With a combined revenue of $21 trillion and $2.1 trillion in profits, the 2026 Fortune 500 is the definitive list of America's largest companies.

Fortune 500

Almost $20 trillion in revenue—and a record-breaking $1.87 trillion in profits. Introducing the 2025 Fortune 500, the definitive list of the biggest companies in America.

Industries included in the sector are mining, oil and gas exploration and services, pipelines, refining, and utilities.

Fortune Sector Leaders: Energy

The Fortune 500, in its 70th year in 2024, ranks the biggest U.S. companies by revenue.

The Fortune 500, in its 69th year in 2023, ranks the biggest U.S. companies by revenue.

This year’s Fortune 500 marks the 68th running of the list.

This year’s Fortune 500 marks the 67th running of the list.

F500-2021-274-Vistra

The electricity and power company services 20 states and Washington, D.C., including all but one of the seven competitive wholesale markets in the United States, as well as parts of Canada and Japan. Vistra offers over 50 renewable energy plans.

This year's Fortune 500 marks the 66th running of the list.

F500-2020-270-Vistra-Energy

The Dallas-area electricity and natural gas provider shot up the ranks this year, from 337 in 2018.

This year's Fortune 500 marks the 65th running of the list.

This year's Fortune 500 marks the 64th running of the list.

This year's Fortune 500 marks the 63rd running of the list.

Key Financials (last Fiscal Year)

Revenues ($M)

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Total Stockholder Equity ($M)

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Profit as % of Revenues

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Profits as % of Stockholder Equity

Earnings Per Share (last Fiscal Year)

Earnings Per Share ($)

EPS % Change (from prior fiscal year)

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Total Return

Total Return to Investors (last year)

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Total Return to Investors (10 year, annualized)

Vistra is a power-generation company that operates across the U.S., with a particularly strong concentration in Texas. It specializes in producing and selling electricity for residential and commercial customers; it also provides power for AI data centers. Vistra’s portfolio includes natural gas and nuclear power plants, coal-powered facilities, and solar power, as well as battery storage for energy. The company changed its name from Vistra Energy to Vistra in July 2020.

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Vistra (VST): Company Profile, Stock Price, News, Rankings

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Vistra

vistra

Good morning, and welcome to Vistra's Fourth Quarter twenty twenty four Earnings Call. All participants will be in listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Eric Mysik, Vice President, Investor Relations.

Good morning, and thank you for joining Vistra's investor webcast discussing our fourth quarter twenty twenty four results. Our discussion today is being broadcast live from the Investor Relations section of our website at www.vistracorp.com. There you can also find copies of today's investor presentation and earnings release. Leading the call today are Jim Burke, Vistra's President and Chief Executive Officer and Chris Moldovan, Vistra's Executive Vice President and Chief Financial Officer. They are joined by other Vistra senior executives to address questions during the second part of today's call if necessary.

Earnings release, presentation and other matters discussed on the call today include references to certain non GAAP financial measures. All references to adjusted EBITDA and adjusted free cash flow before growth throughout this presentation refer to ongoing operations, adjusted EBITDA and ongoing operations adjusted free cash flow before growth. Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the investor presentation available in the Investor Relations section of VIXXRA's website. Also, today's discussion contains forward looking statements, which are based on assumptions we believe to be reasonable only as of today's date. Such forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied.

We assume no obligation to update our forward looking statements. I encourage all listeners to review the Safe Harbor statements included on Slide two of the investor presentation on our website that explains the risk of forward looking statements, the limitations of certain industry and market data included in the presentation, and the use of non GAAP financial measures. I'll now turn the call over to our President and CEO, Jim Burke.

Thank you, Eric. Good morning and thank you for joining us to discuss our fourth quarter and full year 2024 operational and financial results. 2024 was a transformational year for our company defined by growth and execution. In the past twelve months, we closed on unique acquisition, adding three new nuclear sites and 1,000,000 retail customers with nearly 2,000 team members joining the Vistra family. We completed a twenty year license renewal for our Comanche Peak nuclear power plant and secured two large power purchase agreements for our renewable pipeline.

