Prepared remarks
Good day, and thank you for standing by. Welcome to NRG Energy, Inc.'s Second Quarter 2026 Earnings Call. Operator instructions were provided. 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 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 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 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 growth toward 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 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 $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 commercial operation, 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 commercial operation date. 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.
Questions and answers
Operator instructions were provided. 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 team. 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. It seems that some of your sites have the opportunity to expand to that full 2.4 gigawatts. 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 commercial operation date. 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. 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, that's 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 is the delivery of these projects is the commercial operation dates of construction and the turbine deliveries themselves. Depending on how the customer wants to go, where the sites are going to be and when we can get the turbine on the ground, that will determine the speed that we go. 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 GE Vernova 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. 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, 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 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 to see.
Julien, on the commercial operation date point, I'll just add. So this first one is late 2029. What we've said previously is the way that the GE Vernova and Kiewit structure is organized, you can assume there's another block, so 1.2 to come on serially each year after the 2029 commercial operation date 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 complement to 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 timeline as far as you're concerned?
Okay. So on the contract duration, we've told you 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 for the customer. On the Texas governor's announcement, I understand where the politicians and regulators are in Texas. I tried to make that point in my prepared remarks. Our project answers those questions. 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. As far as timing goes, Texas is a state that gets things done. I expect them to work through matters to get to a higher-quality understanding of projects as development advances. And remember, this is a commercial operation date in 2029. So I think we're okay.
Our next question comes from the line of Shahriar Pourreza of Wells Fargo.
Can you elaborate a little bit on the actual progress that's being made and what drove the confidence to announce the principal terms at this stage? 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 and the strategy of how we're delivering on our GE Vernova and Kiewit turbines. 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 as we've stated today, we are commercially aligned, meaning that the customer has seen the structure and agrees to it. We are in close conversations every day about specific timing or a piece of land or related matters. The things that remain outstanding include continued negotiation on remaining details, required internal approvals and the usual development items. 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. The next time we'll come back to you, we'll tell you when we have another material piece of information to discuss. I'm not going to set the negotiation team up with a public timeline to work against. But I feel 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, given some of the noise around collateral requirements, can you elaborate a little bit on the counterparties? It's obviously investment grade, but is it BBB? Is it single A? Can you elaborate on the credit quality of the counterparty?
To quote my predecessor, no.
Our next question comes from the line of Nicholas Campanella of Barclays.
Appreciate all the updates on the BYOP deal. Just a follow-up on the contract details. You used to talk about targeted pricing around $80 plus per megawatt hour. With the returns on the slide and CapEx a bit higher, is the PPA equivalent now north of $90 or north of $100? Any comments there, given the structure is a fixed capacity charge pass-through, how should we think about that?
Given the structure, the dollar-per-megawatt-hour metric is less relevant because of how we've structured it. If you were to do the math and assume expected usage of the data center, it's probably in the $85 to $90 plus range. But we really don't focus on that metric. The structure provides the certainty and returns that we need for our investors, and it also provides flexibility for the customer to manage their own risk depending on their views. We could hedge the variable piece if they wanted, and that collateral would be their requirement. We built flexibility into the structure because we started by considering what our shareholders need, how we serve customers and how we serve communities. That's how we've approached data centers.
Maybe pivoting quick to just PJM. You outlined in your contracted cash flow visibility walk the potential to do something with the 2 gigawatts of upgrades in PJM. Can you update how you're thinking about the bilateral process or procurement and how to think about that?
It's a multipronged approach. There's the long-term auction opportunity, which we will bid into, and we're also in bilateral conversations now. The additional capacity from those upgrades is valuable to anyone connecting inside PJM and wanting to avoid curtailments. We know it's valuable and we are continuing to monitor and we will bid through any process. The way to think about it is we will invest capital where we can get long-term durable cash flows. Fifteen-year auction proceeds make sense, and so would a bilateral conversation of similar 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. As you think about the upgrade opportunities, are you able to share how much of the 2 gigawatts is economic at the $555 per megawatt day cap just to size the opportunity on the central procurement side?
If you interpret that $555 cap as preventing procurement above that level, then it's probably less than half of the 2,000 megawatts that would go through that auction in that way. But we continue to have bilateral conversations on all 2,000 megawatts.
Got it. Okay. Very helpful. And then on the capital allocation side, you talked about it largely coming through the buyback program for the year. How are you thinking about potential incremental capital to allocate there given where the equity is trading from a valuation standpoint?
Carly, as we sit here today, to the extent we have the ability to upsize the buyback program, that will depend on where we land from a cash flow perspective for the year. If we're executing against this project and spending the capital we've outlined, that's where we'd see the money going because we see this project as being really valuable. But if the opportunity exists to upsize the program with incremental cash flow, we'll definitely consider doing so.
Our next question comes from the line of Michael Sullivan of Wolfe Research.
Could you elaborate more on what you're looking at on the funding side? You alluded to potential capital partners. We've seen peers do similar transactions. What can that do for you from balance sheet flexibility and credit metrics?
