting for that 3.5 billion? Where are we against that? And what else are you looking at for potential sales?

Yes, this is Steve. We're currently at 3.4 billion, which puts us very close to our 3.5 billion target. During our February call, we mentioned plans to reach between 800 million and 1.2 billion from 2025 to 2027. This recent sale, not including the Ohio sell-down used for debt paydown, contributes to that goal. After this insurance sell-down, we are approximately halfway toward that target. Remaining proceeds include the Vietnam sale and other smaller asset sales in our thermal portfolio, as well as partnerships with operating assets, including our LNG portfolio, which have the potential to expand. We've also established partnerships and sell-downs involving our renewable portfolios at attractive low-cost capital rates. While our technology portfolio, particularly Fluence, is significantly undervalued right now, we remain optimistic about its future potential, though we're not relying on it. Other assets such as Uplight could also be candidates for sale. Overall, we have a larger array of options remaining, with approximately 500 million still to achieve by 2027. I'm very confident that we can reach our goals across the various opportunities I've mentioned.

Okay, great. That's helpful. And back to the IRA discussion here. Do you all have any view on kind of when this starts to take shape in the Reconciliation Bill? Feels like things starting to come to a head a little bit. And then also just specifically on transferability, your view on whether a Safe Harbor would cover you on that even in a scenario where that were to go away?

I spent some time with key senators and congressmen. I expect an initial draft from the House and Ways and Means Committee to kick off discussions. This isn’t the final version, which was made clear to us. The approach seems very pragmatic, emphasizing the importance of reliability, particularly regarding Safe Harboring, which everyone I spoke to considers essential for maintaining the credibility of U.S. laws and programs. I feel positive about this aspect. Regarding the IRA, I anticipate that some elements will be addressed, and it’s likely there will be an earlier sunset, which is where the majority of savings would originate. Overall, I believe the outcome will be pragmatic, as hundreds of thousands of jobs are at stake and many will face elections in 2026. There is a strong incentive to avoid rising unemployment in rural areas where much of this work occurs, along with the tax revenue this will generate. I think we’ll see something relatively soon, but it's important to remember that whatever emerges won't be final. Regarding reconciliation, many believe it should occur before the August recess as members will want to finalize matters before leaving town. The discussions I've had were encouraging, focusing on what's beneficial for the country and what is realistically achievable.

Appreciate that color. Thank you.

Thank you.

Thank you. The next question comes from Richard Sunderland with JPMorgan. Please go ahead, Richard.

Hi, good morning.

Good morning, Richard.

I just wanted to follow up on transferability one more time. On an agency metric basis, what would be the impact to your FFO without transferability, and how do you expect the agencies to treat that?

The transferability remains fundamentally the same in terms of cash and credit profile. The distinction lies in the fact that transfer credits are recorded through operating cash flow. Consequently, it does not affect S&P and Fitch's focus on the parent free cash flow. Instead, it appears at the subsidiary level and is used to pay down debt, and this is reflected in Moody's metrics. We will need to collaborate with Moody's to ensure they have a clear understanding, though I believe they already recognize that there is essentially no change. The cash is received when the project becomes operational, whether it's from a transfer or a tax equity partner, and is used to reduce debt. Therefore, it effectively has no impact. Should we reach that point, we would work with Moody's, as we have in the past, and they have been cooperative in comprehending how renewables operate, including the adjustments they made in their last update. Thus, I do not perceive this as negative for the credit profile.

Got it. That was very clear. So presumably on a Moody's basis, this would push out the improvement you've called out for '26, but you also expect Moody's to look through the impacts, given what you laid out earlier on the value through tax equities being the same?

I mean, look, I can't speak for Moody's, but it's very logical, and we're talking about a geography issue on the cash flow statement. So I have a hard time being that logic won't prevail there, that fundamentally the credit profile is exactly the same.

Understood. And then maybe I'll just follow up with one more. I mean, I think there's been a lot of attention on transferability and maybe some fears out there that this first draft on the IRA could have a lot of negative headlines, then we migrate some more reasonable middle ground. Do you think transferability is something that may come out in that initial draft and then goes back in? Any thoughts on sort of the magnitude of that headline risk initially versus where things might ultimately shake out in your earlier commentary?

No. There are two groups to consider: one focuses on the uses of capital and the other offers a more straightforward perspective. I believe a compromise will be necessary. I don't have specific insight into the initial language, but it's evident that bills serve as starting points for discussions. They originate in the House, must be reconciled with the Senate, and require negotiation. So, anything emerging now is just the beginning, not the conclusion. From my conversations, it seems that discussions have been constructive and positive overall, with an understanding of the key issues, which is crucial. Ultimately, we aim for two primary objectives: energy dominance and leadership in the AI race. Achieving both requires significant renewable energy, and energy in general. For instance, if we order a new gas turbine today, we could face a waiting period of three to five years, not factoring in permitting and interconnection issues. If the outcome is unfavorable for new energy, it would undermine two critical goals of the administration. That's why I believe this understanding exists. I'm cautiously optimistic about the direction it will take, although I cannot predict the political landscape or media reactions. Your speculation is as valid as mine.

Perfect. Thanks for the time today.

Thank you.

Thank you. Our final question today comes from Anthony Crowdell with Mizuho. Please go ahead, Anthony.

Hi, good morning. Thanks for squeezing me in. Most of my questions Richard's taken care of in front of me. Just quickly on Ohio, some legislation passed earlier, I think this week, multiyear rate plans, but also maybe removal of OVEC revenues. Just curious the impact for AES Ohio and does it change your plan on rate filings?

Thank you so much. This is Ricardo. So I will start by saying that overall the impact of the bill is net positive for us, while on one side eliminates the ESP. It's going to be now replaced by a 3-year forward-looking distribution rate case with annual true-up, which is a more constructive regulatory framework in a growing business such as AES Ohio. In addition, the language clearly states that the current ESP4 features will be extended from August 2026, which was the original expiration date, to May of 2027. So, this will give us enough time to have the new rates coming from this 3-year forward-looking framework in place. I think this is very, very constructive. It eliminates regulatory lags, so again, very, very positive for a growing business such as AES Ohio. I think in terms of our timing for filing the distribution rate case, more likely it's going to be by the end of this year. With respect to OVEC, the impact is estimated to be between $0 million and $10 million. Why $0? Because it depends very much on the financial performance of the asset or assets, I should say, because we are talking about 2.3 gigawatts of coal assets that provide capacity to PJM, and we are seeing a significant increase in capacity prices where you may recall they were like around $29, and now $270 per megawatt per day. So it's going to be within that sort of range, $0 million to $10 million depending on the financial performance and capacity prices in PJM. And as I said, all-in-all, net positive, and I think this regulatory framework with a three-year forward-looking is extremely constructive for AES Ohio.

Great. Thanks for taking my questions.

Thank you, Anthony.

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.

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