NRG Energy Stock

Good day, and thank you for standing by. Welcome to NRG Energy, Inc.'s Second Quarter 2026 Earnings Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Brendan Mulhern, Head of Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to NRG Energy's second quarter 2026 earnings call. This morning's call is being broadcast live over the phone and via webcast. The webcast presentation and earnings release can be located in the Investors section of our website at www.nrg.com under Presentations and Webcasts.

Please note that today's discussion may contain forward-looking statements, which are based upon assumptions that we believe to be reasonable as of this date. Actual results may differ materially. We urge everyone to review the safe harbor in today's presentation as well as the risk factors in our SEC filings. We undertake no obligation to update these statements as a result of future events, except as required by law.

In addition, we'll refer to both GAAP and non-GAAP financial measures. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to our earnings release and the non-GAAP reconciliations and supplemental data file located in the Investors section of our website.

With that, I will now turn the call over to Robert Gaudette, NRG's President and Chief Executive Officer.

Good morning, and thank you for joining us. From the beginning, we've been focused on serving the next wave of power demand the right way. For the largest new loads, new demand should be matched with new generation with the customer supporting the investment. That's how growth at this scale should work. It protects existing customers, strengthens the grid and creates durable value for the communities we serve and for our shareholders. The developments in Texas over the last 24 hours reinforce why that approach matters. States want the economic growth that data centers can bring, but they also expect new demand to bring new supply, support the infrastructure it requires and strengthen, not strain the power systems and the communities that make it possible.

The environment has changed. Our strategy has not. In fact, the direction of policy is moving toward the model we've been building from the beginning. We have the commercial structure, the equipment and the capabilities to deliver it at scale. Today, we'll walk you through the commercial framework we are pursuing, the 1.2 gigawatt project advancing under it and the broader opportunity in front of us. We are aligned on the principal commercial terms with a leading global cloud and AI hyperscaler, including their capital commitment to support 1.2 gigawatts of new generation in Texas with the potential to expand to 2.4 gigawatts. This is expected to be our first Bring Your Own Power project and reflects our strategy for large load growth. We believe it should be the industry standard, supporting economic growth, meeting our customers' expanding power needs and protecting families and small businesses.

The commitment will be long term. The credit quality is strong, the economics support both the investment and our targeted return. This is disciplined growth at meaningful scale, structured around a large investment-grade customer and a clear path to do more. We also delivered solid second quarter results and are reaffirming our 2026 financial guidance. Bruce will cover the quarter in detail.

As I mentioned, we're advancing a 1.2 gigawatt project in Texas with a leading global cloud and AI hyperscaler. We're aligned on the [ principal commercial ] terms with negotiations and remaining land-related matters progressing in parallel. The customer has made a financial commitment to advance the project. Importantly, the project is designed to bring more new generation to Texas than the data center is expected to require. We believe its design positions us well to meet the state's power and reliability objectives. Any final investment decision will be subject to the customary conditions, including required internal approvals. These are highly complex transactions with work to be done but we're confident in the way we've structured and what we expect to deliver with our partner.

NRG plans to develop, own and operate the new combined cycle gas plant. The facility is planned to support a 1-gigawatt data center load with additional Texas development opportunities that could expand the relationship to as much as 2.4 gigawatts. The project is supported by the turbine and EPC capacity we secured through GE Vernova and Kiewit. This investment also has to work for the surrounding community. We expect more than 1,400 high-paying construction jobs, 30 permanent roles at the plant and significant new tax revenue for local governments and schools. NRG has operated power plants in Texas for decades, and our employees live in these communities. We know that water matters, and we and our customers are committed to responsible water stewardship, and are working closely with local stakeholders as development advances.

We also understand the broader concerns surrounding data center growth. Communities expected growth to be -- that growth to be responsible, to respect local resources and to create real lasting benefits. That's how we're approaching this opportunity. The project's initial term is at least 15 years from commercial operation with potential for extensions. Based on the current development schedule, commercial operations is targeted for late 2029 with full run rate earnings thereafter. At full operation, we expect $500 million of annual adjusted EBITDA and $375 million of annual free cash flow before growth. Those figures reflect a 1.2 gigawatt project and do not include the potential expansion. These are high-quality, long-duration earnings supported by an exceptional investment-grade counterparty. The project is expected to deliver attractive returns that achieve our required investment hurdles on a stand-alone basis and are even more compelling on a risk-adjusted basis. It also represents a build multiple below where NRG trades today.

The contemplated facility is expected to require $3.2 billion of investment. Bruce will provide more detail on the capital requirements and how we're thinking about funding the project. But let me be clear, our commitment to return at least $1 billion to shareholders through share repurchases each year is unchanged. We have the financial flexibility to fund this project as it advances, manage our path to target leverage and continue executing our capital allocation framework. The economics are compelling, and our commercial structure is what gives us confidence in their durability.

Now let me walk you through it. On Slide 6, the commercial framework has two components: the Capacity Payment is designed to recover the capital we invest and deliver the return we require. A separate Operating Payment covers natural gas and plant operating costs. Put simply, we're paid for the megawatts we build and make available, not for how much the data center runs. That distinction is critical. The commercial structure provides for 95% of the project's free cash flow to be supported by Capacity Payments over the term, independent of data center utilization. Fuel and operating costs are recovered separately, and the customers' commitment will be supported by an investment-grade parent guarantee. The result is durable, visible cash flow. Our return is established upfront and is not dependent on merchant power prices or natural gas prices. The more important point is, that this structure is not unique to one project. We do not need to reinvent the model each time. The customer, location and project size may change, but the fundamentals remain the same.

The commercial structure supports the investment NRG develops, owns and operates the generation and the economics are established before construction begins. What differentiates NRG is our ability to bring the full solution together. We provide an integrated path to power from bridge solutions through permanent combined-cycle generation with the flexibility to operate in island mode, grid-connected or transition between the two. Pairing generation with a load can also reduce the amount of incremental transmission infrastructure required to serve that demand. Another important benefit of the BYOP model. We also bring the in-house capabilities to develop, engineer, interconnect, commission and operate the assets across their full life cycle. That gives the customer one experienced partner accountable from initial design through decades of operations. It reduces handoffs and helps lower execution risk across a highly complex power development. We've built those capabilities over decades and are proving them today.

Our 1.5 gigawatt Texas Energy Fund portfolio remains on track, including T.H. Wharton, which we delivered on time and on budget. We moved early to secure both turbine and EPC capacity through GE Vernova and Kiewit, giving us the equipment and the execution capability required to continue building at scale. Few companies can bring all of those elements together. I am proud to say that NRG can. That is why this opportunity came to us and why we're positioned to do it again.

On the next slide, the market setup is increasingly compelling. Across ERCOT and PJM, projected demand growth is materially ahead of the supply currently expected to come online. We do not need every forecasted project to materialize for both markets to require substantial new generation. That imbalance is changing the market. Customers need executable power solutions. Policymakers are pushing towards growth or pushing growth towards customer-backed supply and the value is moving toward companies with real development positions and the ability to deliver. Our BYOP framework answers the reliability and affordability concerns of elected officials and regulators. Our ability to design, build, own and operate a power plant for decades is a differentiator for our solutions. We have a history of working-in and living in the community. We are a responsible operator and community member. In today's world, that matters, that's where NRG is positioned today.

Now let me put the scale of the opportunity into perspective. The 1.2 gigawatt project discussed today is the first step in bringing the full potential into perspective. It represents the first 1.2 gigawatts of the 5.4 gigawatts of turbine and EPC capacity we secured through 2032, with line of sight to the critical labor required to execute that build-out. Our broader development pipeline is more than twice the 5.4 gigawatts of capacity we have secured with every turbine slot tied to an active customer discussion. Customers recognize the value and scarcity of the development position we have assembled and our technical expertise and capabilities. And as you'd expect, engagement across that pipeline continues to build. Potential capital partners also recognize the value of what we've assembled, providing additional pathways to advance the broader opportunity through capital-efficient structures while preserving balance sheet flexibility and continuing our disciplined and consistent return of capital to shareholders.

We also have about 2 gigawatts of uprate opportunities across our PJM fleet. Together, that gives us a substantial runway to apply the model we just described. Let me be clear about how we will pursue that opportunity. We will not trade discipline for scale. Each project must stand on its own, meet our risk-adjusted return thresholds and be supported by the commercial and credit protections appropriate to the capital we deploy. Combining the established base with a 1.2 gigawatt BYOP project creates an illustrative 23 -- sorry, 2030 contracted free cash flow opportunity of $1.2 billion. For purposes of this illustration, we hold current capacity auction prices constant through 2033. That is an assumption, not a forecast of future auction outcomes. If we're successful in bringing this project to fruition, and I strongly believe we will be, then together with contracting the remaining new build opportunities and executing the uprates, the free cash flow supported by long-term agreements and capacity revenues can reach 95% of the midpoint of our company-wide 2026 free cash flow guidance by 2033. And that would only be one part of NRG. The rest of the business would continue to generate cash flow and create value alongside it.

As a reminder, before any data center opportunities, our business is expected to deliver 14-plus percent adjusted EPS CAGR through 2030. That is the opportunity, to materially expand NRG while fundamentally improving the quality of its cash flow. We intend to help build the power infrastructure behind America's digital economy, while protecting communities and customers, both large and small, all while creating a larger, stronger and higher quality NRG in the process. This is an important step. We intend for it to be the first of many.

Bruce, over to you.

Thank you, Rob. Turning to Slide 10. NRG delivered a solid quarter with adjusted EBITDA of $1.2 billion, up $308 million or 34% from the prior year period. Adjusted net income was $315 million compared to $339 million a year ago, and adjusted EPS was $1.49 compared to $1.73. Free cash flow before growth was $1.025 billion, up $111 million year-over-year. This was our first full quarter with the portfolio we acquired from LS Power, and we are exceptionally pleased with the quality of the assets and the contribution they are making to the business. The year-over-year increase in adjusted EBITDA was driven primarily by the acquired portfolio, higher PJM capacity values and continued growth in Smart Home.

Adjusted net income and adjusted EPS were modestly lower as acquisition-related interest expense and D&A offset the higher EBITDA contribution. That is the expected near-term net income and EPS profile during the de-leveraging period. As we reduce debt and associated interest expense, more of the portfolio's earnings contribution will flow through to EPS.

Turning to segment results. Texas adjusted EBITDA declined $131 million year-over-year, primarily reflecting lower load and power prices. ERCOT Houston around-the-clock prices averaged $33 per megawatt hour during the quarter, 8% lower than last year and well below our 2026 planning assumption of $52. With prices low and volatility limited, our fleet had fewer opportunities to run, and our commercial team had fewer opportunities to optimize the portfolio. East adjusted EBITDA increased $370 million year-over-year, driven primarily by the contribution from the portfolio acquired from LS Power. Energy margins from those assets did not fully realize the increase in PJM power prices because some preexisting hedges were in place when we closed the transaction. Results also reflected higher supply costs in our Retail businesses.

One additional item in the East is Virginia's return to the Regional Greenhouse Gas Initiative, or RGGI. After we acquired the portfolio from LS Power, Virginia enacted legislation requiring the state to rejoin the program effective July 1, that change applies to the 1.2 gigawatts of Virginia assets in the acquired portfolio and creates an estimated $70 million of incremental cost in 2026 that was not included in our underwriting. .

In the West, adjusted EBITDA increased $27 million year-over-year, primarily due to lower operating expenses following the expiration of a facility lease last year. Smart Home adjusted EBITDA increased $42 million, driven by continued customer growth and higher recurring service margin per customer. The business ended the quarter with 2.45 million customers, up 8% year-over-year and continues to deliver growth well ahead of the pace assumed in our long-term outlook.

With solid second quarter results, we are reaffirming our 2026 guidance ranges. Through the first half of 2026, softer load and power prices in Texas and higher regional power supply costs incurred during Winter Storm Fern have us tracking below the midpoint of the ranges. While PJM prices have strengthened, preexisting hedges on the acquired portfolio and higher RGGI costs have limited the near-term benefit. Our first half results largely reflect the impacts of weather and market conditions, not a change in the underlying performance of the business. We plan for outcomes like these when establishing our guidance ranges and actively manage the portfolio to align expected supply with committed customer load to ensure we deliver results within those guidance ranges. As a result, as we move through the balance of the year, we have limited unhedged exposure, and our outlook does not rely on a material recovery in commodity prices, thereby giving us confidence that we will deliver within our guidance ranges.

Moving to Slide 11. We have updated our 2026 capital allocation plan to incorporate the initial investment in the 1.2 gigawatt Texas data center new-build project Rob discussed. As you can see from the chart, aside from the reallocation of a portion of planned liability management to the new build investments, all other elements of our 2026 capital allocation remain unchanged. Importantly, this investment does not change our previously announced commitment to repurchase at least $1 billion of shares annually. The primary update is a new data center new build investment category, reflecting $721 million of expected project investment in 2026. Of that amount, $40 million was previously included in plant and other investments and has been reclassified so the full project investment is presented in one place. The remaining $681 million is the incremental change to the plan and will be funded through lower liability management, resulting in less net debt reduction in 2026 than previously planned. It is important to note that the vast majority of the expected spend in 2026 relates to equipment-related procurement.

Not only is this spend critical to currently contemplated project but it is also critical to the preservation of the increasingly valuable option the equipment represents given the prominence that new generation will have in the data center build out. Since this spend is largely equipment related, it represents spend that can be pointed to other viable projects and therefore, is not sunk cost. Our approach to facilitating the data center build-out combined with the pipeline of prospective opportunities we are pursuing, gives us confidence that these are prudent investments that will drive appropriate returns.

As a reminder, in April, we advanced our post-acquisition de-leveraging plan through a series of refinancing transactions. We retired substantially all of the $1.5 billion of Lightning senior secured notes we assumed in the acquisition and repaid a portion of the revolver borrowings used to fund the transaction. These actions extended our average maturities, reduced secured debt and are expected to generate more than $10 million of annual interest savings. Our long-term leverage target of 3x remains unchanged.

We are also executing against our 2026 return of capital plan. Throughout the first half, we completed $921 million of share repurchases and paid $202 million in common dividends. For the full year, we continue to expect $1 billion of share repurchases and $407 million of common dividends.

Turning to Slide 12. Rob covered the contemplated commercial structure. Let me focus on what it means financially and how we plan to fund the project. The commercial structure of the new build project protects the return we underwrite through an availability-based capacity payment, separate recovery of fuel and operating costs and limited commodity exposure. The customer is investment-grade and its obligations will be backed by appropriate credit support. At full operation, the initial 1.2 gigawatt project is expected to generate at least $500 million of annual adjusted EBITDA and approximately $375 million of annual free cash flow before growth.

On $3.2 billion of total investment, we expect the project to deliver a pretax un-levered IRR within our 12% to 15% target range. At the expected run rate EBITDA, that implies a build multiple of approximately 6x. These earnings are not included in the long-term framework we provided earlier this year. That framework, including our expectation for 14% plus adjusted EPS CAGR through 2030 is supported by the base business alone. This project represents substantial additional earnings power. We plan to fund the project through operating cash flow and balance sheet capacity, including lower liability management, resulting in less net debt reduction than previously planned over the construction period. We remain committed to long-term net leverage of 3x, which we believe is consistent with investment-grade credit metrics. We believe the expected cash flows and counterparty credit quality are constructive from credit and ratings perspective.

The funding plan preserves the capital allocation commitments we have previously made as we expect to continue to execute at least $1 billion of annual share repurchases through the construction period. Lastly, we expect the project to qualify for bonus depreciation upon COD. COD thereby further extending our cash tax runway.

Moving to the next slide. Total investment for the 1.2 gigawatt project is expected to be $3.2 billion or $2,700 [ of KW ]. With capital deployed over 4 years and the large outlays following key development and construction milestones. Cumulative investment through the end of 2026 is expected to be $0.8 billion, including previously made reservation payments. From there, we expect to invest $1 billion in 2027, $1.1 billion in 2028 and the remaining $0.3 billion in 2029 ahead of the expected late 2029 COD. 60% of the investment relates to EPC and the remainder relates to turbine equipment and other project costs. The investment profile is deliberately phased. Capital follows project progress with the larger outlays occurring after key milestones. We attain meaningful flexibility throughout development and construction.

As I mentioned earlier, much of the 2026 spend relates to equipment, which, if necessary, could be redeployed at other viable projects. As such, we see this investment as less project-specific and more an investment in NRG's unique capabilities to deliver solutions that work for customers. Our current plan assumes NRG funds and owns the project. As development advances, we will evaluate opportunities to improve capital efficiency, including financial partners while preserving the economics and strategic value of the investments.

In closing, we delivered solid second quarter results and reaffirmed our 2026 guidance. The data center new-build project adds a substantial new stream of contracted earnings beyond our existing framework with returns protected by a robust commercial structure and a funding plan that preserves the commitments we have made to shareholders.

With that, I'll hand it back to Rob.