Our retail business grew and reached performance levels not achieved in the past two decades of competitive markets. This was a result of our one team mindset at Vistra and I'm excited about what we can achieve in 2025. Turning to Slide five, Vistran delivered another strong year of financial and operational performance resulting in full year adjusted EBITDA of 5,656,000,000 This outstanding financial performance which the team achieved despite a mostly mild year of weather in our key markets, exceeded the top end of our original guidance range even before considering the $545,000,000 benefit from the nuclear production tax credit that we recognized in the fourth quarter. This consistent execution from our team across generation commercial and retail supported by a focused corporate services team delivered reliable power and customer solutions that reflect the strength of our integrated business model. We believe the performance achieved in 2024 is proof that a diversified portfolio of generation assets including nuclear and gas combined with a best in class retail business and a sophisticated commercial team produces a superior business model for operating in volatile power markets.

Moving to our longer term outlook, we are reaffirming the guidance ranges for 2025 adjusted EBITDA of $5,500,000,000 to $6,100,000,000 and adjusted free cash flow before growth of $3,000,000,000 to $3,600,000,000 that were introduced on our third quarter call. As you can see, we are also maintaining our outlook for a 2026 adjusted EBITDA midpoint opportunity of over $6,000,000,000 While we have the potential to be significantly above this amount, there are still a number of variables in play, including final approval of the 2026, '20 '20 '7 PJM auction parameters and remaining hedging activity required to take us above the current hedge level of 80%. We expect to provide more clarity on our expectations for 2026 later this year. Finally, during 2024, Vistra positioned itself to deliver significant capacity additions at our key markets to meet the coming load growth. This starts with the megawatts we can bring to the grid most quickly, augmentations of existing gas assets in our Texas market totaling approximately 500 megawatts.

These upgrades represent an effective and efficient use of capital to add capacity to the market, especially in the hours when it's needed most. We completed nearly half of those upgrades in 2024 and will finish the remainder in time for this summer. We also announced the expected conversion of our Coleto Creek coal plant to a gas fuel plant once it ceases coal operations in 2027, enabling it to operate beyond its previously announced retirement date. In addition, we adjusted the 2025 retirement date for Baldwin, extending operations to 2027, which will help with reliability concerns in MISO. And we are developing contracted solar and battery projects in a number of competitive markets.

Moving to new gas build as we announced last May, we are in the early stages of development for two natural gas peakers totaling up to eight sixty megawatts of capacity. While we continue to target a commercial operations date for these units in the middle of twenty twenty eight, the ultimate decision on construction will depend on our view of the economics, including any market reforms being considered. Turning to Slide six, our four key strategic priorities remain central to our strong operational and financial business performance. As highlighted on the previous slide, our integrated business model and comprehensive hedging program provide increased visibility into our long term financial outlook. From an operational perspective, our generation team achieved another year of strong commercial availability at approximately 95% for our gas and coal fleet.

Our nuclear fleet also delivered a solid result with a capacity factor of 92%. We are excited about the work that's already been done to form a nuclear fleet operating model and we believe we have opportunities going forward with respect to our operations performance improvement efforts. Our team continues to deliver high commercial availability, particularly in hours when it's needed most. The most recent example being the winter storms in February of this year, where the team achieved commercial availability of approximately 96% across the fleet nationwide. On the retail side, the team delivered an impressive result driven by strong customer count growth and disciplined margin management despite milder weather in most of our markets.

Switching to capital allocation, we remain disciplined in our approach to allocating shareholder capital through a strategy that balances return of capital and investment in growth. As part of this approach, we continue to execute the capital return plan put in place during the fourth quarter of twenty twenty one. Since that time, we have returned approximately $5,900,000,000 to our investors through open market share repurchases and common stock dividends. We expect to return at least $2,000,000,000 in total through share repurchases in 2025 and 2026, which includes the additional $1,000,000,000 share repurchase authorization announced last quarter. We also closed on the highly accretive acquisition of the 15% MistraVision minority interest.

