AES Corp (AES) — Q3 2022 Earnings Call Transcript

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.

Good morning, everyone, and thank you for joining our third quarter 2022 financial review call. This morning, we reported third quarter adjusted EPS of $0.63, bringing our year-to-date adjusted EPS to $1.18. With these results, we now expect our full year adjusted EPS to come in at or near the high end of our guidance range of $1.55 to $1.65. We're also reaffirming our 7% to 9% annualized growth target for adjusted EPS and parent cash flow through 2025. Steve Coughlin, our CFO, will discuss our financial results in more detail shortly. Our business model continues to demonstrate its resilience with strong contractual protections and natural hedges that have insulated us well from foreign currency movements, higher interest rates and volatile commodity prices. In addition, the vast majority of our business is with U.S. utilities or investment-grade off-takers. Turning to Slide 4. At the same time, we have built flexibility into our portfolio, which has allowed us to capture upside in the current environment. For example, in Panama, we've been able to redirect Henry Hub priced LNG to European markets to capitalize on high international gas prices. This upside is the direct result of actions we took in the past to create a diverse portfolio that would limit our downside exposure to fluctuations, both in commodity prices and hydrology. With above-average rainfall in Panama this year, we have been able to buy cheap hydro power and run our gas plant less, which has made it possible to redirect a portion of our contracted LNG creating meaningful upside in our results. Now to Slide 5. We spoke briefly about the U.S. Inflation Reduction Act, or IRA, on our previous call. But since then, it has become even more apparent how it is likely to greatly accelerate the demand for renewables and stand-alone storage in the U.S. We are very well positioned to capitalize on this demand and growth through our market leadership in renewables, particularly in the C&I segment due to our strong customer relationships, our ownership interest influence and our extensive and growing pipeline. Specifically, the IRA extends the production tax credit, or PTC, and the investment tax credit, or ITC, for 10 years and provides additional tax credits for energy communities such as low-income areas or places where coal mining or thermal generation previously took place. We anticipate that the benefits of the IRA will result in a meaningful step-up in demand across the U.S., but particularly from C&I customers looking to reach their decarbonization goals. The IRA also includes a 30% ITC for stand-alone energy storage. AES benefits not only from being one of the largest developers of energy storage projects, but also from our ownership stake influence, the market leader in energy storage integration. We see battery-based energy storage as an essential enabler of more renewables on the grid by reducing intermittency and providing renewables-based capacity. As you can see on Slide 6, to address this expected growth in demand, we have been working hard to grow our pipeline of renewables and energy storage projects. Today, our pipeline stands at 64 gigawatts or more than twice the size of our entire current portfolio. The majority of our pipeline, 51 gigawatts, is in the U.S. and much of it is in the most attractive markets for renewables such as California and PJM. Our pipeline consists of projects that have a combination of land, interconnection access or advanced permitting. Approximately one-third of our pipeline is in the energy communities that I previously described and are eligible for additional tax credits. We believe our pipeline will become increasingly valuable as sites for projects become scarcer. Turning to Slide 7. At the same time, since our last earnings call in August, we have signed an additional 1.6 gigawatts of new renewable PPAs or 3.2 gigawatts year-to-date. Furthermore, we are in very advanced late-stage discussions on several large contracts that we expect will bring us within our full year range of 4.5 to 5.5 gigawatts. Today, our backlog of signed PPAs stands at 11.2 gigawatts, the majority of which is expected to come online by 2025. We remain largely on track with our construction program, which is now 5.2 gigawatts. There are some projects that have been moved from this year to next, primarily due to delays from customers. But as we've mentioned before, none of these projects are late due to a lack of solar panels. We also continue to make very good progress on our two very large green hydrogen projects in the U.S. and Chile, which include the integration of electrolyzers and renewables. Although we don't have any specific announcements to make today, we are confident that we will have more to share with you on this important initiative before the end of the year. Turning to Slide 8 for an update on growth initiatives at our U.S. utilities. This quarter, AES Ohio filed a new electric security plan or ESP 4, which outlines a comprehensive road map to position AES Ohio to resolve outstanding regulatory proceedings and make significant investments to modernize its network. The filing is a substantial achievement for AES Ohio as it will lay a strong regulatory foundation for growth by implementing a more traditional utility rate structure. We expect the public utilities kind of Ohio to approve ESP 4 in the next 12 months. As a reminder, AES Ohio has the lowest T&D rates in the state across all customer groups, and we see significant opportunity to invest to improve reliability and strengthen the balance sheet, while remaining cost competitive. Finally, AES Indiana is in the last phases of its integrated resource plan process and plans to file the 2022 IRP report with the state regulator by December 1. The proposal includes another milestone in AES' decarbonization plan with the conversion of the last remaining units of coal operated by AES Indiana to natural gas in 2025 and the addition of up to 1.3 gigawatts of renewables, including wind, solar and battery storage. With that, I now would like to turn the call over to our CFO, 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 one-time 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 four slides, beginning on Slide 12. In the U.S. and Utilities SBU, lower PTC was driven primarily recognition of one-time 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 commissionings 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 commissionings, 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 three-quarters 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.