Thank you, Bruce. Let me close with where we stand. We delivered solid second quarter results, reaffirmed our 2026 guidance and made significant progress on our large load strategy through the 1.2 gigawatt BYOP opportunity discussed today. At the start of the year, we said we were targeting at least 1 gigawatt of large load agreements in 2026. We are advancing an opportunity that would deliver that objective with principal commercial terms aligned and negotiations and remaining land-related matters progressing. Any final investment decision will be subject to customary conditions, including required internal approvals.

As I said at the outset, the environment has changed. Our strategy has not. Texas has made it clear that how large load growth is served, matters. New demand must bring the power infrastructure required to support it, strengthen the system and avoid shifting the investment burden to families and small businesses. That direction plays directly to the model we have built. This project is designed to bring more generation than the data center is expected to require, reduce the need for incremental transmission and place the investment burden on the customer. That's why we believe the project is well positioned in Texas and why NRG is well positioned to lead. There is still work ahead. We will stay focused on advancing the project, executing across the broader business and maintaining the discipline that brought us to this point. We have made meaningful progress against what we set out to do. We are going to keep our heads down and finish the work.

Operator, we're now ready to open the line for questions.

[Operator Instructions] Our first question comes from the line of Julien Dumoulin-Smith of Jefferies.

Congratulation, guys in getting this across the finish line. Nicely done. Rob and Gang. Yes, absolutely. So you know what I'm going to always ask here. So nicely done here, I'm very curious about an expansion of this site. I mean it seems that some of your sites have the opportunity to expand to that full 2.4 gigawatt. How are you thinking about the timeline to make it happen? I noticed, not to nitpick on the slides, it looks like it could be up to 18 months between the first and the second in terms of the COD. So how do you think about just setting expectations on the cadence around these incremental 1.2 gigawatt chunks, whether at that site or elsewhere?

And then also, if you can, can you speak to the returns. Is this kind of a build multiple so we say the new norm as to how you think about what these other projects are going to be? Or are they going to be slightly less favorable given that it is the first one and potentially the cheapest.

Yes. So there's a lot in there, Julian. So thank you. So I'm going to try to answer everything you said. Let's start with returns. So the returns that we showed today on this particular project that we're moving forward, that's our expectation. That's what we've committed to our shareholders. And when we have conversations with customers, that's it. Like this is what it's going to be. And everyone will flow a little bit here and there. But generally, that's what we expect to return to our shareholders for the capital they deploy.

As far as how to think about timing and where projects go, the thing that gets set on delivery of these projects is the CODs of construction and the turbine deliveries themselves, right? Depending on how the customer wants to go, where the sites were going to go to and when we can get the turbine on the ground, that will determine kind of the speed that we go to. But what we've laid out historically is consistent with what we see across our pipeline because it's determined by what we see out of our GEV agreement. And so we have those conversations with customers.

And then the last piece I would just in response to your statements. The one thing I would think about is the 1.2 gigawatts on a site to expand to 2.4 gigawatt, that doesn't rule out taking 2.4 gigawatt somewhere, that doesn't rule out 4.8 gigawatt somewhere, right? As we talk to customers and we think across these turbines, we have multiple customers looking for multiple turbines. The project that we put forward today and the one that we have the most alignment around is at a site, right? But don't get tied up on trying to sort out where or how because that's not the important part. What we're trying to get across is the commercial structure we put forward so that you guys can see how it works. And that is the conversation that we are having with every customer as to how we structure these deals because it's the right way to do it. We're working hard on it. We're not done but we believe that this is an important piece of information for all of you guys to see.

Julian, on the COD point, I'll just add. So this first one is late 2029. What we've said previously is the way that the GEV, Kiewit structure is organized, you can assume there's another block of 1.2 gigawatt to come on serially year -- each year after the 2029 COD for the first one.

So 12-month cadence. Nice. And then just a couple of nuances. First, just with the contract duration, is that typically the -- to complement the return that duration is the new norm? And then also, how do you think about the Texas governor's announcement yesterday? Again, I know not necessarily specific and germane to this project per se, but how does that impact just the time line as far as you're concern?

Okay. So on the contract duration, we've told you guys 15 to 20 years. This particular structure is 15 years. We're not going to go less than that or I wouldn't expect to, because that would dramatically change the price of the customer.

On the Texas governors stuff, look, I understand where the politicians and regulators are in Texas. And I tried to make that point in this in our -- what I said earlier in my scripted remarks, our project answers those questions, right? It is the right project to meet the concerns of the communities and the elected officials because it doesn't strain the grid and because it also can reduce the need for [indiscernible] transmission out there. As far as timing goes, Texas is to get things done state. I expect them to work through stuff to get to higher quality -- a higher quality understanding of the projects to be put down over time. And then the last part I would point out is, remember, this is a COD in 2029. So I think we're okay.

Our next question comes from the line Shar Pourreza of Wells Fargo.

Rob, can you just maybe just a little bit higher level, just elaborate on the actual progress that's being made and kind of what drove the confidence to announce the principal terms at this stage. So I guess, what types of final approvals could be outstanding? And when can those be expected?

Okay. So we'll [indiscernible] why we talked at all. It's important for our shareholders to understand both the structure of what we're pursuing, the strategy of how we're delivering on our GEV and Kiewit turbines. And we found that we were in a material place to have a conversation about progress so that each of you could understand where we're at.

As far as things that are what we've stated today, right, we are commercially aligned, meaning that we have -- they've seen the structure, they agreed to the structure. We are close and in close conversations every day about specific timing or a piece of land or whatever those things are. The things that we're still subject to is we're still subject to negotiation. Moving forward is not done, and we will continue to push until we are, and we'll continue to have conversations with multiple customers until we are. And then it's obviously the required internal approvals and all of the things that go with that.

The last thing I would say around timing. The next time we'll come back to you, Shar, we're going to tell you when we have another material piece of information to talk about. I'm not going to set myself or the negotiation team up with a time line to work against. But I feel very strongly that we will continue to push forward, and I believe that we will meet our objectives both for the short term and the long term for this company.

Got it. That's perfect. And then just lastly, just given some of the noise around collateral requirements that we're seeing and stuff. And can you just maybe elaborate a little bit on the counterparties. It's obviously investment grade, but is it BBBs? Is it single A? Can you just maybe elaborate a little bit on the credit quality of the counterparty?

To quote my predecessor "No".

I could see Larry right now shaking head saying don't answer that, Rob. Don't answer.

He's so happy with that answer. Investment grade, Shar that's what you get.

Our next question comes from the line of Nick Campanella of Barclays.

Appreciate all the updates on the BYOP deal. Just a follow-up on the contract details. You used to kind of talk about when you were outlining for investors how to think about this targeted pricing? I know you kind of talked about like $80-plus per megawatt hour. Just with the returns on the slide that you're looking at and the CapEx cost being kind of a little bias higher since you've given that update. Just is the PPA equivalent now north of [ $90, ] north of [ $100 ]. Any comments there? I know it's kind of like a fixed capacity charge pass-through, but how would you think about that?

Yes. So given the structure. The dollar per megawatt hour thing doesn't really matter because of the way we've structured it. I think if you were to do the math and expect a capacity -- or sorry, an expected usage of the data center. It's in the probably $85 to $90 plus range. But we really don't focus on that, right? It's all about -- it's good for the customer to not focus that way, and it's good for us to not focus that way. So that we -- this structure provides the certainty and the returns that we need for our investors. And it also provides flexibility and ways for the customer to think about managing their own risk depending on what their views look like. So we could hedge up that variable piece if they wanted, and that collateral would be their requirement.

But we've built as much flexibility in here because we started from the beginning with what do our shareholders need. How do we serve our customers and how do we serve the communities around it? That's how we've approached data centers.

Maybe pivoting quick to just PJM. You kind of outlined in your contracted cash flow visibility walk, the potential to do something with the 2 [indiscernible] of uprates in PJM. So just maybe an update on how you're thinking about the bilateral process or the procurement and how to think about that?

So it's a multipronged approach, right? There is the long-term auction opportunity, which we will bid into -- and we are also in the bilateral conversations as we speak. The additional capacity that those upgrades offer are going to be valuable to anybody who wants to connect inside of PJM and not be subject to curtailments. So we know that it's valuable, and we are continuing to monitor, and we will bid-in through any process. The way to think about it is I am going to invest capital for this company in a place where we can get long-term durable cash flows. 15-year auction proceeds, that makes sense. And so would a bilateral conversation of the like term.

Our next question comes from the line of Carly Davenport of Goldman Sachs.

To start, maybe just a quick follow-up on Nick's question there. As you think about the uprate opportunities, are you able to share how much of the 2 gigawatts is kind of economic at the $555 per megawatt a cap, just to sort of size opportunity on the central procurement side?

So if you -- depending on how you interpret that $555 cap, meaning can they procure above or not. The way I think about it, Carly is it's probably about less than half of that [ 2,000 megawatts] would go through that auction that way. But we continue to have bilateral conversations on all 2,000 megawatts.

Okay. Very helpful. And then maybe just on the capital allocation side, as you talked about in the prepared, it's kind of largely through the buyback program for the year at this point. How are you thinking about potential for incremental capital to be allocated there just as you think about where the equity is trading from a valuation standpoint?

Carly, I think as we sit here today, to the extent that we have the ability to upsize the program that will somewhat depend on where we land from a cash flow perspective for the year. If we're executing against this project and spending the capital that we had outlined that's where we would see our money going because we see this project as being really valuable at the end of the day. But certainly, if the opportunity exists to be able to upsize the program with incremental cash flow, we'll definitely do that.

Our next question comes from the line of Michael Sullivan of Wolfe.

I was going to ask if you could just elaborate a little more on what you're looking at on the funding side of things. I think you alluded to potential capital partners. We've seen Williams do something like that relatively recently? And then just what that can do for you from a balance sheet flexibility credit metric standpoint?

Yes. So Sully, I mean right now, the base case is that we just fund all of this on balance sheet and all that really results in is we had previously spoken about being able to hit our 3x leverage ratio in 2028. If we were to do this project and fund on balance sheet, that just gets extended out to 2029. But there still would be deleveraging over the period for sure, even while we're funding the project. Obviously, if we pursue something that involves a partner, whether it be the Williams-type structure or any other structure and that creates some incremental capacity. Then honestly, that probably provides for more opportunity to increase the annual buyback program more than anything else.

And in terms of making that decision, is it just you need to leg into more of these agreements? Or it's just irrespective of that, it's only conversation.

I mean making that decision is really just a function of having the concerted conversations with potential partners and coming up with a structure that we think makes a lot of sense for us economically. And so we certainly intend to do that. Clearly, having the contract is important because the partners need to understand what they're theoretically investing into. And I think we're definitely getting to a point where those conversations can really start to happen in earnest.

Very helpful. And Rob, if you could just give us your latest thoughts on on the ERCOT market pricing dynamic. I think people watching all-time peaks, limited volatility this year. But then at the same time, a lot of folks following this patch process, which seems to have a lot of load coming but forward is not really reacting. Curious, you think what's kind of driving the pricing action there?

Yes. So Sully, you're referring to the fact that the ERCOT market is not valuing anything right now. Prices are low. They're low out the curve. People thought that maybe some announcements around batch would have driven those curves up. But what we've seen in markets over the last couple of decades is until it's real, it's not. And so things like concerns around delays, things like when is the stuff going to hit the ground, that's impacting, call it, the '27, '28 time frame in the curves today.

At the end of the day, Texas is still a growing market. And it's got some battery and solar development to absorb through, call it, '26 '27 and maybe a little bit into '28. If the data center market -- or sorry, [ 8 data center ] development slows down, that inflection point changes, or gets pushed out. But the fundamental doesn't change. ERCOT needs generation in the medium term because we can't get back to the place where we were years ago. And given the tax implications or whatever subsidies for batteries and solar going away in, call it, '27, that build will dramatically reduce over time and the market tightens. And remember, you don't need all 500 gigawatts. You don't even need 1/3 of that to really tighten this market up to a place where everybody will be grateful that they have generation to support their customer loads.

Our next question comes from the line of Angie Storozynski of Seaport.

I just wanted to talk a little bit more about financing of the growth and how that's going to flow into your free cash flow. So basically, as we sit here today, I'm assuming that $1.5 billion out of the $3.2 billion of total CapEx is financed with that, is that fair? I mean that is assuming that 3x net debt to EBITDA for the project?

And then how does that interest flow through the free cash flow that you will be reporting, and I understand that it's pre-growth, just the mechanics of the accounting for that interest?

Angie, the interest expense will be -- it's IDC, so it will be capitalized. So we don't -- that wouldn't have an impact on our free cash flow before growth at the end of the day.

And the assumption is that its going to be basically holdco [ and amortizing ] debt, right? So when I tried to see what is the fully loaded return that these assets provide. I don't amortize this debt. I just account for the interest expense.

Yes, I think that's probably fair. Just assume that there is a permanent capital structure related to the project of 3x.

Yes. And then this 25% that you show as a deduction against EBITDA for maintenance CapEx and tax. I mean, the assumption is right, that even in '29 or 2030, you're not a cash taxpayer, right? So...

That's right. We provided what is otherwise kind of the long-term run rate that doesn't necessarily suggest that, that is what the cash flow number would be in the early years when we have the benefit of the various tax shields.

Okay. And what's the -- like roughly the math for maintenance CapEx, this is sort of an asset? Is it, say, $50 million a year? Like what's the ballpark?

We're not going to provide that just right now, Angie. We'll provide that at a later date.

Okay. That's fine. And then secondly, so I mean, I'm looking at the breakdown between the cost of turbines versus the EPC contract. I mean, can you give us a sense, for example, that EPC component seems pretty big. Is there -- like the cost of new build advantage, is that mostly on the turbine side in a sense that as you announce additional projects, there is some sort of a market-based adjustment for the EPC component. How do we think about that?

Angie, I think -- this is Matt. I think the way to think about that is the EPC has two elements to it. It's the labor piece. They also bring a balance of plant equipment piece to it. So think about the turbines as the OEM and then a lot of the balance of equipment comes from the EPC. So that's why it may look a little bit higher than what you would think just OEM providing everything [indiscernible] would be.

Awesome. And then just the last question. So I appreciate the Virginia rejoining RGGI as a drag. Is there any other drag like related to the below-market hedges for LS Power beyond '26, like as I think about '27 or '28?

So Angie, the portfolio did come with some hedges that extended beyond 2026, not nearly as much as there were in 2026, but there are -- there were some hedges in 2027 that the portfolio did come over. And obviously, given when those were struck, those were struck at a slightly below level -- market level relative to today.

And you're not going to say what percentage? Like -- or how big a drag?

We'll certainly provide that detail when we come out with 2027 guidance in our next earnings call.

Our next question comes from the line of Moses Sutton of BNP Paribas.

Rob and team, congrats on the deal. To clarify Nick's question maybe through maybe more correct language here. Would it be fair to consider the return structure as $1,150 a megawatt day, which gets you to $500 million EBITDA and that the P&L costs like O&M and fuel and how much you're using it are pass-through and gross up to revenue?

And given later projects would have higher-priced turbines and EPC, is it fair to then assume cost of new entries, you might assume on CCGT is well above $1,200 a megawatt day?

Do you want to take that?

Moses we are not going to comment specifically on any of the specific terms of the contract. You've obviously done the math and depending on where you want to come out we are squarely looking at a project that is within that 12% to 15% return. And so however, that comes out in terms of your math, and that's what you should run with, but we're not going to comment specifically on that.

Just to be clear -- to answer your question, but also for clarity, everywhere. If the cost of the build goes up over time. Our expectations of return on your cash flow -- or on your investment don't change, right? So we will -- and we have open conversations with customers about that. We will always signed deals inside of our 12% to 15% hurdles, always.

Very helpful. And on that annualized capacity payment, does it simply switch on at COD? Or is it a multiyear stage ramp as the data center is ramping its own site plus the data center utilization?

It switched on immediately upon COD.

Our final question comes from the line of Nick Amicucci of Evercore ISI.

Rob, Bruce, just wanted to get a sense Bruce, just kind of where we get confidence on kind of the 2026 guidance. Where we can kind of shake out just given that we kind of obviously more subdued prices in ERCOT and then kind of the benefit that you could see in PJM.

Yes. So Nick, I mean, obviously, as we said in the prepared remarks, given kind of where the first half has landed, we would probably forecast ourselves to be in the below the midpoint of the guidance range. But we still feel confident that we'll be within guidance range. And a lot of that confidence is really based on where we see the current fleet being hedged for the balance of the year, which is pretty much substantially hedged for the balance of the year. And then how does that gets layered on top of how we've matched our supply and committed load and most of the committed load that we would have expected for the year has essentially been acquired or set up. And so therefore, that's the sort of visibility we have with respect to earnings and margins for the balance of the year.

And then just as we think about the uprate opportunity in the PJM, so those 2 gigawatts, I know you had said roughly half, we can think about in the RFP. But when we think about that kind of CT-to-CCGT conversion, just where would -- where -- what's kind of like the rule of thumb if we're thinking about that relative to from a build cost relative to the $2,700 on the greenfield side?