That acquisition, which represents a significant investment in our nuclear and renewable generation assets, as well as our retail franchise, simplifies our business model and increases our proportion of zero carbon revenue streams all while balancing financial leverage. Moving to the balance sheet, our financial position is ahead of expectations communicated during our third quarter call with net debt at the end of twenty twenty four below three times adjusted EBITDA. We expect further deleveraging through 2025 and 2026. With respect to zero carbon growth projects, we continue to execute on our strategy of utilizing existing land and interconnects to opportunistically complete solar and energy storage projects. As part of this strategy, we completed and brought online two solar and energy storage facilities at our Baldwin and Coffeen sites in Illinois, which is part of our Illinois coal to solar and energy storage initiative in the fourth quarter.

We have also begun construction at our sites in Oak Hill, Texas in support of our contract with Amazon and Pulaski, Illinois for our contract with Microsoft. Once online, these facilities will add over 600 megawatts of renewable capacity to our portfolio. Moving to our nuclear portfolio, we have engineering studies in process with initial estimates indicating the potential for upgrades across our nuclear fleet of approximately 10%. We expect to finalize these studies over the next year with target online dates in the early 2030s. Before I continue, I'd like to take a minute to address our Moth Landing site in California.

As you know, one of our facilities on the site, the 300 megawatt Phase one battery storage facility experienced a fire. We are grateful there were no injuries and the event was managed safely by our team and first responders and we appreciate the support of the community. Other facilities located on-site including the 100 megawatt Phase two battery storage facility, the three fifty megawatt Phase three battery storage facility and the ten twenty megawatt combined cycle gas plant were not damaged by the incident. The combined cycle plant has since restarted and resumed normal operations. The other two battery facilities will remain offline until we've had sufficient time to evaluate them in light of what is learned.

We will continue to work with the community and state leaders on our path forward, including the remediation of the Phase one facility with safety remaining the team's highest priority. Moving to Slide seven, we continue to see real time load growth in our primary markets. Similar to the 2024 summer peak load growth highlighted in our third quarter results call, actual load growth weather normalized in PJM and ERCOT for the twenty twenty four-twenty twenty five winter peak also exceeded historical rates. This included new records for winter peak load of 145 gigawatts in PJM exceeding Winter Storm Elliot by approximately nine gigawatts and approximately 80 gigawatts in ERCOT exceeding last year's Winter Storm Heather by approximately three gigawatts. Energy usage in these markets is growing even faster than peak demand, indicating likely future acceleration and peak load growth as these numbers converge.

We continue to believe the level of growth across both markets confirms our view that load growth is already ramping and the most recent updates to load forecast from PJM and ERCOT reflect these accelerating growth trends. PJM and ERCOT have consistently revised long term forecasts upwards and that is certainly a bullish sign. We will keep an eye on the ramp rates as we go. Importantly, the source of this expected load growth remains diversified across industries with power demand related to AI data centers being only one aspect of the growth in large load sources. The magnitude of expected load growth has raised the level of discussions with differing views on how to solve projected declines in system wide reserve margins.

Over the last few months, there has been significant regulatory and legislative action related to market design in both PJM and ERCOT. Generation interconnect queues across the country remain heavily weighted towards renewable projects, which do not provide the same reliability benefits as dispatchable resources. While there have been some short term actions taken by policymakers, long term market structure questions remain. Recent developments with respect to the PJM capacity option will provide some clarity, but continued delays and persistent regulatory uncertainty have made it difficult for generators to respond in a timely manner. FERC's recent two zero six order, which we believe indicates the co located load in PJM will continue to be permitted as a step in the right direction.

However, there are a number of questions to be answered and clarity may not be provided until this summer. In Texas, policymakers remain concerned with grid reliability and the challenges of meeting the forecast for rapidly growing load. We appreciate policymakers concerns about grid reliability. It's a message we have consistently reinforced for many years. However, the market reforms to incentivize new generation have been limited or shelved, which is leading to a heightened concern about new large loads.

Recent legislative activity in Texas is raising some questions with both generators and large load customers, particularly data center customers. It is still early in the legislative process and it is not yet clear whether customers will pause or change any of their siting decisions for data centers at ERCOT, while the legislation is under consideration. But we see workable pathways to a resolution. With the proper policy framework, our competitive markets can welcome the load growth and the economic development that accompanies it. We can build generation faster and at a lower cost in other areas of the country, while the utilities build out the needed transmission.