Thank you, Steve. In summary, we now expect our 2022 adjusted EPS to come in at or near the high end of our guidance range of $1.55 to $1.65, and we are reaffirming our 7% to 9% annualized growth target for adjusted EPS and parent free cash flow through 2025. Our strong financial results continue to demonstrate the resilience of our portfolio to macroeconomic volatility. We signed additional agreements that will redirect excess LNG from our business in Panama to international customers. We expect the Inflation Reduction Act to greatly accelerate the demand for renewables, stand-alone storage and green hydrogen. To address this growth in demand, we have increased our pipeline to 64 gigawatts, including 51 gigawatts in the U.S. and year-to-date, we have signed 3.2 gigawatts of renewables and energy storage under long-term contracts, and we are in late-stage discussions on several more that we expect will bring us within our full year range of 4.5 to 5.5 gigawatts. With that, I would like to open the call for questions.

First question regarding the updated outlooks for the U.S. pipeline and the backlog you've revised. With the passage of the IRA, as we wait for fourth quarter earnings to provide additional guidance, do you have a strong sense of the potential increase in that backlog, particularly for 2025 and 2026? Does this give you confidence in achieving the upper end of the 7% to 9% EPS growth range?

Yes, we're observing very strong demand, particularly in the U.S. market and among commercial and industrial customers. The main issue isn't demand itself but rather the availability of permitted projects that can satisfy our clients' needs across different markets. We are confident in achieving our growth targets of 7% to 9%. The Inflation Reduction Act positively impacts this outlook, but we anticipate some market adjustments. It's not solely about growth; profitability of those projects is also crucial. In the coming months or year, we expect there to be a bit more scarcity of projects as demand rises. Those who have prepared well and developed a solid pipeline will benefit significantly. Additionally, the Inflation Reduction Act includes a $3 a kilogram incentive for green hydrogen, which will further support the growth of renewables and AES. All these factors are encouraging. Currently, we maintain our projection of 7% to 9%, but as the market improves, growing profitably becomes just as important as the growth rate itself.

We will wait for more guidance on this. My second question is about LNG. It appears to have provided a significant benefit in the MCAC segment, with an estimated EPS benefit of around $0.25 year-over-year, which exceeded our expectations. Can you provide more details on the volume that contributed to this? It's important to note that hydro conditions will be a key factor in determining any benefits going into next year and beyond. Assuming normal hydro conditions and the current prices for global gas, could there still be some positive impact as we consider 2023?