Lower and faster.

This concludes the question-and-answer session. I would now like to turn it back to Robert Gaudette for closing remarks.

Thank you. And thanks, everyone, for joining us this morning. We're pleased with the quarter and with the progress we outlined today. We will always be disciplined with the allocation of your capital. The update reinforces why we believe BYOP is the right model for serving large load growth, bringing new supply alongside new demand, strengthening the grid and protecting existing customers. There is work ahead, but we're executing well and remain confident in the opportunity and our ability to create long-term value for shareholders. Thank you again for your time and for your interest in NRG.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Good day, and thank you for standing by. Welcome to the NRG Energy, Inc. First Quarter 2026 Earnings Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would like to hand the conference over to your first speaker today, Brendan Mulhern, Head of Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to NRG Energy's First Quarter 2026 Earnings Call. This morning's call is being broadcast live over the phone and via webcast. The webcast, presentation and earnings release can be found in the Investors section of our website at www.nrg.com under Presentations & Webcasts. Please note that today's discussion may contain forward-looking statements which are based upon assumptions that we believe to be reasonable as of this date. Actual results may differ materially. We urge everyone to review the safe harbor in today's presentation as well as the risk factors in our SEC filings. We undertake no obligation to update these statements as a result of future events, except as required by law.

In addition, we will refer to both GAAP and non-GAAP financial measures. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to our earnings release and the non-GAAP reconciliations and supplemental data file located in the Investors section of our website. With that, I will now turn the call over to Robert Gaudette, NRG's President and Chief Executive Officer.

Good morning, and thank you for joining us. I'm joined today by Bruce Chung, our CFO; and other members of the management team who are available for questions. Before we get into the quarter, I want to briefly acknowledge the CEO transition. I've been with NRG for over 2 decades and have worked across the company through multiple market cycles. That experience shapes how I think about and operate this business. I want to thank [indiscernible] for his leadership over the past several years and the impact he's had on this company.

I also want to acknowledge our employees across the business. The work you do every day is what makes this company run and positions us to deliver for our customers and our shareholders. As I step into this role, I view our responsibility clearly. We are stewards of your capital. Our job is to allocate it with discipline, operate efficiently and deliver consistent long-term returns. That's how I'll run this company. I've seen this business at its best and at its most challenging. Over time, outcomes come down to how well we operate and how we put your capital to work. We've positioned the business for where the market is going, and I see a clear opportunity to build on that and drive the next phase of performance. I have a high level of confidence in where we are, and I'm excited about the opportunity in front of us.

With that, let me turn to Slide 4 and walk through our key 3 messages. First, we delivered strong operational performance and are reaffirming our 2026 financial guidance and capital allocation. The business is tracking to plan. Our teams are executing and the results reflect the underlying conditions this quarter. Second, we're seeing a sustained shift in power demand outlook across our markets with the regulatory frameworks continuing to evolve in response. What matters is not just that electricity load is growing. It's the pace, the location and the duration.

Near-term conditions remain variable, and that is reflected in current market signals. And third, we're positioned to capture significant value from this environment. We have built a platform for where the market is going with the flexibility to develop capacity alongside long-term demand as those opportunities evolve. Our base plan stands on its own. It does not require incremental contribution from large load or new development to hit our numbers. Those remain upside. Our job is to execute allocate capital effectively and convert the opportunity in front of us into results.

Turning to Slide 5. First quarter results reflect a soft market environment. Texas was mild with heating degree days down 30% year-over-year, and the market offered limited opportunity, where storm firm drove significant price spikes across PJM in late January. We closed the LS Power transaction on January 30, after most of the storm had passed. So those assets were not part of our fleet during that period. Bruce will take you through the numbers. What I want to be clear about, none of that changes our view of the business or the year.

We are reaffirming guidance, and the business is on track. Integration of the LS portfolio is underway and progressing well. The assets are performing as expected, and we're focused on I'm fully incorporating them into our operating and commercial platform. Our first Texas Energy Fund project, TH Wharton, is expected to come online in May, on time, on cost and on spec, qualifying for the TH completion bonus. Our remaining TEF projects continue to progress on schedule. At 1.5 gigawatts, these 3 projects will power roughly 300,000 Texas homes at peak demand. arriving just as the state continues to add nearly 400,000 new residents a year.

Very few companies have recent experience developing new natural gas generation. We have and we're good at it. These projects were developed at well below current new build costs because we identified the opportunity and prepared the site years before the TEF program existed. When the moment came, we were ready. If we execute on what is in front of us, this capability will be one of the most important competitive advantages in our industry. This is what you should expect from NRG. We look around the corner, we prepare -- and when the opportunity is there, we bring it home on time and on budget.

Turning to Slide 6 for an overview of our key markets. Demand expectations continue to increase. this quarter earnings season reinforced the scale of investment being directed toward AI infrastructure, and the implications for power demand are significant. [indiscernible] the numbers are straightforward. The system's all-time peak demand is more than 85 gigawatts.

The preliminary long-term load forecast filed this month shows the pipeline of large load requests reaching over 36 gigawatts in by 2033. That is more than 4x today's record peak in under a decade. Not all of that materializes, but even if a fraction of what is in that pipeline arises on those time lines, this market looks fundamentally different from the one we're operating in today. Senate Bill 6 and the large load batch process are bringing more structure to how new demand connects to the grid, and we support those reforms. I want to specifically thank the PUCT and ERCOT teams for including bring your own generation support in the initial batch process. That's an important step in aligning new demand with new supply and supporting reliable system growth.

In PJM, the reliability backstop procurement is an important step to help bring new capacity forward. and we appreciate the coordination against -- across PJM, state policymakers and the federal government in advancing these efforts. Within our existing fleet, we see up to 2 gigawatts of upgrade and conversion opportunities. This represents an incremental 1 gigawatt above the previously disclosed [indiscernible] CCGT conversion opportunity with the additional capacity coming from more traditional natural gas upgrades.

We will pursue those where structures and returns support it through the procurement process or bilaterally where appropriate. We'll move forward selectively. Each opportunity must compete for capital, meet our return thresholds and be supported by long-term commitments from high-quality customers.

Turning to Slide 7. I want to be specific of what -- about what makes our position in this market different because I do not think it's fully appreciated yet. We serve commercial and industrial customers at a scale, very few companies in this industry can match. That's not something you acquire. It's built over decades to relationships, credit, operational track record and the ability to structure complex agreements across multiple markets. We have that foundation and is the reasons customers come to us when problems gets hard.

On flexible load, we acquired LS Power because it is the leading commercial and industrial demand response business in the country. Our Texas residential virtual power plant is targeting 1 gigawatt of capacity. And we can only operate at that scale because we have the retail electricity business and smart home technology behind it. No 1 else has both of those run inside of generation and retail platform at our size. When a [indiscernible] needs to move, we can move it.

On generation, we operate a large dispatchable natural gas fleet, primarily in ERCOT and PJM. These assets run when the system needs them. they demonstrated that again this quarter, and they provide real earnings leverage as load growth materializes in our markets. On development, our TEF projects are under construction. Our partnership with GE and Kiewit gives us construction capability, equipment access and execution readiness that most companies in the space are still trying to establish. As the right opportunities emerge with the right structures, we are ready to move.

In PJM, we have additional development opportunities across uprates and conversions that we will pursue through the procurement process or bilaterally or structures and return [indiscernible] Taken together, this is the platform this market is asking for. We can solve complex load problems. We know how to develop and build. We have equipment and labor access. We can move load when the grid needs it. and we have the customer relationships and scale to back it all up. I am confident in where we are going.

Discussions on large load agreements are active and progressing. These are complex long-duration structures, and we're moving forward in a disciplined way. We are seeing strong engagement in the right types of opportunities, and we feel good about how these discussions are developing. Based on what I'm seeing today, I have a high level of confidence in this company's position. With that, I'll turn it over to Bruce.

Thank you, Rob. Turning to Slide 9 for a discussion on our first quarter financial results. Before I go into the results, I wanted to be sure to highlight 3 items. First, we remain on track to deliver within our 2026 guidance ranges. And as such, we are reaffirming those ranges today. Second, during Winter storm Firm, our generation fleet demonstrated excellent operating and reliability performance, once again reflecting the benefits of our robust generation CapEx program over the past few years. And finally, as a reminder, the LS Power portfolio acquisition closed on January 30. As such, our first quarter 2026 results reflect approximately 2 months of earnings contribution from the recently acquired portfolio.

Now on to our financials. NRG delivered adjusted EBITDA of $1.08 billion, adjusted net income of $308 million and adjusted EPS of $1.49 for the first quarter of 2026. Year-over-year adjusted EBITDA was lower by $46 million. This reflects the impact of milder weather in Texas for most of the quarter and increased supply costs in the East due to Winter Storm Fern offsetting incremental earnings from our newly acquired portfolio. It is also worth mentioning that favorable weather was a big factor in making 1Q 25 a record first quarter for NRG, thereby making the year-over-year comp for 1Q '26 more challenging.

To finish on consolidated results, both adjusted EPS and adjusted net income were also lower on a year-over-year basis. The declines reflect higher interest expense and depreciation and amortization associated with the LS Power portfolio acquisition as well as the partial period contribution of the acquired assets.

Turning to segment results. Texas experienced the impact of unfavorable weather on our home energy volumes as well as lower average power prices and minimal market volatility, which weighed on both our retail consumer business and commercial optimization activities. Specifically, Houston on-peak prices averaged $29 per megawatt hour, down approximately 13% from last year. Notwithstanding the general lack of weather during the quarter, our fleet was well prepared to handle any moments of extreme volatility due to weather as evidenced by fleet performance during Winter Storm Fern. Increased investment in our generation assets has been an important focus for the company over the past few years, and it is great to see that investment paying off.

Our East segment results benefited from our recently acquired portfolio, reflecting the immediate contribution these assets are making to the combined platform. However, these gains were offset by higher regional power supply costs incurred during Winter Storn Fern. PJM West Hub on-peak prices for the quarter averaged $103 per megawatt hour, up approximately 72% from last year, a tailwind for our generation dispatch but a headwind for our retail supply costs since we had not closed on the acquisition at the time of Winter Storm Fern.

As a reminder, we closed the LS Power acquisition late in the storm, so we did not have access to those assets for most of the event. Our West segment results benefited from higher retail power margins driven by lower supply costs and favorable customer mix and include the impact of the expiration of the Cottonwood lease, which ended in May 2025.

Smart Home results reflect continued organic customer growth and expanded net service margins, supported by sustained customer demand for our connected home platform. The business ended the quarter with approximately 2.37 million customers, a year-over-year increase of 9%, well ahead of the 5% to 6% net customer growth embedded in our long-term growth plan.

Moving to Slide 10 for a look at our 2026 capital allocation, which remains unchanged from what I outlined on our fourth quarter call and is fully consistent with our previously disclosed priorities. As a reminder, the waterfall on the left begins with $3.05 billion of capital available for allocation, reflecting the midpoint of our updated free cash flow before growth guidance range. As part of our ongoing commitment to a strong balance sheet, we expect to execute approximately $1 billion toward debt repayments throughout the year.

On that front, I want to highlight an important balance sheet action completed subsequent to quarter end. On April 28, we closed on $3.5 billion of new financing, retiring the $1.5 billion Lightning senior secured notes and reducing revolver borrowings, a key step in our post-acquisition deleveraging plan and consistent with our 3x net leverage target. This financing paves the way for the future removal of the ring fencing we had in place when we closed on the acquisition and will result in more than $10 million of annual net interest savings.

Turning to return of capital. We remain on track to return at least $1.4 billion of capital to shareholders in the form of share repurchases and common dividends. Through April 30, 2026, the company completed $817 million in share repurchases, inclusive of our negotiated repurchase of 1.83 million shares from LS Power. Finally, we are allocating the remaining capital to continued investments in our core portfolio with $310 million directed towards growth investments.

In closing, NRG delivered solid first quarter results in a challenging weather environment, once again demonstrating the resilience of our integrated platform. Our guidance reaffirmation today reflects confidence in the full year outlook underpinned by disciplined capital allocation, prudent liability management and the growing contribution from the LS Power portfolio. With LS Power integration well underway and tracking ahead of plan, we are well positioned for the remainder of 2026. I look forward to updating you on our progress in the quarters ahead. With that, I'll turn it back to you, Rob.

Thank you, Bruce. Let me close with our priorities on Slide 12. We will run the fleet with a relentless focus on safety, reliability and performance. That's the foundation this company is built on. We will continue to serve our customers with discipline, focusing on value, retention and the integration of our retail, smart home and flexible demand capabilities to strengthen those relationships over time.

We will be disciplined in how we allocate capital, maintain a strong balance sheet and continue to return capital to shareholders. We are advancing our key growth initiatives and are on track to deliver at least 14% adjusted EPS and free cash flow per share growth over the next 5 years before any contribution from large load or incremental development. As I step into this role, that's where my focus will be running this business with discipline and consistency, driving efficiency, allocating your capital with accountability and converting the opportunities in front of us into results.

Operator, we're ready to open the line for questions.

[Operator Instructions] Our first question comes from the line of Shahriar Pourreza from Wells Fargo.

Rob, big congrats on your first earnings call. I know it's going to be one of many. I know obviously, the focus is on ERCOT. But in terms of PJM and the regulatory process there, do you guys see any -- do you guys see FERC, PJM colocation rules opening up opportunities to bring both new generation and upside in existing assets in that market? I mean it looks like peers are having conversations with customers. So there is an opportunity with the asset base there as we're thinking about a tentative framework on things like new capacity versus existing capacity matching?

Yes. So great question. I believe that the PJM process and look, I applaud all the effort that's going on between the states, PJM, the White House to try to make things happen up there. I think it presents kind of 3 opportunities for NRG if you think about it. We've obviously got up to about 2 gigs what we talked about today and upgrades around existing assets that we picked up through the LS acquisition. We've had the opportunity to take the GE turbines up there if the economics make sense that a customer is willing to go there. And then the third piece, and I think this is kind of the place where is new is the potential to offer in kind of the load management side. So the BPP the team is building down in ERCOT, that's something we can use up north. And through [indiscernible], we've got a real capability around demand response. I think all of those pieces are opportunities for NRG, and I think there are also real reasons to think about how to solve the equation up in PJM. Does that answer your question?

Yes, totally, Rob. I appreciate that. And then in terms of the 5 gigawatt plant in Texas, do you still anticipate all the capacity to be utilized front of the meter? Or is there a higher return option with PJM deals as we've seen an increase in behind-the-meter announcements with higher implied levelized revenues in the $150 million range. Maybe any thoughts on how you're thinking about the $90 million to $95 million range that you had previously talked about.

Yes. So the $90 million to $95 million was kind of the -- where we had kind of put the top end for like a normal data center deal, depending on the structure and where we would go, the thing that we're going to capture, Shahriar, what our returns require. So the prices could go up depending on the environment. Our primary focus is front of the meter generation front of the meter data center because we believe that's the right thing for the market. But we'll look at everything. We'll look at behind-the-meter solutions. We'll look at all of it. The conversations that we have today are front of the meter conversations, and they're progressing as well as they have been over the last 12 months. We continue to push really hard to get that done. I think front of the meter is the right solution, and we're getting to a place now where we're going to get something done quickly.

Got it. Perfect. And just go again one more time. Just a big congrats to you on Phase 2 and just do me make sure you work Bruce a little bit harder than Larry.

Our next question comes from the line of Julien Dumoulin-Smith from Jefferies LLC.

Congratulations on the role and hang in there. I got to tell you, watch out. Well, look, let me follow up quickly on here. I mean, obviously, you talked about mild weather here in the quarter, et cetera. But how do you think about offsets for '26 and then probably more importantly here, you think about what we've seen in the power curve moves thus far? I mean, Rob, you've been watching these markets for a long time. How do you view the move forward here in ERCOT relative to any potential delays in bad 0 or any other interpretation? Maybe just transposing what we've seen in softness or to date forward or what have you? Looking back to and also hedging views around that.

Right. So I'll take in parts. Let's talk about the markets first. The markets are -- they showed up physically weaker in the quarter. That's a reflection of the supply demand and just lack of weather, right? There just wasn't any real weather in ERCOT. The traded markets tend to have a recency bias. So when people aren't excited they kind of lean out the back and you see the curves kind of trade down a little bit. And then what I would also tell you, and we've talked about this in the past. As far as out the curve, the real transaction capability are the things that are going on that are setting that curve, are the large C&I customers and what they're doing around the markets. If you think about the macroeconomic environment that we're in today, that puts question marks into our big customers and what they're thinking. And so as that cleans up, as the complex around the world, help people have a little bit better view into what their business looks like. In 5 years, that helps them get back out into the market and provide some support in the market. There's no natural buyer out there unless you're a large industrial trying to lock up your time. As far as I don't remember the second question, Julien, I'm sorry, what was it?

