NRG Energy, Inc. (NRG) Q2 2026 Earnings Report, Transcript and Summary

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 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'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 the 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 it 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 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 the 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 2 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 customer's 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 operation. 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 -- 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've 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 upgrade 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 the 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 core 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 deleveraging 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 pre-existing 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, pre-existing 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 investments 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 investment, 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 the 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 deleveraging 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 (sic) [ $932 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 unlevered 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 a 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 a kW, with capital deployed over 4 years and the largest 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 largest outlays occurring after key milestones. We retain 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.

Congratulations, guys, on 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, shall 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 this is the first one and potentially the cheapest?

Yes. So there's a lot in there, Julien. So thank you. 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, that doesn't rule out taking 2.4 somewhere. That doesn't rule out 4.8 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.

Julien, 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, so 1.2 to come on serially year -- each year after the 2029 COD for the first one.

Got it. Okay. 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 concerned?

Okay. So on the contract duration, we've told you guys 15 to 20 years. This particular structure is 15. 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 governor 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 some 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 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 of Shar Pourreza of Wells Fargo.

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 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 a -- they've seen the structure, they agree 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, I mean, 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 BBB? 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 his head, saying, don't answer that, Rob. Don't answer that.

He is so happy with that answer.

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. So 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 off 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 built as much flexibility in here because we started from the beginning with what do our shareholders need, how do we serve our customer 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 gigs of upgrades 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're 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 upgrade opportunities, are you able to share how much of the 2 gigawatts is kind of economic at the $555 per megawatt day cap just to sort of size the 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 would go through that auction that way. But we continue to have bilateral conversations on all 2,000 megawatts.

Got it. Okay. Very helpful. And then maybe just on the capital allocation side, as you talked about in 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've previously spoken about being able to hit our 3x leverage ratio in 2028. If we were to move -- do this project and fund it 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.

Okay. 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 still in 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.

Okay. Very helpful. And Rob, if you could just give us your latest thoughts 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 batch 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 into a little bit into '28. If the data center market -- or sorry, 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 5 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 debt. 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.

Yes. 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 it's going to be basically Holdco unamortizing debt, right? So when I try 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?

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 for this 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 2 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 the OEM providing everything view 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 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 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 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.

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 passed through on grossed up to revenue? And given later projects would have higher-priced turbines and EPC, is it fair to then assume cost of new entry you might assume on CCGTs 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.

And Moses, on the future -- just to be clear on -- 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 conversation with customers about that. We will always sign deals inside of our 12% to 15% hurdles always.

Got it. 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 switches on immediately upon COD.

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

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

Yes. So Nick, I mean, obviously, as we said on the -- 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 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.

Great. And then just as we think about the upgrade 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 -- 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.