Yes, we have designed our contracts to ensure that during dry years, we can secure all the LNG necessary to meet our thermal contracts. Conversely, in wet years, we can purchase hydro at a lower cost and adjust our shipments accordingly. It's crucial not just to have the LNG but also the capacity to transport it primarily to Europe, especially considering the port bottlenecks. This highlights the flexibility we've established and our strategic partnerships with LNG suppliers, which enable us to leverage their market positions for effective shipment management. Looking ahead, during a La Nina year in Panama, more water is available, which is influenced by reservoir levels. Currently, we anticipate that conditions will remain favorable. The key factors will include the difference between Henry Hub prices, shipping costs, and international pricing. We expect to see additional contracts in the fourth quarter. For next year, it will depend on conditions such as reservoir water levels and hydrology, as well as the price spread. Overall, we view this situation mostly positively going forward, although we are not relying heavily on it. In terms of tonnage, we expect to ship slightly less next year compared to this year, but we can provide details on actual volume shipped later.

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?

If I understood the question correctly, you're asking about how we anticipate cost savings in the current inflationary environment. Given our international exposure, we are well-prepared to manage inflation and control costs. As noted in previous calls, the cost of building renewable energy has increased over the past year, with higher panel prices and EPC costs in the U.S. However, in this robust market, we are able to pass these costs on and maintain our margins on new projects. We've had cost-saving initiatives in place for the last 12 years, translating to about $500 million in costs on a run rate basis. Our infrastructure for this is solid and it's part of our culture of continual improvement, so we're not overly worried on that front. Additionally, around 80% of our contracts include some form of inflation indexation, providing us with good protection. We have the experience and methodology in place, so we don't view this as a significant concern.

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 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.

No, that certainly makes sense. And I appreciate the color there. And maybe Steve, picking up that last point around the IRA. Curious on transferability could impact your tax credit outlook? Is this an opportunity to invest more on a net to AES basis or any other impacts you foresee?

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 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.

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.

No change, Angie. What we wanted to highlight is that with the IRA now established and the tax credits extended into the next decade, it’s important for everyone to understand this is a crucial aspect of the renewable economics in the U.S. We want to convey what this means for AES, emphasizing that we have a long runway ahead and that it plays a significant role in how these assets are monetized and returns are generated. This will certainly increase over time. As we expand our business, it is expected that we will have a larger share of the credits. Additionally, looking at the U.S. utilities business unit, the skew towards the fourth quarter is largely due to commissioning more projects, especially renewables, during this period. The tax credit recognition for the investment tax credit is linked to when these projects are commissioned. Thus, we anticipate a boost in the U.S. fourth quarter results, similar to what we experienced last year, due to these factors. I wanted to emphasize the significance of the IRA and the seasonal nature of tax credit recognition in the U.S. utilities sector.

I remember a couple of quarters ago, you had set growth targets of 4.5 to 5.5 gigawatts of power purchase agreements per year, and it seems like you're on track with that. I'm curious if there's any potential to exceed that target. Additionally, it appears you have over 5 gigawatts of capacity currently under construction. I'm looking for some reassurance on how you are managing that level of activity, and whether there is a chance to increase it, and how you plan to handle so many projects logistically.

Yes. Thank you, Angie. That's a great question. Yes, we have a significant step-up in our construction between this year and next. And you correctly point out, we have more than 5 gigawatts currently under construction. I think we've handled it very well. We have doubled the number of people that we have working on construction in renewables in the U.S. We have been working with strategic EPC contractors, meaning that we can give them not sort of just project by project, but really a line of sight, how much work they're going to get over the next two years, so they're able to staff up. So we've done very well there. I think we've done a very good job of managing the solar panel supply, which has been very turbulent. We've had no delays this year due to solar panels. We have already most of the solar panels that we need for 2023. So we're working very closely with that also the inverter. So I feel very good about that. We have done a lot of outside of the renewables area, a lot of big projects. So I think we have experience there. So I feel very comfortable. We will have a roughly doubling of what we commissioned this year to next year. And again, we've been worried about the supply chain. We started more than two years ago. So we are in as good shape as anybody in handling it. And I think the results speak for themselves. We haven't had to delay any projects because of a lack of supplies or a lack of construction workers or anything of the sort. Regarding sort of the upside, as I said, the IRA does provide upside. It has good incentives for renewables. They will be, I think, increasing demand certainly from corporations. And I think what's very important is we're not just looking at increasing our growth rate but making sure that we're growing profitably and growing well.