Well, I mean, I was thinking about like just offsets on '26 here. Just if you think about like softness of the year, see the reaffirm. Is there anything that we should be keeping in mind there?

Well, so I think that the way our markets work is I talked about how we -- what's left in the year. You still have some here in front of you, Julien, right? We still got potential heat in Texas anytime -- and so we've got to manage through that. We've invested in it so that our plants are ready to capture it. And then we've got the retail businesses ready to serve our customers. As far as offsets going the way that we think about it, I'll turn it to Bruce. But obviously, he and I are going to work to ensure that we deliver what we told you guys we're going to deliver.

Yes. Julien, look, I think it's really as simple as this is just the first quarter. As you know, our company and our business has always been sort of seasonally weighted towards the last 3 quarters anyway. So I think that's why we feel comfortable being able to reaffirm the ranges that we've put out there. And certainly, that's the case on an EBITDA basis, I'd say we're even more confident on a free cash flow basis. we see certain working capital items sort of unwinding themselves over the remainder of the year. That gives us a lot of comfort that we're still going to be able to hit the free cash flow number that we put out there.

Nice. Rob, bigger picture question here, right? You've taken over, how do you think about the strategic direction of the company here? I just want to ask bluntly here and give you the opportunity to respond. I mean, obviously, the company is already moving towards building new gen on contract, adding duration to the overall contract portfolio. It seems like that's the direction you all are going. You are doubling down on that statement. It seems like today with yet more gen build given the increase in the opportunity in PJM here. But look, I just wanted -- if you were to define the strategy in a way with your fingerprint here, how would you add or evolve what I would describe -- what I've just described.

Yes. So Bruce, I others were all part of the transition or transformation with Larry. So it's not going to sound too different, Julien. But if there was something I was going to put my finger on the scale on, I would say, we are definitely putting more focus around contracted cash flows, looking for duration of cash flows with counterparties. That leads us to things like data center deals and new build generation. But it also leads us to thinking about the total addressable market differently, right? We have historically been kind of in the competitive markets only. I see an opportunity for us to find contracted cash flows by partnering with regulated entities that may not have the capital or the relationships or equipment or development capability that NRG has. We have a really solid platform, and we should be able to take that to address other customers' needs from the Atlantic to the Pacific.

I don't want to put words in your mouth, but that sounds like more like a contract, a gen build strategy like a [indiscernible] than it does like [indiscernible], not to point at others.

Well, so I'm not going to try to figure out what other people are doing. I'm really focused on what we're doing. But to say it succinctly, I think that we can create value for investors by putting their capital to work in generation or other programs, right, with long-term contracts.

Our next question comes from the line of Michael Sullivan from Wolfe Research.

Congrats [indiscernible] Maybe if you could just give us a little more color on what you mean by on track for the year in terms of the data center now. It seems like you've had a sense of price and economics for some time now. So what are kind of the main areas you're progressing on? And to hit the 2029 COD, what we need to do in terms of equipment procurement for this year?

Sure. So I'll answer your question in reverse. To hit '29, we've got to get something done in '26 we haven't given anything more specific than that, and I'm not going to start today. And as far as like the things that we're working through, the economics are pretty straightforward, right? We've been -- we know where we need to kind of hammer to to get our returns, and we know where our customers need to be for them to get their returns. So that's not the issue. The real conversations and the work that's still ongoing and it's probably on every project out there. is around infrastructure. So I think interconnections for gen and load and then depending on the location, sites, et cetera, what's that gas infrastructure look like too. And all things that we can manage through and I'm confident that we will -- it's just stuff that takes a little more time, and it's not as simple as just, okay, what's the number? It's a conversation with multiple parties. It's a conversation with regulated entities and we're working through those. And I have confidence that we will get that done.

Okay. Great. And then the pace of buybacks was pretty quick year-to-date. Anything to read into that? I know a chunk of it was the direct transaction with LS. But any chance you go above $1 billion? Or yes, just anything to make of being a bit ahead of pace there on the buyback.

Yes. I mean, So, I think the read into that is we didn't like where our stock was trading during periods of the first quarter, and so we tried to be as opportunistic as we could. As we sit here today, the average price that we bought back shares over the course is well below what we had planned in our guidance. So on a per share basis, we certainly expect to see some potential upside on that basis. whether we would go above $1 billion right now. Right now, the plan remains $1 billion, but to the extent that we see opportunities for extra cash flow, you can probably assume that we'll be pretty laser-focused on being able to deploy it in the form of share repurchases.

Our next question comes from the line of Nick Amicucci from Evercore ISI.

And I know Larry would want me to congratulate Bruce as well. So congrats. I wanted to kind of dig in a little bit on the residential side of the house. And just kind of thinking through that as well as kind of the opportunity now with the power guys, the LS Power folks in the door, just kind of how you can leverage kind of both the residential as well as kind of segments and business lines to -- within that kind of offering of the DPP opportunity.

Sure. It's a great question, and it's something that gives us a unique opportunity to both create value, but also help manage affordability for customers. the portfolio by having what we're doing around [indiscernible], by having the tech stack that we've got through the smart home business and by adding C-Power, which is more of a C&I play, but they do have an understanding of how to make things move. Those all set us up for success. So I'm going to let Brad talk about like kind of where -- what our kind of milestones are going to be and how we're addressing that, if that helps.

Yes. On the residential side, we're really pleased with our performance. We have made some choices around kind of the quality of customers we want in and around Texas, and we've seen that pay off in terms of bad debt and kind of record churn on that front. However, there are some segments where I think we're underpenetrated. So I do anticipate returning that to growth. On the home automation side, we're seeing -- we finished 2025 with record growth, and we've continued that momentum. So really pleased not only on the acquisition side but record retention numbers for Vivint, all the while driving growth in margin and keeping acquisition cost in check. So we see a lot of opportunity there. And then we also spend a lot of time how we bring these 2 products together to create even more affordability for customers in a bundled type service. So a lot of positive momentum on the residential side.

Great. And then if I can just kind of follow up to on Julian's question before. When we think about -- obviously, you guys mentioned kind of what there was no weather really in ERCOT from a pricing perspective. But just any kind of color you could provide just on the impact of kind of RTC plus B initiatives and just kind of the normalization, I guess, we could say, of the ancillary costs that could be impacting that.

Yes. So I've been following that since I first started talking about it. it kind of showed up the way we expected it. Honestly, Nick, like the ERCOT market boils down to a couple of facts, right? You saw a big solar build a few -- several years ago, then you saw a battery build over the last couple of years. Both of those have kind of slowed down or will slow down in the next year or so. And then we haven't had any weather to really stick a marker out there for anybody to get excited about where those markets are, right? The goal was set -- or the peak was a couple of years ago. You get 1 hot summer with a couple of handful of days where people remember that the price can go to $5,000, and these curves change radically. That's what we're building for. That's what we're supported on and that's how we manage our portfolio. This market is going to look very different, like I said in the scripted remarks, once you start adding generation -- or sorry, load that starts to kind of eat up any marginal megawatts that were out there.

Our next question comes from the line of Carly Davenport from Goldman Sachs.

Maybe just to start on the LS assets. Just kind of maybe could you talk a little bit about as you're integrating those assets, kind of what the key learnings have been so far? Any opportunities for synergies that you see today that perhaps weren't contemplated in your original plans?

So when we acquired -- or after we've gotten under the hood on the assets to we closed in the middle of earn look, we -- the assets kind of came in where we expected them to, right? Our assessment during due diligence for the acquisition was pretty spot on. So no big surprises there. Where we have seen some opportunities. If you remember, when we announced the acquisition, we saw potential up rates as we continue to look at these assets. Depending on the market structure, Carly, right, you've got to get the rules right and we've got to get an opportunity in front of us, but we could take that up to 2 gigs. So that's a plus, and that's exciting. And as far as synergies go, recall the acquisition was heavy on generation facility personnel, so guys who make the plants go not a lot of synergy there. But what we're going to work through over time is how we work that into the portfolio, and that will create better opportunities for us to think about hedging, better opportunities for how we serve customers and serve in those markets. So I see an opportunity there. We just haven't put our finger on that yet.

Got it. Okay. Great. We'll stay tuned there. And then maybe just on the test development, it seems like you're really close here on TH. And maybe can you just provide some detail on what is left there to get the asset online? And then just maybe a scats update on the process on [indiscernible] and [indiscernible] just as you progress those towards the 2028 in service date.

Yes. We're very happy with the TEF projects. We're extremely excited about where they are. And I'm going to let Matt give you an update on [indiscernible] and then the other 2 that come in 28. SP541324311 On TH Wharton, the kind of remaining steps between where we are in COD is just sinking the initiate grade, getting ERCOT to give us the the blessing that they show up the way we expect. So that's all on track and on schedule. And then when you pivot over to [indiscernible] and [indiscernible] of those projects are kind of in an end of 2028 COD. So there various stages of construction, but they're only been long, right, where we expect them to be at this point in time to hit that '28 COD as well.

Our next question comes from the line of Moses Sutton from BNP Paribas.

So we continue to see the ERCOT load pipeline rising. Slide 6, you show supply/demand, we see as kind of believable too, if not conservative. How should we size up the upside to your uneconomic gen in Texas in terawatt hours per year. Could we see 10, 15 terawatt hours upside? ERCOT thermal fleet gets called upon more and more thinking into the out years? Trying to frame the tailwind and is it fair to assume that, that incremental gen would go wholesale and not be integrated into the retail business? Or anything you can give us on that down the road tailwind?

Yes. So we -- a great question, and it's something that we we think about every day. If I was going to advise you as to how to think about it and how to kind of put your finger on that pulse. First, you're spot on, right, that incremental generation wouldn't be attributed to retail led, right? It should be open. And the reason why I say that is because we're obviously managing a position with the market curves where we are today, right? So we're going to cover that up which means that the generation, if it comes -- if prices move to the right place, that generation will become economic and that's additional megawatts. So the way I would think about how you frame it up for your clients or whomever, is think about what that supply demand was. We gave you a pretty decent graph or a slide on Slide 14 that lets you take a look at what these price curves look like. and then what those impacts to the generation are, right? So I think we've kind of given you the numbers. The thing you need to think through is what do you believe price impacts look like and what does that actually do from a overall impact to ERCOT pricing? I know it's not a answer you want, but I'm trying to point you to where you can get.

No, no, it's very helpful. And I guess it's a little bit tied to this and you kind of mentioned it in one of the prior answers, like specifically on the industry battery build in Texas. The returns have been at [indiscernible] now. The pipeline kind of remains there, which is strange. So how do you think of the battery impact on the curves in particular? I know you mentioned it a bit, but do you still see multi-gigawatt build still coming even if they don't have returns? Or are these holding agreements? Like what is still coming on the battery side in Texas that might be impacting the curves? And how do you see that cadence of the decline? Because you kind of mentioned that in your solar and battery comment earlier.

Yes. So my commentary around battery build and how I think it's going to decline is based exactly on the facts you just pointed out, right? The economics just aren't working for them. And so what batteries due to as it kind of pushes the pressure point out a couple of hours when you get tight, right? Right now, you have peak demand that's around, call it, 4, 5:00 in the afternoon, but you have peak price around 7:00 or 8:00 in the evening in the summer. What batteries would do is push that out to, call it, 9 or 10, but they still have to draw. So it provides support for the markets in some parts of the day and then it would kind of discharge during the peaks. If we get even a percentage of what this data center load looks like coming into the grid between now and like I've alluded to before, this market is off to the races. You eat through all of that battery push and all of a sudden, you've got the tight market that we all know ERCOT has been and can be that we saw in '22 and '23.

Our next question comes from the line of James West from Melius Research.

Rob, congrats again on your first conference call as CEO. And also as funded humorous site in Texas complained about mild temperatures in the first quarter for sort of results. We know it's going to get bad. We'll talk again in July and see how you go about it. But -- like I wanted to touch on kind of the large load do data center opportunities, both in ERCOT and PJM lot of regulatory kind of movements trying to kind of, I think, clear the market to speed things up to help the process, but there's also it's a free market, and you can contract without going through the auction process and certainly can contract without needing the help of regulators, particularly in tribute where are the conversations and the development process now? Are the hyperscalers are there waiting for some type of regulatory clarity before they contract? Or are things stalled because of that? Are we waiting a couple of a month or so in PJM and maybe more there in ERCOT. And I'm just going to get some clarity or some color, I guess, on kind of when we should expect to see this enormous demand because these things are being built, so they need power. When we should see some type of movement here on on contracting. Yes. So that second piece is ERCOT, I would say that the regulatory structure and where the PUCT is on putting out rules around SB 6 is pretty well developed. Like that's definitely moving. I think that the counterparties, both on the data center side, but also on the generation side. We know the rules. So we have a pretty good idea of what they're going to look like. And so I wouldn't say that, that is the the long pole in the tent on stuff in Texas. I think it's, like I said, infrastructure interconnections and working with our partners from a regulated entity perspective. And I know that everybody is working hard to deliver data centers to Texas. Every party involved one time. So let's talk about PJM. So in PJM, you've got the new long-term auction, which they're working through at the behest of the White House and it's a good solution, and it's a good answer to help get things kind of moving in over the line. What I would tell you is that in conversations with counterparties there, so our potential customers they're open to bilaterals, too, right? And we're in a unique position -- well, we -- with a couple of others, are in unique positions to offer bilateral solutions that don't need that PJM auction. The auction to me is more of a backstop for conversations that we could have, right? The auction priced right with the right rules. That's a great way to put 2 gigawatts of uprates into our fleet. But I can also have a conversation with a hyperscaler and put a gigawatt of that in the same time, right, or in the -- so we kind of have 2 levers. Most of the conversation there directly with the customer is, hey, I don't want to do a bilateral with you and then have to pay the RBA thing. And I think that stuff all gets worked out over time here. I believe that PJM is trying to do the right thing. I know they're trying to solve reliability and affordability. We support the work they're doing, and we're obviously in the middle of all of those conversations because PJM is a big part of our lives now.

Okay. Okay. Very helpful. And then a quick follow-up for me because some much of this power generation is going to come from natural gas. You guys are more uniquely positioned than others given your generation is natural gas. There's a lot of -- I don't maybe call it chaos, there's a lot of midstream activity going on, the gas producers are trying to get gas from where it is being produced to where it needs to be for power generation. How do you feel that you guys are aligned with that process, so you have the security of supply because that's one thing I think maybe is getting missed in the whole conversation is, okay, you can put a turbine here and build some colocation or attached to the grid, but can you get the actual [indiscernible]

Yes. So you raised a very important point. We do have a great gas platform, right? And we've been serving C&I customers for decades. We've also been serving power plants that are ours and some that aren't ours through the gas side. So because of that, we've got really good relationships, both with the midstream guys but also the upstream guys. And so if we want to procure long-term gas, we know the right folks to call, and we'll do that if our customer wants that. But I feel really good about the platform that we have and its ability to actually create value in addition for our customers but also for our company.

Our last question comes from the line of Andrew Weisel from Scotiabank.

A couple of follow-ups on [indiscernible] and a couple of interrelated questions actually. So first of all, impressive to see the pickup on the uprate potential from 1 gig to so. Am I hearing you right, most of the incremental sounds like it's coming from the LS Power assets as opposed to the legacy, I think, would you only pursue those -- great. Would you only pursue those if they're backed by a long-term contract, whether bilateral or from the auction? Or could any of those make economic sense even without a hyperscaler contract? And then also given the uncertainty around the network upgrade costs, how comfortable would you be bidding greenfield build into PJM? Or would that only be existing assets or operates and all of the new build would be in ERCOT.

So we could build new build in PJM, but you bring up 1 of the risk adjustments that we'd obviously have to make. The second point I would make is we're not going to put capital to work without contracts or long-term revenue. We've got a fleet in PJM. We're in a good place from a position perspective. But I'm not going to go put money after stuff on a merchant basis. So we could find a bilateral deal or go through the PJM auction process. to help backstop that new build, but we're not going to do it without it. And then the last piece I would say is that when you compare and contrast ERCOT from a get things done perspective. We're trying to move these turbines and this capital to get to work as soon as possible. And like I laid out earlier, ERCOT's a little bit further ahead on the regulatory process, which lends us leaning in that direction. But we can take those turbines anywhere and for the right economics with the right counterparty, that's exactly what we'll do.

Then second, more of a philosophical question, but over the years, we're seeing more and more extreme winter storm and similar weather events. At the same time, you as a company are clearly trying to derisk and increase the predictability and stability of earnings and cash flows. You've talked a little bit about this earlier, but do you think there are any additional assents you can take specifically to protect you from these weather events, whether that's hedging or insurance or something more big like M&A or other corporate actions.

So we made a big step towards derisking the portfolio for the winter by closing on the acquisition of LS, right? So what that gave us is [indiscernible] on the ground in the Eastern markets where we have exposures, and there is I can financially hedge my exposures around retail businesses, but there is no better hedge than flexible, dispatchable natural gas assets. And that's exactly what we did. Bruce and I and the team think about our risk, our hedging every day. We're thinking about how we position the portfolio because managing through those storms in the winter or managing through a heat event in the summer is what you guys pay us to do. So that's what we're working on.