The team at Vistra will continue to work with policymakers and regulators on these key issues. This is a big opportunity for the areas of the country that find a way to do this well and it aligns with our national interest. In competitive markets, our view remains to let markets function by sending the proper supply and demand signals. Load growth by itself is a market signal that can incentivize generation. As we've discussed on previous calls, we expect load growth to come from many sources, including residential, on shoring of manufacturing, oil and gas electrification, as well as data centers, including those focused on AI.

Regardless of the demand source, we believe a new paradigm of load growth is already occurring and we expect it to continue. With that, I will turn it over to Chris to provide more information on our fourth quarter and full year results, our outlook and our capital allocation.

Chris? Thank you, Jim. Turning to Slide nine. As a reminder, on our first quarter results call following the closing of the Energy Harbor acquisition, we initiated guidance for 2024 combined adjusted EBITDA with a range of $4,550,000,000 to $5,050,000,000 including 700,000,000 expected to be contributed from owning the Energy Harbor business for ten months. Despite the lower cleared prices and the mostly milder weather we experienced throughout 2024, we delivered adjusted EBITDA excluding the nuclear production tax credit of more than $300,000,000 above the midpoint and more than $50,000,000 above the top end of that range.

Including the nuclear production tax credit, our adjusted EBITDA was more than $850,000,000 above the midpoint and more than $600,000,000 above the top end. Notably, the ten month contribution from Energy Harbor, including the nuclear PTC, exceeded our $700,000,000 expectation by approximately $200,000,000 As you would expect, the adjusted EBITDA over performance in 2024 translated to a higher than expected adjusted free cash flow before growth of approximately 2,888,000,000 implying a conversion ratio of approximately 57% when excluding the nuclear PTC from adjusted EBITDA. As we've stated previously, we didn't expect the 2024 nuclear PTC to begin impacting cash until 2025 at the earliest. Looking forward, we continue to target a conversion rate of adjusted EBITDA to adjusted free cash flow before growth of at least 55% to 60%. Moving to Slide 10, despite the potential impact from the Moss Landing fire, including the uncertainty around the timing and treatment of insurance recoveries, which we expect to total up to $500,000,000 We are reaffirming our 2025 adjusted EBITDA guidance range of $5,500,000,000 to $6,100,000,000 and our adjusted free cash flow before growth range of $3,000,000,000 to $3,600,000,000 Looking forward to 2026, as Jim noted, we continue to have high confidence in an adjusted EBITDA midpoint opportunity of over $6,000,000,000 As always, our guidance and long term outlook remains supported by our comprehensive hedging program.

Since our third quarter call, our 2026 hedge ratio has increased from 64% to 80%. Our commercial team continues to be opportunistic in taking advantage of periods of power price strength and volatility to protect our gross margin. Turning to Slide 11, we provide an update on the progress of our capital allocation plan. Our share repurchase program continues to generate significant value for our shareholders. Since beginning the program in November 2021, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 160,000,000 shares at an average price per share of approximately $30.46 Notably, this reduction in our share count has led to an approximately 48% increase in our dividend per share since Q4 twenty twenty one.

Moving to the balance sheet, as of the end of twenty twenty four, our net leverage was below our stated long term target of three times adjusted EBITDA despite closing the acquisition of the 15% VistraVision minority interest on the last day of the year and recognizing the remaining payment obligations as debt. Going forward, we expect to continue to manage the balance sheet in a conservative manner. Finally, we will remain disciplined in the deployment of capital towards further deleveraging, growth and shareholder return. To that end, we expect to spend just over $700,000,000 on solar and energy storage projects in 2025, including the previously announced solar projects supported by contracts with Amazon and Microsoft. Based on our current pipeline of contracted projects, we expect a moderate step down in solar and energy storage development CapEx for 2026, but this could change as additional offtake agreements are executed.

Of course, we will continue to pursue opportunities to fund a significant portion of our growth expenditures with third party capital, including non recourse loans. Finally, we continue to expect to return at least $1,300,000,000 to our shareholders in each of 2025 and 2026 through dividends and share repurchases. Even after taking that into account, we continue to expect to have at least the $1,500,000,000 of incremental capital available for allocation through the end of twenty twenty six that we highlighted on our third quarter call. As a reminder, this amount is based on an assumed $6,000,000,000 of adjusted EBITDA in 2026, so we see potential for significant upside. We are excited for the opportunities in the coming year and believe Vistra remains well positioned to take advantage of the growing energy dynamics in our primary markets.