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?

What I'd say, we're going to continue to churn capital. As our projects mature, it's a way of increasing our return on invested capital. As you know, once we finish renewable projects, we sell down to people who want a fully contracted U.S. dollar renewable. So our plan through 2025 that we've laid out is fully financed. If we were going to know I would say, going forward, if there are additional very profitable opportunities, we'll have to look at that, but we have a lot of options. We have a lot of options. We're investment grade. And as we have done in the past, we can turn more quickly some of our assets in terms of our sell-downs.

This question is for Nick today. I just want to quickly discuss the Ohio rate case. We have observed some peers facing challenges in this process. Could you provide an update on how you're managing your regulatory strategy in Ohio and the outcome of the rate case? If there are any changes since the last update, that would be helpful. However, I understand that Ohio has a minimal impact on the consolidated EPS. Any additional information would be appreciated.

Yes, I'm happy to provide an update. This is Steve. We are taking a strategic approach. We recently filed for our electric security plan, ESP 4, and we're currently awaiting a decision from the utility commission regarding the outstanding rate case. We expect to hear back before the end of the year. The main issue is whether rates should be frozen while the rate stability charge, which has been in place for about 20 years, is still applicable. We believe there is considerable support for the new rates proposed in our plan, and the staff has expressed support as well. Consequently, we've decided to move forward with a new ESP regardless of the outcome of this case, and that process has already begun. As Andres mentioned, we anticipate resolution on ESP 4 by the middle to later part of next year. Our primary focus is on growing the utility, which currently has the lowest rates across all customer classes. There is significant potential for upgrades and investments, and it's important for us to maintain a healthy financial structure to support ongoing investment. The filing of ESP 4 is intended to facilitate that process. We remain confident in the case we've presented and believe the stability charge can still be maintained. However, if the commission decides to hold rates until the stability charge is retired, we will have the ESP 4 process in place, which is already underway. This way, we will have a resolution by mid-next year without delay. That is our strategy, and we still anticipate a decision on this case later this year.

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 bringing 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?

Okay. Julien, good to talk to you, there are a lot of questions. Let me try to frame this response with both Steve and myself addressing your question. The first point is about the new IRA, which does provide us with the flexibility regarding ITC and PTC on certain projects starting in 2023, presenting a slight upside. In terms of project timing, these developments usually skew toward the end of the year due to the financing structure, particularly in Q3 and Q4, and we expect this trend to continue. Regarding our backlog, it's currently at 11.2 gigawatts, with most projects expected to be commissioned by the end of 2025, although a few will extend beyond that. As projects get completed, new ones will enter the backlog. It's noteworthy that our backlog represents about one-third of our current installed capacity, giving us confidence in our growth rates and the quality of our contracts. Our growth in the U.S. is largely driven by investment-grade off-takers, with utilities and primarily corporate clients, while internationally we are signing major contracts in Chile, including with Codelco, a significant copper exporter, which we view as a similar risk level to U.S. clients. I'll now pass it to Steve for further details on the tax matters and your other questions.

And if I can, just to clarify, I would like to know about the yearly breakdown of that 11 gig instead of looking at it on an intra-quarter basis. I'm trying to reconcile the older expectations with the newer ones and would like to understand how many gigs per year can realistically be expected.

What I would say is that we're expecting to increase from less than 2 gig this year to around 4 gigs next year. Eventually, if we continue signing 5 gigs of new renewable contracts, we will be commissioning or bringing online 5 gig as well. The two aspects are interconnected. Therefore, the most significant catch-up will occur next year, with both lines progressing simultaneously. If our signings increase, there will be a lag of about 18 to 24 months between the higher number of signed PPAs and the commissioning or bringing online.