This concludes our Q&A session. I would like to turn it back to Robert Gaudette for closing.

Thank you, everyone, for joining us this morning and for your continued interest in NRG. I'm excited about the opportunity ahead and honored to step into this role at such an important time for the company and the industry. We've built a strong platform. We're operating from a position of strength, and I'm confident in our ability to execute and create significant long-term value for our shareholders. Thank you again for your time today.

Ladies and gentlemen, thank you for joining us and participating in today's conference call. This concludes our program. You may now disconnect.

Good day, and thank you for standing by. Welcome to NRG Energy, Inc. Fourth Quarter and Full Year 2025 Earnings Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the call over to your first speaker today, Brendan Mulhern, Head of Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to NRG Energy's Fourth Quarter and Full Year 2025 Earnings Call. This morning's call is being broadcast live over the phone and via webcast. The webcast presentation and our earnings release can be located in the Investors section of our website at www.nrg.com under Presentations and Webcast. Please note that today's discussion may contain forward-looking statements, which are based upon assumptions that we believe to be reasonable as of this date.

Actual results may differ materially. We urge everyone to review the safe harbor in today's presentation as well as the risk factors in our SEC filings. We undertake no obligation to update these statements as a result of future events, except as required by law. In addition, we will refer to both GAAP and non-GAAP financial measures. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to today's presentation and earnings release.

With that, I will now turn the call over to Larry Coben, NRG's Chair and Chief Executive Officer.

Thank you, Brendan, and good morning, everyone. I'm joined today by Bruce Chung, our CFO; and Rob Gaudette, our President. Other members of our management team are also on the line and available to answer questions.

Let's begin with the key messages on Slide 4. We exceeded the midpoint of our raised 2025 guidance marking the third consecutive year we increased our outlook and delivered above it. We introduced stand-alone 2026 guidance in November, updated it in February to reflect 11 months of LS Power ownership and today, we are reaffirming those ranges. We successfully closed LS Power at the end of January. Integration is well underway, and performance is already exceeding our underwriting assumptions. With LS Power now closed, we are rolling forward our long-term outlook. We continue to target at least 14% annual growth in adjusted earnings per share and free cash flow before growth per share, now measured from 2026 through 2030 rather than the previous through 2029.

We are maintaining this more than 14% trajectory despite a much higher share price than assumed at the original announcement. This is achieved through earnings from both the LS Power portfolio and our legacy businesses. Finally, as demand accelerates across our markets, affordability and reliability will define long-term success. New large loads must bring their own power and contract for the generation that supports them. Flexible demand response must scale alongside that. Otherwise, prices will rise and volatility will increase. NRG is well positioned to do both and thus meet rising demand across our markets.

Let's turn to Slide 5, our 2025 financial and business results. 2025 was a record year of performance at NRG Full year adjusted EPS was $8.24 per share, and adjusted EBITDA was $4.87, both above the high end of our raised guidance. Free cash flow before growth totaled $2.210 billion or $11.63 per share, above the midpoint of our revised outlook.

Turning to our 2025 scoreboard. We delivered against the priorities we outlined at the start of that year. We achieved top decile safety performance for the 10th consecutive year and delivered our 2025 target under our $750 million organic growth plan. We signed 445 megawatts of long-term data center PPAs at attractive margins. We secured Texas energy fund loans for 1.5 gigawatts of new capacity with all construction on budget and on schedule. We've launched our Texas residential and finished the year at nearly 10x our original objective. We also announced the LS Power transaction, which we'll cover in more detail on the next slide. In 2025, we returned $1.6 billion to shareholders through repurchases and dividends, while increasing the dividend by 8% for the sixth consecutive year. Our momentum has carried forward into 2026.

During [indiscernible], our Texas fleet achieved 97% in the money availability. Our assets were ready when the grid needed them. That performance reflects investments we have made in the plants in recent years and great work by our amazing people.

Turning to Slide 6. Beyond 2025 performance, we strengthened our competitive position with the close of the LS Power portfolio. our generation fleet has doubled to 25 gigawatts. We added 18 natural gas assets primarily in PJM with additional positions in ERCOT, NYISO and ISO New England. The combined fleet is now more than 75% natural gas. Together with our existing generation and projects under development, we are naturally long against our residential load in our core markets. In PJM, several of the newly acquired peaking units provide a potential 1 gigawatt of upgrades through conversion to combined cycle configuration. That adds flexibility to support future large load demand. CPower, a preeminent company in the demand response space strengthens our capabilities and expand our position in this sector with both commercial and industrial customers. This transaction was immediately accretive, supports our long-term leverage targets and strengthens our credit profile.

Performance is already exceeding our underwriting assumptions driven by stronger capacity and energy prices. In addition, 100% bonus depreciation enhances after-tax returns relative to our original modeling. We have expanded our earnings base and strengthened our competitive position as markets tighten.

Turning to Slide 7. Let's discuss our near- and long-term outlook. Beginning with 2026, we are reaffirming the guidance ranges introduced in early February following the close of LS Power. Recall that the LS contribution reflects 11 months of ownership, not a full year. In 2026, we will deliver these results embedded in our outlook and integrate the LS Power portfolio. We are also targeting at least 11 gigawatt plus signed long-term data center power contract under our Bring Your Own Power Approach. Turning to the longer-term framework. We are rolling forward our outlook and continue to target at least 14% annual growth in adjusted EPS through 2030. This extends the prior 5-year framework, which ended in 2029 and reflects our expanded earnings base. Consistent with our prior methodology, the outlook assumes flat power and capacity prices across the planning horizon.

Detailed assumptions in Texas and PJM price sensitivities are included in the appendix. The plan also now incorporates all 3 Texas energy fund projects rather than one. The first remains on track for June 2026 completion and the additional 2 are expected online by mid-2028 and these represent incremental value relative to the prior outlook. The plan also reflects the portion of the 445 megawatts of previously announced signed data center contracts that are expected to be online during this period. I must emphasize that the outlook does not assume any additional data center contracts or higher power or capacity prices. Let me repeat that. The outlook does not assume any additional data center contracts or higher power or capacity prices.

So beyond what is embedded in this plan, of course, we see significant opportunities to contract new large load natural gas generation under long-term agreements with high-quality counterparties. We have the ability today to support more than 6 gigs of long-term power agreements to serve large data center demand. At that level, it represents the potential to add more than $2.5 billion of recurring annual adjusted EBITDA on contracts of up to 20 years. These projects would provide stable contract-backed cash flows. Discussions are ongoing, so stay tuned.

Turning to Slide 8. I want to discuss our approach to affordability, which has 2 primary components: first, bring your own power. New large loads should contract directly for the generation that supports them. Data centers must pay for their required capacity additions. Cost and volatility should not be shifted to existing customers. Second, demand response. Flexible demand is an essential complement to our approach. Demand response, including virtual power plants provides dispatchable capacity when the system is tight. It lowers peak costs and strengthens reliability without adding structural cost to the system. We are executing on this model today. We have more than 6 gigs of natural gas generation capacity reserved for customer-backed large load projects, including 5.4 gig through our GEV and Kiewit venture and 1 gig of upgrade potential within the recently acquired LS portfolio.

We are also developing new generation through the Texas Energy Fund to support grid reliability. On the residential side, we are building a 1 gig virtual power plant in Texas and preparing to extend that model into PJM. On the commercial and industrial side, CPower now anchors one of the leading demand response platforms in the country. We built all of these platforms early in anticipation of where markets were heading and what politicians and customers are now saying, it is operating today. As demand expands, this model supports significant growth without compromising affordability or reliability.

With that, let me turn it over to Bruce for the financial review.

Thank you, Larry. Starting with Slide 10, I am pleased to share that NRG delivered exceptional full year financial results in 2025. We achieved earnings at or above the high end of our raised financial guidance ranges, including record level performance across several key metrics. Our 2025 adjusted EPS was $8.24 and adjusted EBITDA was $4.087 billion, representing an increase of 21% and 8%, respectively, over the prior year. We delivered $1.606 billion of adjusted net income and $2.21 billion of free cash flow before growth. Our robust financial performance in 2025 marks the third year in a row where excellent execution across our businesses continues to demonstrate the durability of our integrated platform. .

Moving on to a brief discussion of segment results. Our Texas segment delivered full year adjusted EBITDA of $1.877 billion driven by margin expansion and excellent commercial optimization throughout the year, as well as favorable weather that benefited our home energy volumes. The East segment contributed full year adjusted EBITDA of $981 million reflecting a slight decline from the prior year, primarily driven by higher regional retail power supply and planned maintenance costs and the retirement of the Indian River facility. These impacts were partially offset by strong capacity revenues at our plants, winter weather driving natural gas margin expansion and continued commercial optimization in both power and gas.

Our West and Other segment provided full year adjusted EBITDA of $137 million, a modest decline from the prior year driven by the absence of earnings from the sale of our Airtron business in September 2024 and the lease expiration at the Cottonwood facility in May 2025. These were partially offset by higher retail power margins in the West. The smart home business generated full year adjusted EBITDA of $1.092 billion driven by record new customer adds and impressive retention rates, in addition to expanded net service margins. Free cash flow before growth for 2025 was $2.21 billion, exceeding 2024 results by $148 million or 7% year-over-year growth. This year-over-year increase is primarily driven by the strong adjusted EBITDA results, lower interest payments due to the Vivint ring-fence removal and receipt of the remaining insurance proceeds from our WA Parish unit claims.

Turning to Slide 11. We are reaffirming the 2026 financial guidance announced earlier this month, which includes 11 months of earnings from our recently acquired generation assets in CPower. Midpoint for our reaffirmed guidance ranges are as follows: adjusted EBITDA is $5.575 billion. Adjusted net income is $1.9 billion. Adjusted EPS was $8.90 per share, and free cash flow before growth is $3.05 billion. As you can see on the waterfall charts at the bottom portion of the slide, we have made moderate adjustments to the pro forma guidance previously shared on the third quarter call. The updated adjusted EBITDA and free cash flow before growth disclosures now capture improved pricing and capacity values in addition to a preclosing adjustment for January 2026 financial performance for the LS Power assets. You can find more details on the energy and capacity price assumptions we use in the appendix of this presentation.

Moving to Slide 12 for updates to our capital allocation for 2026. Starting at the left of the waterfall and moving right, our total cash for allocation has increased to $3.05 billion. This includes $2.1 billion from the legacy company free cash flow before growth midpoint together with $950 million, representing free cash flow before growth to be contributed by the recently acquired assets from LS Power rated to 11 months. As part of our ongoing commitment to a strong balance sheet, we expect to execute approximately $1 billion toward debt payments throughout the year. As part of the integration for the acquired assets, we expect to spend $123 million of onetime costs to ensure that the assets are appropriately incorporated into our operating and commercial portfolio. We remain committed to our robust return of capital program. and plan to return at least $1.4 billion of capital to shareholders in the form of share repurchases and common dividends.

Finally, we are allocating the remaining capital to continued investments in our core portfolio. with $310 million allocated towards growth initiatives. This primarily consists of spend for our new generation build in Texas, including Texas Energy fund proceeds and continued investment in our consumer platform.

Turning to Slide 13. We are reaffirming our long-term adjusted EPS and FCF BG per share CAGR of 14% plus while also rolling forward, the long-term outlook from 2029 to 2030. As described when we first disclosed the acquisition of assets from LS Power, we have a highly visible path to achieving more than 14% growth in our adjusted EPS and free cash flow before growth per share metrics over the next 5 years, underpinned by solid business expansion and disciplined capital allocation. Starting on the left side of the page with adjusted EPS. We moved from the original 2025 midpoint of $7.25 to our 2026 updated midpoint of $8.90. This step-up reflected strong underlying business performance, contributions from the LS Power portfolio and the ongoing benefit of our share repurchase program.

Looking ahead, we are forecasting adjusted EPS of greater than $14 per share by 2030, underpinned by existing growth programs in our core business operations and our robust return of capital program. Shifting to the chart on the right, our free cash flow before growth is similarly increasing on a per share basis. Starting with the original 2025 guidance midpoint of $11.20. We have increased the midpoint to $14.50 for 2026. By 2030, we expect a further increase to greater than $22 per share again delivering compounded annual growth of more than 14%. The core drivers for this per share increase are similar to those for our EPS growth and reflect the strong cash generation capabilities of our platform and a disciplined capital allocation framework. It is worth highlighting that our long-term outlook holds energy and capacity prices flat through the period.

Our energy price assumptions reflect market prices at the end of December 2025, and our PJM capacity price assumptions reflect pricing at the $325 per megawatt day cap for the next 2 capacity auctions to be held in June and December 2026. Most importantly, this long-term outlook does not include any upside from rising power prices, new data center deals or the 1 gigawatt CT to CCGT conversion opportunities we have with the acquired LS portfolio. We've provided more details on the assumptions in our long-term outlook in the appendix of the presentation. We have also provided updated power price sensitivity slides so that you can appropriately model the meaningful gearing our portfolio has to rising power prices. Wrapping up this slide, we believe our long-term outlook represents a derisked and outsized opportunity to enjoy above-market earnings and free cash flow per share growth, while with meaningful upside levers. I look forward to updating you on our progress in achieving this long-term outlook on future earnings calls.

Finally, on Slide 14, we are refreshing our view of long-term capital allocation. On the left side -- left-hand side of the slide, we have updated our 2026 to 2029 view of capital allocation so that you can have an apples-to-apples comparison. Our current forecast represents an impressive 55% increase in capital available for allocation and a 32% increase in share repurchases from our original guidance in 3Q '24. We Furthermore, the current plan allocates 85% of cash available after debt reduction to return of capital compared to 80% in the original plan. Moving to the right side of the slide, we have rolled forward our plan to include 2030 cash available for allocation, bringing the total to $18.3 billion of total capital available through 2030.

Including the additional year's earnings for 2030, we are increasing our return of capital program to a total of $13.2 billion, comprised of $11 billion in share repurchases and $2.2 billion of common dividends. This represents an increase of $5.3 billion and $800 million for share repurchases and dividends, respectively, relative to the original plan shown in the far left bar of the chart. Forecasted amounts for growth unallocated capital for the period increased modestly by $400 million, with most of that increase in the unallocated bucket. The combination of an improved earnings profile and planned debt reduction of $2.9 billion over this 5-year period will ensure that we achieve our targeted credit metric of 3x net debt to EBITDA. Our long-term capital allocation strategy is consistent with our long-stated principles, which prioritize a strong balance sheet and robust return of capital.

The significant free cash flow we generate over this period affords a meaningful amount of flexibility to put capital to work accretively. Share repurchases will always remain a strategic component of our annual capital allocation plan. While we've shown much of the capital over the period devoted to share repurchases, we recognize that there may be other very accretive uses of that capital beyond share purchases particularly the development of power plants supporting data center contracts under contracts -- sorry, data centers under contracts of up to 20 years, and we will evaluate those opportunities with discipline. But rest assured that any and all of those situations will be measured against our stated hurdle rate of 12% to 15% pretax unlevered IRR and the implied return of buying back our stock.

In closing, NRG delivered record financial and operational execution through 2025, reflecting the resilience of our platform and the continued momentum across our core businesses. As we look ahead, the 2026 outlook and capital allocation priorities I have outlined, highlight the durability of our strategy and our commitment to disciplined growth, prudent liability management and long-term value creation. With the successful close of the assets acquired from LS Power, we have strengthened and expanded our portfolio. Integration is well underway, and the addition of these assets into our combined portfolio positions us well for continued growth and execution of our strategic and capital allocation priorities.

With that, I'll turn it back to you, Larry.

Thank you, Bruce. Let me close with our priorities for 2026. Demand is accelerating, led by data centers. Our priority is to serve that growth under a bring your own power framework securing long-term power agreements that support the new generation required to meet it. We will complete TH work. We will integrate LS Power. We will continue building our virtual power plant platform. Execution and capital discipline remain our load star. We will deliver the financial results embedded in our guidance, return at least $1.4 billion to shareholders grow the dividend consistent with our framework and maintain balance sheet strength.

As I approach the conclusion of my time as CEO, I want to thank all of our 18,000 employees for their incredible work and commitment, our customers for their trust and our shareholders for their support. Over the past [ 25 ] months, the NRG team has reshaped the portfolio, strengthened the balance sheet and positioned NRG to compete and keep winning in the changing power market. We entered 2026 strong, disciplined and well prepared for this next phase of growth. I look forward to continuing as an adviser and long-term shareholder and to watching this incredible team built on the foundation in the years ahead. This is only the beginning and the best is yet to come. Thank you all for everything you have done.

Operator, we're now ready to open the line for questions.

[Operator Instructions] First question comes from the line of Shar Pourreza with Wells Fargo Securities.