Sully, the base case is that we fund this on balance sheet, and that would push our prior timeline to hit 3x leverage from 2028 to 2029, but deleveraging would still occur over the period even while funding the project. If we pursue a partner structure similar to what others have done and it creates incremental capacity, that could provide more opportunity to increase the annual buyback program.
In terms of making that decision, do you need to line up more agreements or is it independent of that?
Making that decision is a function of having conversations with potential partners and structuring a deal that makes sense economically. Having the contract is important because partners need to understand what they're investing into. I think we're getting to a point where those conversations can happen in earnest.
Rob, can you give your latest thoughts on the ERCOT market pricing dynamic? We're seeing limited volatility and low prices despite growing loads. What's driving the pricing action there?
Sully, ERCOT is not valuing the future build right now; prices are low out the curve. People thought batch announcements might drive curves up, but markets typically wait until projects are real. Concerns around delays and timing are impacting the '27 and '28 time frames in the curves today. Texas remains a growing market with battery and solar development absorbing supply in '26 and '27 and maybe into '28. If data center development slows, the inflection point changes or gets pushed out, but the fundamental need for generation in the medium term remains. Given tax or subsidy changes for batteries and solar in '27, that build will reduce and the market will tighten. You don't need every forecasted project to materialize to see significant tightening; a fraction of the expected additions tightening the market materially would be very beneficial.
Our next question comes from the line of Agnieszka Storozynski of Seaport Global.
I wanted to talk more about financing of the growth and how that flows into your free cash flow. As we sit here today, assuming a 3x net debt to EBITDA for the project, is it fair that about $1.5 billion of the $3.2 billion CapEx is financed with debt? How does that interest flow through the free cash flow reporting mechanics, understanding the free cash flow before growth?
Angie, the interest expense during construction is capitalized as interest during construction (IDC), so it will be capitalized and would not impact free cash flow before growth during construction.
And the assumption is that it's holdco-style permanent capital, so when modeling fully loaded returns one would assume unamortizing debt and just account for interest expense, correct?
Yes. That's fair. You can assume a permanent capital structure related to the project at roughly 3x.
The slide shows a 25% deduction against EBITDA for maintenance CapEx and tax. The assumption is that even in 2029 or 2030 you're not a cash taxpayer early on, correct?
That's right. The long-term run-rate number doesn't necessarily reflect the cash flow in the early years when we have the benefit of various tax shields.
What's the ballpark for maintenance CapEx for this sort of asset? Is it around $50 million a year?
We're not going to provide that detail right now, Angie. We'll provide it at a later date.
Regarding cost breakdown between turbines and the EPC contract: the EPC component seems large. Is the new-build cost advantage mostly on the turbine side, and as you announce additional projects is there a market-based adjustment for the EPC component? How should we think about that?
Angie, I think the way to think about it is the EPC has two elements: the labor piece and balance-of-plant equipment. Think of the turbines as the OEM and much of the balance of plant equipment comes from the EPC. That's why the EPC portion may look higher than a view that assumes the OEM provides everything.
Thanks. One more: I appreciate the Virginia RGGI change as a drag. Is there any other drag related to below-market hedges from the LS Power acquisition beyond 2026, like into 2027 or 2028?
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 included. Given when those were struck, they were slightly below today's market levels. We'll provide more detail when we come out with 2027 guidance on 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 using possibly more correct language, would it be fair to consider the return structure as roughly $1,150 a megawatt-day, which gets you to $500 million EBITDA, and that P&L costs like O&M and fuel and actual usage are passed through and grossed up to revenue? Given later projects would have higher-priced turbines and EPC, is it fair to assume the cost of new entry for CCGTs might be well above $1,200 a megawatt-day?
Moses, we're not going to comment specifically on the detailed contract economics. You've done the math and depending on your assumptions, you can evaluate it, but we're not going to comment on specific contract pricing terms.
Moses, to be clear, if build costs rise over time, our expectations for returns do not change. We will always sign deals that meet our 12% to 15% hurdle. We have open conversations with customers about that and will continue to ensure projects meet our return thresholds.
Got it. Very helpful. And on that annualized capacity payment, does it switch on at commercial operation date or is it a multi-year stage ramp as the data center ramps its own site and utilization?
It switches on immediately upon commercial operation date.
Our final question comes from the line of Nick Amicucci of Evercore ISI.
Just wanted to get a sense, Bruce, where we should have confidence on the 2026 guidance and where we might shake out given more subdued ERCOT pricing and the benefit you could see in PJM.
Nick, given where the first half landed, we expect to be below the midpoint of the guidance range but still within it. Our confidence is based on where the current fleet is hedged for the balance of the year, which is substantially hedged, and how we've matched supply with committed load. Most of the committed load we expected for the year is acquired or set up, which provides the visibility we need for earnings and margins for the remainder of the year.
Great. And as we think about the upgrade opportunity in PJM — the 2 gigawatts — when you convert CTs to combined cycle, what's the rule of thumb relative to the $2,700 per kW greenfield cost?
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'll 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.