Yes, I would say that Andres mentioned we will have 4 gigawatts next year, which will continue to grow. This is our primary growth area, reaching 5 gigawatts to 6 gigawatts. We’ll provide more details next year as we update our guidance. I estimate that about two-thirds of this will be in the U.S., with a larger portion consisting of solar and solar plus storage. Currently, approximately 75% of the U.S. backlog is solar or solar plus storage, which is ITC qualified. We can't choose PTC at this point, but we are evaluating that where it yields good returns, typically in areas with higher capacity factors like the Southwest U.S. The credits are expected to rise significantly, and I anticipate next year will see a substantial increase year-over-year due to higher commissioning rates, particularly in the fourth quarter. As our business continues to expand, the timing will become less critical as we move towards a more consistent pattern of annual additions. The credits are a crucial element of monetization, especially in light of the IRA, and understanding this is essential for modeling purposes, particularly as the U.S. Utilities SBU seasonality is increasingly influenced by renewables and the clean energy sector.

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?

Yes. So you're talking about like the adders for the energy communities and domestic content, things like that. Is that right?

Correct.

So yes, I think roughly one-third of our U.S. pipeline today is in these energy communities that qualify for the 10% adder. I think as we move forward, then we look at domestic content, we are a leader. We've launched our U.S. solar buyer consortium. We expect first supplies from that in 2024. So I would expect us to be having a share. I don't have a specific percentage right now, but a material share of our projects meeting the domestic content production in 2024. And then we are fully ready to be qualified for the wage and apprenticeship requirements and training already. So that's a nonissue. We're already at that 30% level with our project. And then I would expect at least one-third to be in that 40% level and some perhaps even higher up to 50% with the domestic content as that starts to become part of our panel supply in '24 and beyond.

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?

I think, as a market leader, we have many long-term relationships in tax equity and possess top talent in the industry for structuring these projects both commercially and from a tax perspective to optimize returns. While transferability is an option, I'm not sure it actually enhances returns due to the significance of the tax depreciation component, which adds value to accelerated depreciation. Typically, the value of projects increases once they are built, surpassing the initial capital cost, so it is vital to focus on returns. Although transferability could add liquidity to the market, AES already has the necessary liquidity to capitalize on tax attributes. We will consider it, but I would not characterize it as a major turning point for us, given our scale and existing capabilities.

Congratulations. Regarding the LNG success year-to-date and your thoughts on next year, just in terms of the repeatability there. What gives you the confidence there? If there's anything you could share about what you might have sold forward or thoughts on what sort of conditions need to repeat for you to deliver that again?

Yes, Gregg, we anticipate a continuation of this trend into the fourth quarter, although it may be slightly smaller. There's potential for next year, which will depend on the difference between the Henry Hub plus prices we secure in our contracts and the prices in Europe. This is crucial. Additionally, for hydrology, we need favorable conditions in Panama, and our reservoirs are currently at high levels, putting us in a good position. The key factor will be the spreads that justify making those shipments. We also expect lower volume next year compared to this year, so any increase would be considered positive. While it seems possible, we're not relying heavily on a significant amount of LNG. These are the main drivers, and you can see how these factors are evolving, indicating a potential opportunity.

Yes. I would like to add that for the fourth quarter of this year, we've already accounted for whatever we could do with LNG. We have a much smaller potential upside in the fourth quarter already included in our comments about meeting the upper end of our guidance range. Any additional volumes would be considered for next year, and depending on the market conditions, as Andres mentioned, we believe it is very possible and would provide more upside. However, for this year, we have already contracted everything we could.

We'd be pointing back to the different base. I mean we've said 7 to 9 growth and through 2025, and that's what we're committed to achieving. So it's not changing our base year for our growth rate.

Yes, it's been a very good year. I believe there is more potential for growth, as Andres mentioned. However, I wouldn't consider this a new baseline since it's not certain that we'll consistently operate at this level.

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.