Larry, big congrats to you and Rob, so a terrific transition and best of luck to both of you on your Phase II. Maybe just starting off [indiscernible] The CEOs are doing such a good job. We forget the CFO sometimes, but Bruce, we still love you. Maybe just starting off on the expectations now that the LF deal is closed, can you just expand on commercially contracting the combined portfolio comments you made? I mean $2.5 billion in sizable. I just want to get a sense on timing and structure, including how we should think about which party would be taken on the gas risk in these deals or risk share passed on to the counterparties? Just a little bit of a sense on the structure.

Yes. Look, I think a little bit obviously depending on the hyperscalers, but I think we're looking at blocks in excess of a gig I think we're looking at contracts of minimum 10 in frequently 20 years with investment investment-rated entities that can actually support the kind of credit required to make this happen. We're looking at a significant fixed price component in that. And so I think you can start seeing these things come on. You can do the math, we've given you the margin. We've given you the capacity number, so you can kind of figure out when it comes I think the first power, assuming we get to the place we need to get could be on by the late '29 and then ratably probably a gig a year maybe more for each year after that.

Okay. And then just a fuel risk, this is a question we get from a lot of investors is who actually takes on the gas risk.

It's Rob. The contract that we're working with in the structure that we're -- the hyperscalers seem to be okay -- it's a very heavy capacity payment like Larry talked about, and then a variable component where it turns into basically a heat rate for the hyperscaler. They take the gas risk. If they want to offload the gas risk, I have a gas platform where I can help them do that. .

Got it. Okay. Perfect. And then just in terms of PJM and the regulatory process, do you guys see FERC PJM directive opening opportunities for energy to bring new generation to that market? Would you focus on the 1 gigawatt of uprates that you noted in the slides? Or is there opportunity beyond that similar to what you're doing in Texas under the TEF, I guess, how attractive is that reserve auction?

I mean look, I think it's attractive, sir, but I think our focus in PJM at least initially will be the 1 gig of upgrades. It's just faster and quicker to market and the demand is there for Texas. If somebody were to come to us and say that they wanted it in PJM, obviously, we have the flexibility to do that. But I think that we would focus in PJM on the 1 gig of uprates and probably the other 5.4 outside of PJM.

The next question comes from the line of Julien Dumoulin-Smith with Jefferies LLC.

Larry, Rob, congratulations. And Bruce, I swear we will never forget you. With that said, let me come back to a couple of things, right? So first off, on the capital allocation, the 14% here. Just to break that down a little bit further here, how much latitude do you have in that inasmuch as you're not reflecting, I don't believe the CapEx for the data center. I mean presumably, you could be foregoing buybacks in the near and medium-term sense to invest in a longer-term sense in presumably 2030 and beyond if you start to pivot into the data center. So maybe just talk about the latitude that exists within that commitment through 2030 against the buyback numbers and how you could see that shift as you allocate capital?

Again, if I understand it right, the first data center here under your targets with and key it would be a 2029 in service anyway. So conceivably, you'd get some of those cash flows on a run rate basis in 2030. But again, obviously, as you continue to scale the strategy, you need to roll forward that target. So Rob, what do you do in an Analyst Day pro forma with all these data centers is really the other way to ask that. But I'll pass it to you, guys.

Julien, just on the buyback question, I mean, I think as we think about the variability in that buyback number, it's probably more on the back end as opposed to the front end. The $1 billion that were sort of thinking about over the next couple of years is probably pretty set in stone, frankly, from our perspective, and we see ample opportunity to be able to fund these projects while still keeping at least $1 billion buyback program in place. So I don't think there's really any risk on that. And then it's really more about how do we think about the cash flows in the out years, particularly after we've delevered and how that can be redeployed in some of these very potentially lucrative projects.

Any sense on returns, though, maybe that's the other back-handed weight assets is like how are you thinking about what the uprate and/or new data center a counterparty in Texas would look like here?

Yes. Look, I mean, we've always been very consistent about and transparent about what our hurdle rate is. It's 12% to 15% pretax unlevered and every project and every dollar devoted to a project is going to be held against that standard. .

Got it. Excellent. I appreciate it. And then just if I can keep going slightly further here. As you think about this rollout of EPP, I mean just any -- when would you expand that? I mean it seems like you're doing very well against it. I mean I'm curious on how you think about the economics contributing to the story here. Just some brief. I saw the targets in the longer term.

Yes. This is Brad speaking. I've been really pleased with our results in Texas, so we continue to scale in Texas. And then we are looking to launch a VPP like program in the east here early second quarter. That, coupled with our relationships with GoodLeap and Sunrun, we continue to scale batteries up. So we feel really good about what we've learned so far and well ahead of our targets, as Larry had mentioned, and pacing well against the 300-megawatt number we gave you for 2027.

All right. Fair enough. Still, I'm asking, what do we get a robust analyst there, but you don't necessarily to commit to that. All right.

More to come. Every day with us, Julien, is a robust day.

Next question comes from the line of Nicholas Campanella with Barclays.

Congrats to Larry and Rob here.

Before you ask your question, would you also congratulate Bruce, please?

And congrats to Bruce. Yes. Look, good question so far. I just wanted to follow up on Shar's comments and just what's kind of underpinning the 2.5. I think in prior decks, you had this target price for signings above 180 -- or above $80 per megawatt hour. Just -- what are your updated thoughts on where that figure is now? And what's really kind of underpinning the 2.5 year?

So it's Rob. So the 80 -- we adjusted our targets from to an 80-plus kind of range. And as we've talked about them, we've mentioned that if you're going to build 1.2 gigawatts of GEV turbines, that number is going to be on the high end. So as you're thinking about how you get in there, think north of the $90 to $95 range where we were back in our original guidance. It's on the top end, it's got to pay for the equipment, it's got to pay for our return, and we're not going to do a deal unless it does.

Okay, that's helpful. And then maybe just understand the share repurchases, they were going to be affected at all from new build. It sounds like it's more in the back end of the plan. But I guess you have a strategic advantage on costs and securing these turbines early I assume they're going to be project financed. So just what would your kind of targeted equity contribution be? Would it be in the 20% to 30% range? And maybe that's just one way to understand how that could pressure the buybacks.

Yes. Nick, from our perspective, project financing comes -- sometimes it can be great. Other times, it can be not so great. And I think in this particular instance, we really see value and simplicity. We see value in transparency. And so I don't think you should assume that project financing is the way that we would go. I think we would probably err on the side of corporate style balance sheet financing. And on that basis, that means you should be thinking about the capitalization for these projects consistent with what our corporate capitalization would be, which is like that 3x leverage level. .

The next question comes from the line of Michael Sullivan with Wolfe.

I was just hoping maybe we could refresh a little on what the key components of the organic growth beyond 2026, I know you kind of laid that out in bits and pieces over the last year or so. But can you maybe just frame that up between like the test, the VPP, some of the other things, what are kind of the core drivers? And then how much of it is the buyback? I know that's become smaller as your stock has done well.

So in terms of the components that are driving the underlying earnings growth for the business, Mike, it's -- first, it's the $750 million growth program that we had announced back in 2023. We are well on the path towards achieving that. We feel very confident that we're going to be able to get there. And if you recall, about half of that was from just regular way organic growth in the smart home business underpinned by like 6% net subscriber growth. And as you saw, we delivered 9% this past year. So the team is executing very well in that regard. And the other half is really from related growth investments in both the C&I business and the retail energy business.

So again, we feel very confident about that $750 million. The other levers that are embedded in the plan right now are all 3 test plants. Remember, in the past, we did not have all 3 test plants in the plan, but we now have those -- the last of which comes online in. And then finally, we have the 400 change of megawatts of the smaller data center deals that we had previously announced, also embedded in the plan. If you think about what that means in terms of how that shapes our growth in that 14% plus, we talked about when we announced the transaction that was about an 80-20 split of organic growth versus share repurchases driving that growth rate and it's pretty much the same as we sit here today.

And then just in terms of the upgrade opportunities at the LS assets in PJM, any sense of timing there just in terms of -- what we're going to do, particularly with the RBA going on in the background, but also the value of kind of speed and what you could do there, just a sense of timing, that would be great.

Sully, it's Rob. So we already have engineers at every plant running around and assessing not just the 1,000 megawatts of uprates that we mentioned when we did the transaction. we're obviously looking at that. But we're also running around, given the RBA and the need for additionality or bringing more power to the markets. we're running around to see if there's 25 or 50-megawatt clips that we can add on to the back of other assets. So we're out there looking -- expect to hear from us later when we actually have some math.

But given the timing of the RBA and kind of how that plays out, we're working very hard to know what we can bring to serve that market and serve our customers. And data centers want to get built up there, too. So we'll be looking for opportunities to monetize that through hyperscalers.

The next question comes from the line of [indiscernible] with Evercore ISI.

Bruce, congratulations. I got 3 quarters worth of questions that I got to ask. Just kind of considering -- I mean, it's another kind of strong fridge, strong guidance. you've now kind of beaten and raised 3 straight times. Just anything that we could kind of pinpoint like really what's gone well? What kind of exceeded the expectations just over the past -- the recent past?

I mean, with a slight amount of humility, Nick, I'll say it's just we have a great team, and we have great employees, and we just execute really well. I mean, that's really what it boils down to is just execution, execution, execution. We took our lumps in years past. We learned a lot from those. We made a lot of significant operational changes and that is really what's bearing fruit for us. I mean, bear in mind, too, that when we budget and we put out guidance, we plan for weather normalized and depending on what happens with weather, that can also influence the results. And for us, we've had situations where the weather has been favorable for us, and we've been able to take advantage of that.

Nick, I would only add to that, we've created a culture where our employees are always looking to improve, bringing improvements to the table and sharing them in ways probably we've never done before. We are really on NRG across all of our businesses, and that kind of collaboration just we keep finding new ways to do everything we do better and more profitably.

Great. That makes a ton of sense. And then I just wanted to kind of triangulate a little bit, too. So just with the VPP opportunity and now having kind of the RTC +B initiative in ERCOT in Texas, kind of up and running now for about 2 to 3 months. I mean, is there incremental kind of upside for you guys in particularly, just given the amount of data points, whether it be through Vivint or just incremental kind of touch points and able to arbitrage that? Is there kind of -- should we be viewing that as kind of an incremental type of opportunity for you guys?

Yes. I mean it's early days, but we look at this as an enormous opportunity and one that nobody is as well positioned to capture as we are. And when I said at the end of my remarks that the best is yet to come. That's one of the things I think is yet to come. But I think it's an extraordinary opportunity that we're just really beginning to quantify and understand.

The next question comes from Bill Appicelli with UBS.

Congrats to everybody in the room. Just a question around how you guys are evaluating the creditworthiness of the counterparties on some of these data on our deals guys exclusively targeting Tier 1 hyperscalers? Or how are you thinking about evaluating that risk?

Yes. We are -- in fact, I would say that we're targeting even inside of the universe of hyperscalers. We watch all the same credit reports you do.

Okay. And then I guess on the retail channel, you you've rolled in the 400 change of megawatts. I think you had talked about maybe potentially an incremental 500 megawatts within that channel. Is that still an opportunity for you? .

Yes. Look, I think we will still see some of those -- I hate to think of 445 megawatts of smaller transactions, but they're smaller than the other ones they've been discussing. And those are ones that won't be targeted to the folks we were just discussing. So yes, we still think that's a great channel that we'll continue to pursue, and you'll hear more about those going forward. But that's those we're trying to distinguish for these purposes between the large gig plus hyperscaler deals and the smaller ones of the type that we've already -- we announced during the year.

Okay. And then just one last one. On the $2.2 billion of growth in unallocated through 2030, can you maybe just unpack a little bit of how much of that is actually unallocated and so we could just maybe understand a little bit of on the back end of this plan when you start to announce some of these contracts, how much of that is available to be allocated towards servicing the data center projects versus maybe having to pull in from some of the share repurchase bucket?

I wouldn't necessarily -- I'd say if you think about the $2.2 billion, a good chunk of that is devoted to the growth plans that we have, the organic growth plans over the years. I wouldn't necessarily look at that bucket as a significant lever towards being able to contribute to the funding of these data center projects. At the end of the day, it's not like massive dollars that would be able to be redeployed anyway. So I don't think you should be thinking about it that way.

The question comes from the line of Angie Storozynski with Seaport.

So my main question is about your upcoming gas-fired new build. I think I'm still recovering from the PTSD associated with [indiscernible] from the early 2000s and the assumptions that were made back then. I mean, I understand that your contracts will be mainly driven by capacity payments. But I still have only about a 10- to 15-year contract for an asset that has a 40-year useful life. And I'm sure you run the same math that I did. It's not actually so obvious to see that double-digit return over the life of the assets, again, given the short duration of the contract. So how do you address this risk as you park on the gas-fired newbuilds? .

I think there's a few things, Angie. One is length of contract. I think we're looking probably past 10. But if you're looking at the pricing that we're getting and the cost that we're paying. We are not going to do anything that doesn't meet our unlevered hurdle rate that we've announced full stop. I promise you that. And Rob promises to do that, and Bruce promises you that. I'm going to promise for everybody else in the room. But I mean, Angie, I lived through that same period that you did we have 0 interest in being in the speculative new capacity build business, 0 interest. And so the math -- we work on the math all the time and people who want power at a cost less than that. Maybe they'll get it from somebody else, but they won't be getting it from us.

Okay. And those prices that you guys quote for those future contracts, do they incorporate payments for the site. So for example, that would have a $95 plus number that Rob is referring to, does it incorporate a site lease? Or is there an incremental payment, for example, the land itself on top of that. So is $95 just energy or capacity, energy and capacity?

$95 is -- so Angie, it's Rob. $95 is a representation of the bottom end of what the total value looks like from a capacity and variable component, we it's going to be very, very, very heavy capacity. So it doesn't really translate into a dollar per megawatt hour basis. For each of these transactions that we've looked at, the ones that are on our sites also involve a land transaction, which is not incorporated in the number, right?

So the way to think about these is that we are going to get our return and our capital back inside of that 20-year contract as we -- that's how we structure it, that's how we think about it, and that's what we're requiring because we're one of the few people who've got 9 turbines that people can go put on the ground and put next to their data center provide affordability and stay out of regulatory hot water.

Okay. Understood. And then just the last one. The $2.5 billion of an EBITDA upside that you're showing me does that directly correspond with that 5.4 gig in gas-fired new build plus the 1 gigawatt of uprates or is there something else included in that $2.5 billion of EBITDA?

No, it's exactly what you said, Angie. It's roughly 6 gigs.

The next question comes from the line of Carly Davenport with Goldman Sachs.

You highlighted in the slides several hundred megawatts of bridge power available beginning in 2028. Can you just talk a little bit about that opportunity in terms of maybe key suppliers, what technologies you're looking at and just how you view the duration of that opportunity?

Sure. So you know as well as I do that Bridge Power that works is a limited resource out there today. I'm not going to go through names, but I can tell you the technology that we look at as most successful is overengineered reciprocating engines. There's a lot of need for spending steel on systems. And what Bridge Power does is gives an opportunity for scale to scale up their capacity as the CCGT is being built so that they could get on the ground earlier. And I've mentioned before, but when you think of the hyperscalers that we speak to, their desire for Bridge power ranges.

Some people want it, some people don't. And it's all a matter of where they fit kind of in their data center build plan and how fast they need generation on the ground. So we have agreements with Bridge power providers. So we have that limited resource that we can offer as part of a package to hyperscalers and like I said, Carly, of some of our hyperscaler clients want it. Some of them are going down a path where their portfolio will just absorb the CCGTs when they come on. So it ranges but it's a good piece of equipment to have to solve the solution for our customers.

Got it. Okay. That's really helpful. And then I think you also noted a new battery storage contract in at just a gigawatt, I think, expected to be online at the end of this year. Can you maybe just talk a bit about that opportunity and how you could see the battery portion sort of scaling over time?

Sure. So it's a series of contracts that make up over a gig batteries in Texas with their PPAs, right? So it's -- or tolls, sorry. so that we have them in our portfolio. We can use them in the portfolio and use it as part of how we serve our retail customers here in Texas. As we use those and as we operate them, that will help define what our strategy is over the long haul. Batteries provide short-term bursts of power, if you need it. It also provides ways for us to shift renewable power between hours. And so as the customer demand changes or it goes up, we'll look to scale that portfolio if it makes sense. .

The next question comes from the line of Andrew Weisel with Scotiabank.

I think I'll take a different approach. I'm going to say congrats to Brendan and the IR team. I'm just kidding. Congrats to everybody. Just a couple of follow-ups. You covered a lot of ground today, but is you talked pretty positively about the outlook for ERCOT and opportunities for your gigawatt signing homes there. How are you thinking about the banking proposal? Do you worry that might slow things down? Or I think you've had some pretty positive comments here, but how do you see that impacting the pace of signing contracts in ERCOT?