We believe the significant amount of cash that we generate combined with our disciplined capital allocation program will continue to add substantial value for our shareholders. With that operator, we're ready to open the line for questions.

We will now begin the question and answer session. The first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Good morning, Jim. So obviously, no surprise on the line of questioning here. But I guess, what color can you provide on the timeline for a deal at this point? I mean, can you at least bookend it? Should we be should we see something by mid year, year end, '26?

I guess and what's the primary impediment on getting a deal done? Is it Texas legislature? Is it deep sea spooking customers? Is it FERC and PJM, something else? Appreciate it.

Yes. Thank you, Charles. I think we had a sense this question might be coming.

say, assuming this is an M and A and it's about data center deals, because there's multiple deals that we're looking at all the time. But I will tell you that on the data center side, it's important I think to elevate the dialogue from the simple nature that there's just a contract to be signed. The flavor of the deal matters. So you can assume that we're speaking to all the major hyperscalers and that we're actively engaged with them and the major data center developers, but there are flavors of complexity. So the virtual PPA, which would be a front of the meter, those are relatively straightforward deals to execute.

We have a number of discussions going on with those. Those do not offer, we think, the same margin potential as the more complicated deals, which do involve co location, whether it's with existing assets or new assets. When we think about that, because it's a new concept, there's a lot of terms and conditions, including the risk sharing that goes into that partnership because you're making a ten, fifteen, twenty year commitment. And you see not many deals have been announced that have actually been co location related. We think co loan deals offer a lot of benefits for not only the data center customer and our fleet, but the market overall, the overall customer base because it not only provides speed to market for the customer, it can result in more transmission build out that the grid absorbs today.

So the customer may be willing to pay for that speed, pay for the reliability benefits. But because it's fairly complicated, it's elevated the discussion in all regulatory and policy making circles. So FERC, of course, has been active on that and we have seen some positive progress there. Texas has just recently filed legislation trying to sort out how do they think about front of the meter and co location deals and customers are aware of that. So when we're talking to these customers, they want to be viewed as constructive.

They want clarity on these rules. And so I think the timing of an announcement will also be dependent at some level on when we get clarity on how these deals can move through the process both in PJM and in Texas. It wouldn't prevent us from signing front of the meter virtual PPAs, but I think the deal that you're speaking about and that folks want to see is where the marriage of the load and the generation asset is proximate because that makes a lot of sense for a lot of reasons. And that complexity I think has raised I think the level of discussion at the federal and state level as well as our customers. But we are in this discussion every single day.

We feel good about the direction of travel on it, but it's still something that we've got to actually get over the finish line before you'd see us announce something.

Got it. And it's just fair to assume that Comanche Peak is probably the lowest hanging fruit versus Davis Bessey or Beaver Valley etcetera. Is that in your discussions is that where the focus is?

I would say there's interest in both markets for different reasons. I would say the Comanche Peak opportunity is probably right now considered the most attractive for a variety of reasons. But I think it's also one that as from a standpoint of having the amount of land we have and the ability to bring that on pretty quickly, just the construction timelines in Texas, working with the wires companies to make sure that we're set up, we think is probably the fastest execution that we have across the portfolio.

Perfect. And just lastly, just on a commercial question, obviously the CDR was very bullish for power, but the moves in the forwards has been a little slower than what we may have expected. We just hit a winter peak demand last week. Can you just talk a little bit about what the commercial team is seeing in the outer years of the forwards and maybe just how that impacts your positioning? Thanks guys.

Sure. And Sharron, that leads to also the question of if you were to sign a long term deal at a power price, what do you think is a fair power price? But if you don't think the forwards today reflect the load growth that everyone is worried about, then you got to be thoughtful about what's the right price to be selling a ten, fifteen, twenty year deal, especially if it's a fixed price construct. We don't think that the forwards while they have moved up in the last couple of months, I'm speaking about ERCOT, they've actually turned a little bit on the outer years in PJM. So we're not seeing exactly the same direction in those two markets.