I think the batching work that ERCOT is doing is perfect for the market. It is a great step forward to accelerate the process for people to get data centers and large loads interconnected to the grid. It's actually a very thoughtful approach, and we're I'm very happy that the PUC and ERCOT are making it happen in that way. It makes a lot more sense than a serial process that just stacks up forever. This is a very good thing for us and all of our customers as well as those who want to serve them.

Accelerate, did you say?

I'm sorry? [indiscernible] versus serial processes of do loops and like reevaluating every time somebody puts something in, yes, this will accelerate it versus that. .

Great. And then one more. Just to be really explicit. The guidance, you talked about you're targeting 1 gigawatt of an announcement for 2026. Is your goal to announce the gigawatt, but the financial impact would be upside? Or does the guidance include that gigawatt but not incremental projects? I just want to specify that.

First of all, it's at least or a minimum of 1 gigawatt. I want to make that really clear. And that gigawatt or more than gigawatt is not included in the guidance or in the roll forward outlook.

Final question will come from the line of David Arcaro with Morgan Stanley.

Congratulations, Larry, Rob and Bruce. Let me see -- just one question from me. I was just wondering, in the PJM market, I was -- how has activity in PJM been impacted by the whole backstop auction process and the general policy uncertainty that we've had over the last several months? Has that changed the pace of conversations with data centers and contracting opportunities just given the policy that's in flux there? .

There's a lot of conversations. I mean we've known -- it's always what we've been talking about for a while ago, it was going to be slower than Texas. It's still going to be slower than Texas. They're making progress going forward. But when you're looking at a 20-year investment, there's a lot to put in place anyway. So I think while we'd all like it to be somewhat faster, it's still progress is being made. It's just faster outside of PJM at this moment.

This concludes the question-and-answer session. I would now like to turn it back to Larry Coben for closing remarks.

I want to thank you all again for all of your support. When I arrived, you came on these calls with an open mind, and we're willing to kind of look at NRG freshly. We made you a lot of promises that we kept, and we really appreciate the challenges that you gave us, the feedback that you gave us and the support that you've given us over this last time. And I do mean it when I say the best is yet to come. So thank you all very, very much.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program.

Good day, and thank you for standing by. Welcome to the NRG Energy, Inc. Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Brendan Mulhern, Head of Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to NRG Energy's Third Quarter 2025 Earnings Call. This morning's call is being broadcast live over the phone and via webcast. The webcast presentation and earnings release can be located in the Investors section of our website at www.nrg.com under Presentations and Webcast.

Please note that today's discussion may contain forward-looking statements, which are based upon assumptions that we believe to be reasonable as of this date. Actual results may differ materially. We urge everyone to review the safe harbor in today's presentation as well as the risk factors in our SEC filings. We undertake no obligation to update these statements as a result of future events, except as required by law. In addition, we will refer to both GAAP and non-GAAP financial measures. For information regarding our non-GAAP financial measures and reconciliations to the most directly comparable GAAP measures, please refer to today's presentation and earnings release.

With that, I will now turn it over to Larry Coben, NRG's Chair, President and Chief Executive Officer.

Thank you, Brendan. Good morning, everyone, and thank you for your continued interest in NRG. I'm joined today by Bruce Chung, our Chief Financial Officer; and other members of our management team are also on the line and available to answer questions.

Let's start with the key messages on Slide 4. Strong performance across all areas of the business led us to raise 2025 financial guidance by $100 million in late September. This is the third consecutive year we have increased our full year outlook. And today, we are reaffirming that higher range. We are also introducing 2026 guidance that aligns with our long-term growth targets. This represents NRG's stand-alone outlook and excludes any contribution from the LS Power acquisition. We will provide updated guidance that includes LS Power around the time of closing.

We expanded our data center power agreements this quarter, bringing total contracted capacity to 445 megawatts. We also rapidly grew our pipeline of potential projects under joint development and letters of intent to 5.4 gigawatts. Together, these actions built on the agreement announced in August and reflect rapidly growing momentum and validation of our data center strategy. The LS Power acquisition remains on track. Financings were executed in September on favorable terms, all regulatory filings have been submitted, and we expect to close in the first quarter of 2026.

Turning to Slide 5. Adjusted EPS for the third quarter was 32% higher than the same period last year, and adjusted EBITDA reached the highest quarterly level in company history. I'd like to pause to congratulate all 18,000 of our employees for that achievement. Our results reflect strong performance across both Energy and Smart Home. In Energy, supply optimization and disciplined commercial execution drove margin improvement across both our home and C&I businesses. In Smart Home, growth was supported by expanding our customer base, record retention and continued momentum in our Home Virtual Power Plant initiative. We also delivered top decile safety performance and completed the loan agreement for our second Texas Energy Fund project. Year-to-date, adjusted EPS is 36% higher than last year, reflecting strong performance across all parts of the business as well as continued cost discipline. These results keep us firmly on track to achieve our raised full year 2025 guidance ranges.

On the right side of the slide, we are introducing 2026 guidance on a stand-alone basis. This serves as an interim view ahead of a full update after the LS Power acquisition closes, when we will provide guidance for the combined company.

Moving to Slide 6 for an update on market conditions. ERCOT experienced a mild summer with moderate pricing and strong growth in overall power use. Total consumption across Texas has increased nearly 30% over the past 5 years, driven by residential, commercial and industrial demand as electrification and onshoring of manufacturing accelerate. Data center development usage remains early with ramp schedules expected to add meaningful capacity over the next several years. Looking ahead, power demand is projected to outpace new supply, keeping the market structurally tight and reinforcing the need for reliable, dispatchable generation. Policymakers are responding through initiatives such as Senate Bill 6 in Texas and similar efforts in other regions focused on affordability, additionality and reliability. We are encouraged by the focus and progress being made to strengthen ERCOT and other competitive markets across the country.

In this environment, NRG is expanding its portfolio of reliable and flexible capacity. Through the LS Power and Rockland acquisitions, the Texas Energy Fund projects and our Home Virtual Power Plant, we are adding 15 gigawatts of natural gas and 7 gigawatts of Virtual Power Plant capacity. We also see about 6 gigawatts of additional opportunities through the GE Vernova partnership and our final test project that is still under review. Together, these actions strengthen our platform and position NRG to meet rising customer demand and support large load growth, including data centers across ERCOT, PJM and other key markets.

Turning to Slide 7. We expanded our data center customer portfolio to 150 megawatts of new premium long-term power agreements, bringing total contracted capacity to 445 megawatts across ERCOT and PJM. This builds up a framework announced last quarter with the same customer. These sites located in Maryland and Illinois support edge data center development with access to high-capacity fiber and proximity to major U.S. cities. These projects will be built in PJM with operations beginning in 2028 and ramping through 2032. This agreement was signed above the midpoint of our prior $70 to $90 per megawatt hour target rate. Given continued strength in customer demand and higher forward power curves, we are raising our target for new long-term data center agreements to above $80 per megawatt hour. This reflects sustained pricing improvement and NRG's leadership in providing reliable long-term power solutions for large loan customers.

We are advancing numerous additional opportunities, including up to 5.4 gigawatts of new capacity for data centers through 2032 under our GE Vernova and Kiewit partnership, supporting the principle of additionality. Since last quarter, side letters of intent have increased 35%, underscoring customer engagement from multiple hyperscalers and data center developers as well as growing demand for new development. We also see several additional gigawatts of potential projects across our broader pipeline. As markets evolve to bring your own generation models, NRG is leading the next phase of data center growth.

Turning to Slide 8. The LS Power acquisition remains firmly on track for a first quarter 2026 close. It strengthens our platform broadens our earnings base and extend our reach across key competitive markets. It reinforces our position as one of the largest competitive generators in the country and increases our leverage to long-term demand growth. At announcement, the acquisition was immediately accretive across all key metrics, reflecting portfolio quality and an attractive purchase multiple. We also unveiled a 14% EPS CAGR through 2029 which does not, I repeat, does not include any contribution from data centers and reflects pricing assumptions that are below current market levels. These factors, along with other upside opportunities underscore the significant potential ahead.

Since announcement, incremental benefits, including 100% bonus depreciation, have further enhanced the economics. All required filings have been submitted and financing was completed on terms better than originally projected. The transaction positions NRG for stronger long-term growth greater scale and enhanced value creation as we bring the new platforms together.

With that, I'll turn it over to Bruce for the financial review.

Thank you, Larry. Beginning with Slide 10, NRG delivered strong financial and operational performance in the third quarter was $2.78 in adjusted earnings per share and $1.205 billion in adjusted EBITDA representing a 32% and 14% increase from the same quarter of 2024, respectively. Adjusted net income was $537 million and free cash flow before growth was $828 million.

Through the first 3 quarters of 2025, NRG delivered $7.17 of adjusted earnings per share and over $3.2 billion of adjusted EBITDA, a year-over-year increase of 36% and 12%, respectively. Our exceptional quarterly and year-to-date financial performance reflects continued execution in all of our businesses, driven primarily by a mix of expanded margins favorable weather and excellent commercial and operational execution.

Our Texas segment delivered third quarter and year-to-date adjusted EBITDA of $807 million and $1.618 billion, respectively, representing an improvement of 38% and 29% from the same period in 2024. These results were driven by margin expansion across our operations in the region with lower realized supply costs and excellent optimization despite low summer volatility. The East segment contributed adjusted EBITDA of $107 million in the third quarter and $680 million through the first 3 quarters of 2025. These results reflect a modest decline from the same period of 2024, primarily driven by the net impact of higher supply costs throughout the region, partially offset by increased capacity revenues at our plants and favorable weather in the first quarter, which benefited our natural gas business.

Our West/Services/Other segment had adjusted EBITDA of $19 million in the third quarter and $139 million for the first 3 quarters of 2025. The segment realized higher retail power margins, which were offset by the absence of earnings from the sale of our Airtron business in 2024 and the lease expiration at the Cottonwood facility in May 2025 when compared to the same periods of the prior year.

Our Smart Home business posted another impressive quarter and executed brilliantly through the key summer selling season, achieving adjusted EBITDA of $272 million in the third quarter and $803 million through the first 3 quarters of 2025. The segment continues to see record new customer adds and retention rates as well as expanded net service margins. Our consolidated free cash flow before growth was $828 million for the quarter and $2.035 billion for the first 3 quarters of 2025. Year-to-date, free cash flow before growth exceeded the same period in 2024 by $597 million or 42%. The year-over-year increase is primarily driven by the higher year-to-date adjusted EBITDA, favorable working capital timing and receipt of the remaining insurance proceeds from our Paris unit [ e-claims ]. We expect some of the year-over-year favorability to moderate as working capital timing normalizes in the first -- in the fourth quarter and as we continue to invest in our plants through our scheduled maintenance program.

Looking to the remainder of 2025, we are reaffirming the increased financial guidance we announced last month with ranges of $7.55 to $8.15 for adjusted EPS, $3.875 billion to $4.025 billion for adjusted EBITDA and $2.1 billion to $2.25 billion for free cash flow before growth.

Moving to Slide 11 for updates to our capital allocation for the remainder of 2025. This has been updated to reflect the new midpoint of our raised free cash flow before growth guidance target setting the total capital available for allocation in 2025 at $2.7 billion. Note that this slide excludes proceeds received from the $4.9 billion of new debt raised in October most of which will be allocated to fund the cash portion of the pending LS Power transaction. A few other updates from what I shared in our second quarter call are denoted in light blue.

Starting with an update to liability management. The $52 million increase primarily reflects transaction costs and financing fees associated with the LS Power transaction. Integration costs increased by $20 million due to a shift in spend from 2024 to 2025. The net total remained largely consistent with our communicated expectation between the 2 years. We remain on track to execute the full $1.3 billion in share repurchases slated in 2025. Through October 31, we have executed $1.084 billion in share repurchases were nearly 85% of our planned annual total at a weighted average price of $125.35, and expect to complete the full amount of share repurchases by the end of the year. Other related activities increased due to higher tax withholdings related to equity compensation resulting from the increase in our share price. The increase in the revenue synergy growth plan reflects the strong customer growth our Smart Home segment has delivered through the year.

Customer growth for the business was 9% year-over-year, while surpassing the targeted 5% to 6% net customer growth embedded in our growth plan. On other investments, we are showing a net $30 million inflow of capital related to our Texas newbuild program. As you may recall, the stipulated capital structure for projects under the Texas Energy Fund program, is 60-40 debt to equity. In order to get our TEF projects to that target capital structure, the initial disbursement under the loan took into account previously spent development costs. Given that catch-up mechanism under the loan, the disbursements we received in 2025 exceeded the amount of capital we expect to spend on the projects, therefore, resulting in a net inflow of capital for the year. Finally, we are on track to finish the year with $158 million of unallocated capital, which we currently plan to roll over into 2026 and deploy as part of our 2026 capital allocation plan.

Turning to the next slide. We are initiating our 2026 NRG stand-alone financial guidance at ranges of $3.925 billion to $4.175 billion for adjusted EBITDA representing a midpoint of $4.05 billion and free cash flow before growth of $1.975 billion to $2.225 billion, representing a midpoint of $2.1 billion. We are not providing stand-alone EPS guidance as we acknowledge that EPS will change materially with the closing of the LS Power transaction due to associated accounting adjustments pro forma capital allocation and other matters impacting any per share financial metrics.

As you can see on the slide, we have included the same adjusted EBITDA and free cash flow before growth for the acquisition, which we provided when we originally announced the transaction in May. This, combined with the 2026 NRG stand-alone guidance that we are initiating today should remind people of the pro forma company's earnings profile. We will provide an updated pro forma view once the transaction is closed, which we -- which will include updates to items like energy and capacity prices, accelerated depreciation benefits and pro forma capital allocation among others.

On the bottom of the page, we have provided walks from the midpoint of our original 2025 guidance to the midpoint of our new 2026 guidance on a stand-alone NRG basis. For adjusted EBITDA, the net $200 million increase year-over-year is primarily driven by the addition of the Rockland assets acquired earlier in the year, the impact of higher power pricing in our Texas segment and the continued execution of our existing $750 million growth plan. The impact of higher power pricing in Texas that we are showing is consistent with the sensitivities we have provided in our previous earnings materials and reflects an increase in around-the-clock pricing from the $47 we previously used $53 per megawatt hour, which reflects Texas pricing at the end of July. The sum total of these year-over-year increases is slightly offset by other minor drivers such as regulatory developments negatively impacting the Maryland and New York competitive retail markets and tariff impacts on our businesses.

On free cash flow before growth, we expect strong year-over-year growth from core operations amounting to $145 million, comprised of the previously discussed EBITDA growth partially offset by the continued investment in our generation fleet. After taking into account higher cash interest and taxes, we forecast free cash flow before growth to be flat year-over-year. The higher cash interest is largely driven by refinancings of very low cost debt that was issued when the Fed funds rate hovered near 0%. The increase in cash taxes primarily relates to fewer federal tax credits available to offset income than in prior years. Just to reiterate, we will provide a more detailed update on pro forma financial metrics once we close the acquisition. I look forward to sharing that update with you soon.

Moving to Slide 13 for a brief discussion on 2026 NRG stand-alone capital allocation. The key takeaway here is that we remain committed to our return of capital program through share repurchases of $1 billion and our planned 7% to 9% annualized growth of the common dividend per share. This is the case both on a stand-alone and pro forma basis. I'm also pleased to share that our Board has approved a new $3 billion share repurchase authorization to be executed through 2028.

As you can imagine, certain elements of this chart suggests the starting point for excess cash and liability management will look very different after we close the acquisition. As such, I do not intend to go further into detail on this slide. We will provide a fulsome update on capital allocation alongside our key financial metrics once we close on the LS Assets acquisition.

In closing, NRG has delivered outstanding financial and operational results through the first 3 quarters of this year, and we are poised to finish the year on a high note. The stand-alone 2026 financial guidance and capital allocation outlook I have shared today further demonstrates the solid growth and continued performance of our stand-alone base business. I look forward to providing you updated and detailed guidance for 2026 that includes the assets we are acquiring from LS Power following the closing of the transaction.

With that, I'll turn it back to you, Larry.

Thank you, Bruce. Turning to Slide 15. 2025 has been an outstanding year across every part of our business, and our outlook continues to improve. Our near-term focus is on completing the LS Power acquisition and providing you with an updated long-term outlook following the close. We also continue expanding our data center portfolio, advancing our Texas energy projects, including completing the construction of the T.H. Wharton project, and returning at least $1.3 billion to shareholders. These priorities reflect a disciplined approach to growth and capital allocation as we position NRG for 2026 and beyond. Continuing to build a company defined by consistent execution and accelerating value creation.

With that, we'll now open the line for questions.

[Operator Instructions] Our first question comes from Shar Pourreza with Wells Fargo.

Shar welcome back to the workforce.

I'm ready to go back to [indiscernible], to be honest.

I want to see the flowers Shar. I want to see the flowers.

There you go. So Larry, just do you think '26 is kind of that year, you're going to be able to announce a data center agreement that includes new development as part of your GEV Kiewit partnership?