But speaking of ERCOT, since you referenced the CDR, we don't think the kind of load growth that's in the officer attestations or even if you haircut it by 50%, we don't think that's in the forwards fully. And so we're going to be thoughtful about signing up a valuable asset that's producing power and selling on a routine basis at a level that's producing very strong earnings like we just covered in 2024. And so our commercial team thinks that while we're starting to see some of that response, we don't think it's fully in there. And that colors the discussions we have with customers because they also are trying to figure out what does the forward look like, what's going to happen with the Inflation Reduction Act, are the solar and batteries going to continue to come at the same level and all of that affects the supply demand signal that I talked about in my prepared remarks. So we're bullish power, of course, because our fleet is well positioned.

But I think the signals that are there, if you were just taking the forwards, we'd be reluctant to just be signing that up on a ten, fifteen, twenty year basis and be comfortable that we can tell our shareholders that that's fair value.

Got it. And I appreciate it. Jim, that's actually very helpful. And I think it's something that investors should think about as your views around power and contracting. So thank you so much on that.

The next question comes from Julien Dumoulin Smith with Jefferies. Please go ahead.

Hey, good morning, team. Thank you guys very much. I appreciate the time. Look, maybe just a follow-up on where Shar left it and some of the comments that you made. How do you think about additionality, right?

And I mean that in a more complex sense of ease there and need immediately or over time to add to existing sites? I mean, obviously, we see sort of the intent of SB six in some respects. We see some of the commentary. How are you thinking about managing that both in the PJM and ERCOT narrative? And how does that figure it into your planning?

And then I got a follow-up on the guidance here quickly.

Yes. Julian, thank you for the question. When you think about this 24x7 load that is the profile that the data centers expect to have and then you look at a grid like ERCOT, we're only tight certain hours of the year. So the question I think that we're trying to work through with policymakers is what problem are we trying to solve. And I think the problem that we're trying to solve is that if this load continues to come on aggressively, can ERCOT with its current portfolio of resources, can it add a lot more load and not worry about any reliability impact particularly to the residential customer base who has traditionally been part of any load shed protocol, in fact, even first in the load shed protocol.

And I think that's very fair to elevate that concern. But since we're talking about a few hours of the year, summer and winter and likely even more winter than summer, all of these data centers expect to be bringing one for one backup resources. That's unlike any other customer class. So what we're working through is on those limited hours of the year in the backup resources with proper notification, can those backup resources be utilized? And if they can and we can get the clarity of that with the environmental rules, then we can solve a problem in the super peak hours.

And I don't think it takes new combined cycles just to solve this problem. Okay. I think we've got a very active and diversified portfolio of resources, but we need to have flexibility to use that backup. I think that is gaining some interest and I think that's something that policymakers are open to. But I think we've also got to be clear that they have to have high reliability and fidelity of power.

And so that needs the notification process and they've got to be prepared to shift to that. In some of the legislation that's been proposed, it's unclear if there's going to be notice if there's for instance a disconnect switch that somebody else can trigger. And so we need to work through some of those aspects. But I think the concept is that there's actually excess capacity most hours of the year on the ERCOT grid. Our combined cycles run at 50% to 60% capacity factor.

So the issue is not the average day. The issue is really about super peak hours and that's what we're focused on.

Right. So you still think something could happen this year though right after the summer for legislative session and PGM resolution?

I certainly hope so, Julian. I will tell you though and I've tried to message this on previous calls. These customers have a lot of options. Everybody's talking to them. They have markets all over the country.

Obviously, they have international opportunities, but even in The U. S, I do expect that we're going to get something done, but I respect their ability to negotiate and work their option set and they're sophisticated. And so having just the land and the interconnects and the gas turbines and look, we have two slots coming for turbines in 2026 and first quarter of twenty twenty seven. We're as early in the queue on that. But when I look at it, they still have choices of where they're going to go and we have value in those assets and that needs to marry up.

And so yes, I do expect to make progress and I think policymakers and legislative clarity here would help.

Got it. Excellent. Thank you again guys. Appreciate the talk.

next question comes from David Ocasio with Morgan Stanley. Please go ahead.

Good morning. I was wondering, are you able to discuss or give a rough range of kind of what pricing levels that you might be thinking or discussing out there with potential deal structures? We had some suggestions from a peer of yours yesterday wondering if you would give any color around how that compares to your own discussions?

Yes. For a lot of reasons, I don't think I'm comfortable talking about pricing in a competitively sensitive kind of category that we're in. And obviously, it matters on the value proposition. So as I mentioned on the earlier response, a straight sort of front of the meter virtual PPA, I'd expect to have a lower margin assumption because it's a less differentiated product. You might get paid for some emissions attributes like if it's a carbon free energy credit of sorts, but you can capture some of that value.

Co location on an existing resource where you're offering speed to market for a customer, if you can execute on that, I think you would potentially see the highest margin. The one that I think is unclear at the moment is if you pair a new generation with a new customer and they need to take a take or pay, especially if it's not grid connected, there could be a premium that the customer has to pay to make that whole model work, but it may not be a margin, it may just give you your required equity return and maybe not a lot of extra, but that took a lot of investment for you to bring that about. So the sweet spot as we see it is understanding what value proposition you have with your fleet and then figuring out is there a place where you can meet in the middle with a customer for what you provide. And I think that's what Vistra has that differentiates us from many others is that we've got a lot of operating assets with a lot of land. We can do a Colo on existing sites, but we can also go to sites that we have over 50 that don't have power plant assets on them.

We could build new there. We could partner with a customer. That isn't typically the fastest speed to market. So when we have a conversation with a customer and they're asking us what can you do to help us in 2027 with our needs, those packages look like twenty nine and thirty. And they're interesting, but they're not as actionable to the customers that we're speaking with.

Okay, got it. That makes sense. And then wondering if you could give an update on the prospects for potential gas plant co location. What's the interest level in those assets from potential counterparties? How do you see the size of the opportunity within your fleet?

Yes. So David, you guys have heard a lot from me. I'm going to turn this over to Stacy Dore, who's been leading this effort. You've heard from her before on previous calls. And I'd like for her to give you a sense of the variation of the models we're talking about with gas plants, so you have a sense of how we're attacking it.

Thanks, Jim. Hi, David. So I think we talked a little bit on the previous call about the fact that we are seeing interest in our existing gas sites primarily from the data center developers at this point. And I think there are a variety of ways to arrange those deals. Typically, you're going to need a grid connection at a gas plant.

So you're going to have to go through the same regulatory approval process that you would even for a front of the meter interconnection. So that adds some complexity and time. You probably need to be able to add some maybe batteries and other backup gen to replicate the reliability that the customers need. And a lot of our gas sites don't have quite as much land associated with them as say a nuclear site. So you have the challenge of thinking about where the data center will be built.

Having said that, we're progressing a lot of those conversations on a handful of our sites in detail working on agreements to bring those projects to fruition. And in addition to that, we are in a number of conversations about building new gas for data centers as well with and without grid connections and in various markets. So we have a number of conversations going on that are at the papering stage. And as Jim referenced earlier, those agreements can be complex, but we are optimistic about our ability to bring those projects to a close.

Okay, great. Thanks so much for the color.

The next question comes from Michael Sullivan with Wolfe Research. Please go ahead.

Hey, wanted to just ask on the forward outlook and maybe why the decision to continue to mark off of November curves? And then when you talk about the certainty needed for a 2026 to give a formal range there, is it more so you need to see the auction results or just more clarity on the rules and parameters?

Yes, Michael, I'll start and ask Chris to provide some input. But when we say 6,000,000,000 plus and I think I toned it in my remarks, we're very confident about $6,000,000,000 and so there's ranges around that. The issue that we have is that because we don't have the auction clear and the parameters aren't set yet and we're not fully hedged, whatever next bump we give you or the market I should say, they're going to be asking for the range around that and we really want to be in the process of giving the next year guidance on our call that we have in the third quarter. And I think you could assume that the earnings power of the business looks much stronger than the $6,000,000,000 plus for 2026. And we don't see that tailing off in 2027 and 2028.

So I'm going to ask Chris to provide his color on this. But I think, Michael, it's really more about what's the right cadence for providing the updates, not simply there are a couple of variables moving around.