Yes. Well, Shar, you remember, the last time I gave you a one-word answer and showed up. So I'm giving you a one-word answer.

Any sense around timing next year? Are we thinking back half or earlier part of the year?

It's hard to tell, Shar, as my good friend Max said yesterday, these are complex, but super excited by the process and never been more sure.

Got it. Okay. That's helpful. And then just lastly, just maybe share a little bit more about sort of the announced data center deals, how they kind of compare to those announced by your peers. So a little bit more color around the margins given other peer deals have come with generation linkages?

Yes. We've put a little slide in the appendix, which kind of talks about margin and pricing. This is very similar to the one that we announced last quarter, just locationally different. Premium margin as a result, different things go into getting our premium margin on any deal, including land, including our commercial acumen. I mean I really need to say we have the best commercial team in the business at both gas and electricity, being able to really meet customer needs in a flexible way. All of those lead to the margin that you see on that appendix Shar.

Our next question comes from Julien Dumoulin-Smith with Jefferies.

Let's -- look, look, let me jump back to the -- let me ask the same question that everybody just asked a second ago in a different way. As far as GEV goes in this Kiewit partnership, do you have a certain time frame that you need to move some of this equipment and use it or lose it, if you will? Can you speak to that a little bit? Because I think that's probably an important nuance to speak to when you talk about your confidence and the time lines under which you're operating to execute on this.

Look, Julien, we haven't disclosed any time lines, but we're -- I'm very confident that we're going to meet all of the time lines that are required under that agreement. But what you're really trying to do, Julien, I know his pin me to a month, and I'm not going to let you do that.

Absolutely. You know we're all trying, I mean, [indiscernible].

I appreciate the effort it was well done, but...

Not quite there. I got it. Well, let me ask you this way. As far as it goes with the Build Your Own Power, BYOP as we're calling it, right? Like there's clearly been an evolution in the marketplace. When you think about the scope of what's possible here, again, I know folks have been looking at colocated opportunities in the last couple of years, but now we've firmly shifted how meaningful, right? We've seen a few announcements here with a couple of hundred megawatts here, a couple of hundred megawatts this quarter. I mean when you say you're going to deliver updates next year, can you speak to BYOP and the scale of what's at hand here in terms of really building out contract gen?

Sure. Look, just starting with the GEV Kiewit deal, Julien, that's 5.4 gigs. So that's a good place to start from. I mean there are some things that could be added to that in a variety of ways that we're looking at. But I think if we brought even 5.4 gig to the table, you would be -- and everyone would be super happy for us. So I mean, the scale -- I mean, that's kind of the scale that we're focused on right now, but we are looking at opportunities to see how we can make that even greater.

Got it. And then let me just shift this slightly. When you think about the focus here, I mean, a lot of conversation has been around your portfolio in Texas and ERCOT specifically. Can you speak a little bit broadly. Obviously, you guys have Illinois site, PJM's talking increasingly about bringing new assets before Illinois just passed legislation in recent weeks. For instance, is there an opportunity in the PJM portfolio to both add [ Gen ] gas and storage specifically and perhaps tap into some of these developments that have been recently a foot to kind of quell the state's needs for new capacity?

Absolutely, Julian, and we are working hard on that, and we'll really accelerate those efforts, of course, once LS closes because until we own the generation assets there, that will really fault us into being a significant player, but we're -- there's no grass growing under our feet there in the meantime.

Got it. All right. In Illinois legislation, is there something for you guys to do there specifically to ask that more pointedly?

I don't think the legislation is really going to be the driver of this, Julien. So -- but as you know, we do have sites in Illinois.

Our next question comes from Angie Storozynski with Seaport.

So first of all, [indiscernible] of the slide showing the sensitivity of your gross margin to changes in forward power curves. I mean we've had finally the move in foreign curves we had waited for. And so I'm just wondering if anything's changed there? Are you waiting to update it for your enlarged portfolio? Any comments.

Angie, you just hit the nail on the head. We are waiting to update it for our enlarged portfolio.

Okay. And you're not going to give me any sense how especially the PJM price is moving, how they are impacting the pro forma EBITDA of the company for now?

Not at this stage. Well, certainly, we will provide, obviously, a very fulsome update soon after we close on the transaction.

Okay. And then the second thing is we've had some companies new power companies or pretending to be new power companies that have aspirations to build gas plants without any prior expertise in power. So I mean it is surprising that they could be ahead of you in the pecking order, if not for the fact that you guys actually have sites have equipment know-how to hedge gas, et cetera. So is it that they just talk more about their opportunities versus you guys? Or do you still feel like you have a head start over those companies?

Angie, I'm convinced that we're in a great position to do what I was describing. It has this a long time so of you, there's a lot of announcements when I actually see to use [ Sam Alten's ] new term electrons flowing, then I will actually believe that they're real [indiscernible] you will see steel in the ground. But we're not one -- we tell you what we've done. We don't tell you what we're going to do, and that's kind of my philosophy and all this. So there's going to be a lot of announcements because a lot of people think they're data center and power developers, some of those probably real. But I'm very, very comfortable with where we sit in the pecking order, both with respect to building power plants and with respect to hyperscalers.

Okay. And then one more. I mean we are still seeing a lot of assets, private assets being offered to companies like you, hopefully, you do have a large pending acquisition. And I'm just wondering if you would still have interest in single-asset transactions before the [ Avista ] transaction closes?

We look at everything. And if there's something that's economically attractive, that's a great fit for our portfolio. We would be interested -- we don't feel we need to add any additional capacity given the LS acquisition, the Rockford acquisition and the test projects, but we are always opportunistic when these things are out there.

And then lastly, Bruce, you mentioned the free cash flow guidance for '26 and the fact that you're sort of running out of the tax shield. I mean, the [ Elasto ] transaction brings the back Shield, right? So there would be presumably an improvement sort of free cash flow generation of the current business on the back of that transaction. Is that fair?

Yes. I think that's generally a fair statement, Angie. The one thing that I'll just clarify for you is that uptick in cash tax that we talk about on a stand-alone basis, is it necessarily related to our NOLs disappearing. It's really more about certain tax credits that we had from our days when we owned renewable assets that eventually expired. And so regardless of the LS transaction, we're still going to have a very sizable NOL position. But clearly, the last transaction is going to give us even more, which should [indiscernible] to a cash flow benefit.

Next question comes from James West with Melius Research.

Larry in your prepared comments, both at the beginning and the end, I think you made it very clear that you guys are not just standing still waiting to close LS, but you've got a lot of a lot of other things going on. If you were to kind of rank order what you're most excited about outside of that transaction, what would you say the top kind of 1, 2, 3 other things, items that you're waiting to hopefully announce to us in the near term?

Well, I'm going to do them in no particular order because otherwise, that's like picking favorites among your kids. I mean we have both on the C&I and on the retail side and Energy and in [ Spartan ], we have a lot of -- people kind of lost sight of we have a very exciting growth plan where we're killing it. Second, our residential VPP excites me tremendously. And after LS close, I'm also even more excited about our demand response potential. So I look at all of those things. And I guess the fourth thing I would say is bringing our first test project online and making progress on the other 2. So there's a lot going on here that we don't -- we haven't even begun to put into our numbers. And so even if there were no -- I just -- as a reminder, even if there were no data centers at all and no changes in power prices, we're still showing a 14% CAGR, and we still have a double-digit free cash flow discount rate.

So I'm sorry, I'm super excited about that. I don't know where I could get in the market such with not much downside those kind of numbers, leaving out all the other great things that we're doing. So I am as bullish as I've ever been.

Okay. Good to hear. I'll leave it there.

Our next question comes from Nick Campanella with Barclays.

Maybe I could just follow up on the BYOP combo. Just your conversation with policymakers at the states you operate in, how does that look in terms of BYOP? How have the customer conversations evolved over the last 6 months? And is it a fair assumption that all deals going forward just need some type of additionality in this space now? Or how would you kind of frame that?

I mean I don't -- speaking to all deals is hard, but it starts with the Secretary of Energy, who's been very, very explicit on this. And I think as regulators more and more look at the affordability question and how to distribute the cost of this new power, the simplest way to do it and the fairest way to do it, I think, is probably bring your own gen. Now whether that's megawatt hour per megawatt hour or 75% or 50% or some other measure, I think, remains to be seen.

But I think every policymaker is looking at this for 2 reasons. One is the affordability factor, and two is everyone knows they need new power, everyone knows they need new infrastructure. So to the extent if you're the governor of, say, New Jersey or Pennsylvania or somewhere like that, you would rather spread that cost across Amazon or Meta's or Google or Microsoft, billions of customers around the world rather than your own rate payers. So this is a trend that we started talking about a year ago and prepared for it with our GEV and Kiewit joint venture, and it's now really coming home to roost and accelerating in the last few months.

Definitely recognize that. Thanks for the thought. Maybe just with PJM being a more important jurisdiction pro forma this LS Power deal, can you talk about the capacity auction and just the prospects and timing for the collar to potentially be extended? Or just what you're advocating for with stakeholders, where you think the industry is heading and ultimately what outcome you think would be good for the industry?

It's Rob. Look, nothing's changed since the last auction as far as supply and demand. So I would expect that, that means that we're going to price at the top of that cap and collar. The -- as far as long term goes, they're looking at lots of different ways to solve the equation. Ultimately, everybody is generally concerned about reliability and they're concerned about things like affordability but in order to get reliability, you have to have price signals. And so the market has to reflect something for something to get built.

As far as the color being extended, we were supportive of the caller last time. I could see it being extended again because it provides certainty for everyone in the market. Whether or not the top end of that collar is at the right place, that's yet to be determined.

Our next question comes from Carly Davenport with Goldman Snacks.

Larry, you mentioned before your excitement about the [ resi ] VPP program and the pilot there. I guess any updates on how that's tracking in terms of uptake? And if that's something that we should expect to see sort of regular updates on in subsequent calls?

Yes, I'm going to kick that over to Brad.

Thank you Yes. No, we've been very pleased with the progress on VPP. So as you're aware, we did raise guidance early this year for the balance of 25, so we went [ 120 ] megawatts to [ 150 ], and we remain on track for our 1 gig by year-end. We received the grade [indiscernible]. So sorry. I would say things [indiscernible]. We see a lot of good feedback from customers about the value and the experience of our offerings. So we're really excited about that, and we're actually installing more customers than anticipated.

And I think as we had shared in our last earnings, we're actually seeing the upgrade of additional equipment kind of 2x our expectations. But apart from that, we're also piloting some additional new home automation offerings which not only deliver the demand response, but will also help reduce home energy consumption, which will enable us to offer customers home energy savings. So as affordability and great capacity become more critical energy, we really have the only solution to meet those needs to be able to reduce energy consumption and save customers funding. So we're really excited about piloting that, not just in Texas, but we will also be taking that out to the East early next year.

Great. Okay. That's super helpful. And then maybe just on the data center pipeline. You have one agreement with first delivery in '26 and other in 28. I guess is there any trends that you're seeing in terms of when customers are looking to be energized on these fields?

I mean I think they're looking to be energized as quickly as possible, but there are some bottlenecks of, as you know, with interconnection and things of that nature as well as if you do really need to bring your own power plant, obviously, that doesn't occur in a day. So I think customers would love to start ramping yesterday, and they're doing what they can to do that. But I think if I look at the graph from now through 2031, there's more and more power coming on ramping each of those years.

So I don't think anybody comes to the table thinking, well, we really want to start in 2033, but I think they're also realistic about building their own businesses and the constraints that exist.

Our next question comes from David Arcaro with Morgan Stanley.

When you say that you're -- let's see, on the data center power agreements increasing your kind of expectations for pricing to now be above $80 a megawatt hour what's that reflecting? Is that a reflection of where market prices have gone and just thinking about the upper end of your prior 70 to 90 range. Like does that upper end go up as well? Kind of curious just like would you be repricing like Bring Your Own Power type deals also upward?

Well, I think everything is pricing upward as a result of increasing demand. If you look at the capital expenditure announcements by the hyperscalers, they continue to rapidly increase across the board. I think it's a recognition from people of the commercial of our rather unique ability commercially to supply them in ways that they want to be supplied and to bring new power to the table. And just really heightened interest from multiple hyperscalers and developers in a very accelerating fashion, just kind of using the basic laws of supply and demand. So all of those are factors that led us to raise this really to kind of take the top off the range and raise the bottom of the range.

Got it. Okay. Great. That's helpful. Then separately, I was just wondering if you could comment on the retail competitive backdrop, retail -- your outlook for retail margins from here? Can they remain strong looking out into your forecast?

Yes. We -- this is Brad. We continue to see strong margins in Texas. And we have had -- primarily because of the competitive marketplace. And so as prices have gone up, we've been able to maintain those margins. As I mentioned earlier, we are looking at solutions to help give some customers' relief in terms of helping reduce energy consumption. As we know affordability will be a challenge, as everyone does raise prices.

In the East, a little bit different dynamic when we're up against the price to compare. And so that one, we have seen a little bit of margin erosion that we are managing very closely. But as I mentioned earlier, being able to bring an integrated value proposition to the consumer that gets beyond competing for price per kilowatt hour and gives them a solution that actually brings our energy consumption down and give them home protection, home automation in the home. We believe that's a solution that we will be able to scale and slightly change the conversation. So a little bit different dynamic, as you know, between the East and what we see in Texas.

Our next question comes from Ryan Levine with Citi.

Hoping to follow up on the Smart Home business. Good to see the 9% annual year-over-year growth there. What are you assuming for '26 stand-alone business contribution for Smart Home growth? And how do you see that trend evolving into your longer-term outlook?

Yes. In terms of customer counts, we're assuming something very similar to what we saw this year. We've seen really strong growth across really all of our channels of distribution. We're also launching more of a good, better, best. Historically, [ Devin ] has been pushing the higher-end systems, but we're able to, as I mentioned earlier, offer a much more affordable entry-level offering that not only gives customers some security protection, but also that energy management savings that I touched on. So with the additional kind of good, better, best, it opens up new channels of distribution. And so we expect really strong growth in '26 as well.

Ryan, I just want to remind, when we announced that $750 million growth plan, we had indicated Smart Home net customer growth to be in that 5% to 6% range. And so I think when Brad alludes to the customer growth that we're assuming for '26, it's still going to be pretty consistent with that original growth plan -- probably higher.

And then in terms of the hyperscale or data center conversations, I appreciate the additional guidance around pricing and momentum. But in terms of duration of the contracts, are you seeing any change there around the tenor of contracts that the customers are looking for as demand has continued to accelerate?

No. We still continue to see people wanting at least 10 years some even more than that. So if anything tenure will be -- is increasing, particularly if you're going to bring your own generation, you really need a longer tenured contract in order to drive your own cost down. So we're seeing longer contracts, not shorter ones, Ryan.

Okay. And anything around inflation provisions? Are they becoming the more standardized around some of the other commercial terms embedded in these contracts?

I mean we are -- most of the contracts are going to be allowing us to pass-through and allow us to keep our margins relatively fixed kind of across the board for a variety of factors.

Our final question comes from [ Andrew Weisel ] with Scotiabank.

Good morning, everyone. Thanks for including me. First question on buybacks. I see that you're guiding to a moderation in next year to $1 billion. I think you previously alluded to that, forgive me, I'm still a bit new to the story. Is that a function of LS Power and TEF CapEx, which is sort of onetime in nature? Or should we think of the $1 billion as a good run rate going forward? I can do the math, $3 billion through 2028 kind of implies that, but how are you thinking about this longer term?

Yes. It's really just staying consistent with what we had indicated when we announced the LS Power transaction, Andrew. We had indicated buybacks of $1 billion per year until we get through our deleveraging. And so that's all we just wanted to keep it consistent, recognizing that we were going to be updating capital allocation once we close.

Okay. That makes sense. And similarly, on that last point there, you said that you'll update all the financials when LS Power closes. Does that mean like an 8-K or a press release as soon as it closes? Or are you talking about the 4Q update in February?

I think it's really just going to be dependent on when we actually close and how that timing lines up with when we might otherwise regularly report earnings, fourth quarter earnings. And so we'll assess based on where things are lining up with respect to close to figure out what's the best way to communicate with the investment community will be.

Okay. That makes sense. And one last one. You covered a lot of good details. So this is kind of a nuanced one, but I'm seeing some headlines that a potential sale of the [ Gladstone ] asset in Australia. A lot of people might not even remember that you have that, but how are you thinking about that asset? And could there be value there?

Look, I mean, we don't -- to the extent that there is value, it's really more -- it's going to be nominal at best. I wouldn't necessarily think of that as being a particularly significant driver. And if anything, it's really more to just continue to simplify our portfolio and streamline our operations.

I'm showing no further questions at this time. I'd now like to turn it back to Larry Coben, for closing remarks.

I want to thank you all for taking the time to listen and for your interest in NRG. I have never been more excited about our prospects as we are today, and I look forward to seeing you all on road shows and wherever so that we can discuss them in more detail.

Thank you, operator, and thank you, everyone.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program.