Yes, I agree. I think it's the cadence and it's also we continue there are some variables that we're waiting on. You mentioned the capacity auction. We still even though we're 80% hedged in 2026 that leaves approximately 45 terawatt hours of generation that's open. And so I think as we continue to hedge and we get some more clarity on the auction parameters, later this year we'll be in a position as Jim said, once we start moving the number then we get into ranges and so we're hesitant to do that at this time.

As for the curves, I think you'll see that historically as we reaffirm the guidance we haven't updated the we say that it's still based on the curves because we're reaffirming the guidance that we gave before, but you can assume that we have considered changes in curves and all the factors that go into it when we go ahead and reaffirm. It's typically I mean this is obviously early in the year and we don't typically move guidance at this point. So we'll wait until later in the year to adjust guidance. But I wouldn't read into the fact that we're still basing it on November 4 curves. We're certainly to get to the reaffirming stage thinking about all the puts and takes that have happened since we put out that guidance.

Okay. I appreciate all the color there. And then kind of related to that, but more on the policy side, two questions. I guess, what should we think about the likelihood of the cap floor proposal passing for the capacity auction? And then in Texas, I mean, you talked about customers having choices and options and the like.

Is there any particular provision in SB six as it stands that you think would push them away from Texas?

Yes, Michael, great questions. On the first, I think we feel the cap and floor is likely to be approved. We've seen obviously stakeholders weigh in. We've seen I and M comments. So I think that's likely for the next two auctions.

And I think that brings some of the volatility around the marketplace, which as you've seen, we've had low clears for the last three auctions until this most recent one. And then that's the only one that makes the news. The load clears were not newsworthy, but they were having real impacts on bringing capacity and asset retirements. On Texas, yes, there are things in SB six that are certainly helpful for the marketplace. The idea that we need to understand what's really in the interconnect queue from a load standpoint and maybe raising the bar so that we get more clarity about the forecast.

If it's a really low bar and folks are worried that we're going to see the grid double by 02/1930, it causes concern when the next deal gets announced for a data center because the view is that we need to solve all the way up to 150 gigawatts. We have not that has not been our view. You've seen us for many quarters suggest that the load growth while robust is not a double digit CAGR on peak demand each year. We see it more in the 3% to 5% peak demand range. So bringing clarity to that and getting a load forecast, I think will help policymakers who are trying to figure out how big of a grid am I solving for.

And frankly, the Talon Amazon deal, what it really did, because that data center could be front of the meter, it's still the same load as it would be if it's sitting next to a new plant. It just catalyzed the conversation on resource adequacy. It really wasn't about co location and there's always going to be a question about is there a transmission charge that should be paid or not. Setting that aside, the concern was do we have a resource adequacy issue? And that's what a large colocation deal really brought to light.

So incentive bill six, part of how they're looking to solve that is to put requirements on customers larger than 75 megawatts to shed load during critical peak hours, which we agree with. And we think the customers that we're talking to are preparing and they're designed to be able to do that. But I think when you get to something like a remote disconnect switch, that's unusual and would only exist for these customers. And that's something that gives them pause because they're going to spend tens of billions of dollars and they need to know that they're in control of those assets and they're more than willing to work as we are with the policymakers to give them comfort that with notice and with these weather events they do give you some notice. So all we really need to do is get to some adequate notice and we can move forward.

The final one is the transmission charges. We just need clarity on them. They just want to know, are they going to get something that's commensurate with the transmission and grid utilization? There's a revisiting potentially of the four coincident peak methodology that probably does need revisiting, because some customers are able to either reduce their load or turn on backup and minimize their transmission exposure, which means those costs go to other customers, including potentially residential customers. And since we serve nearly 5,000,000 customers, we're sensitive to that as well.

So there's a lot in that bill. There's a hearing going on today about it. They're going to get a lot of feedback. But I would say clarity is what we need. And then this disconnect, this remote disconnect I'd say is one of the things that we hear from the customer side is very concerning as they're not seeing that specific approach in other markets right now.

The next question comes from Angie Storozynski with Seaport. Please go ahead.

Thank you. So maybe first, I mean, just taking a step back. So it doesn't sound like gas deals are awaiting for any regulatory clarity. It's just more about contractual arrangements. So why haven't we heard of any gas deals?

Vistra (VST) Q4 2024 Earnings Call Transcript

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