Vistra Corp. (VST) Earnings Call Transcript & Summary

Thank you for standing by. And welcome to the Vistra Corp's. Business Update Call. [Operator Instructions] Thank you. It is now my pleasure to hand the conference over to Molly Sorg, Senior Vice President Investor Relations. Ms. Sorg, please go ahead.

Thank you, and good morning, everyone. Welcome to Vistra's Business Update Conference Call, which is being broadcast live from the Investor Relations section of our website at www.vistracorp.com. Also available on our website are a copy of today's investor presentation and the related press release. Joining me for today's call are Curt Morgan, Chief Executive Officer; and Jim Burke, President and Chief Financial Officer. We have a few additional senior executives present to address questions during the second part of today's call as necessary. Before we begin our presentation, I encourage all listeners to review the safe harbor statements included on Slides 2 and 3 in the investor presentation on our website that explains the risks of forward-looking statements, the limitations of certain industry and market data included in the presentation and the use of non-GAAP financial measures. Today's discussion will contain 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. Further, today's press release, slide presentation and discussions on this call will include certain non-GAAP financial measures. For such measures, reconciliations to the most directly comparable GAAP measures are provided in the press release and in the appendix to the investor presentation. I will now turn the call over to Curt Morgan to kick off our discussion.

Thank you, Molly, and good morning to everyone on the call. We appreciate your time and interest in Vistra. And we appreciate your flexibility joining a call with relatively short notice. This is not our ordinary course first quarter earnings discussion. But given the heightened focus on the financial impacts from the Winter Storm Uri, we thought it was important to get in front of all of you with an update as soon as we had sufficiently reliable information to do so. We recognize that the uncertainty regarding the financial impact of Uri on our company is presenting a significant overhang. We recently received and processed the 55 day resettlement statements from ERCOT. So we are now in a position to discuss that impact. We elected to host a call now rather than waiting another 1.5 weeks for our 10-Q to be filed in an effort to be as responsive and transparent as possible. And also so that we can begin to rebuild from the very strong core of our company, continue our transformation and get back on track to reaching our full value. With that, let's get started on Slide 6. Before I get into the content of this slide, I would like to state the obvious that we are very disappointed in the financial loss our company has suffered as a result of Winter Storm Uri. However, as we will discuss, much of it was outside our control due to an unprecedented weather event and cascading course of events. Our people and, for the most part, our generation performed well. In fact, throughout the week, we consistently generated more megawatts than our market share of total generation. You would think this would translate into positive financial results. What is frustrating is that a confluence of events during the storm changed our risk position without any ability to defend against these events. Most notably, a failure of the integrated gas and power systems and a disproportionate share of load allocation. Now look, we are not so naive to believe this is good news, it is not, or that it somehow pacifies the pain, it does not. It is an explanation. And until we come to grips with what happened, we cannot respond. We have taken an internal and are in the process of an external look at our performance and the causes of the impact, and we have developed and are implementing self-help measures to mitigate the risk we were exposed to. We are also working with legislators and regulators to take measures to reduce risk, not just for us, but for the market as a whole, most importantly consumers. We know that our investors have a choice where to put their money and excuses don't get it done. We are laser-focused on derisking our business model while preserving our earnings power. As we have highlighted from the beginning, we saw this storm coming. It was not a surprise. In advance of the storm, we alerted regulators and elected officials about our concerns that demand would outpace supply. We reached out to our customers to encourage conservation, and took incremental steps to prepare for the winter weather. We positioned our commercial book to be flat to long against an extreme load forecast by buying power at relatively high prices in anticipation of the increased demand. We conducted our normal extensive winter readiness program across the fleet in fall of 2020 and then supplemented this program with an incremental approximately $10 million to prepare for, respond to and support the increased workload during the storm, including hiring approximately 400 contractors to support our operations leading up to and during the event. We similarly took steps designed to ensure that we had adequate gas supply. What we certainly didn't forecast and couldn't have foreseen was the unprecedented failure of the gas supply system, which was the most significant driver of our financial impact. We now have a new appreciation for this risk, and we are taking proactive steps to mitigate it in the future. We also expect the Texas state Legislature to take actions to deal with the contributing factors. In short, we believe we were as well positioned as anyone heading into this storm. As I just mentioned, the primary driver of the Uri related financial loss was the unprecedented nature of the gas system failure in Texas, as we outlined on Slide 7. Specifically, 70% of force majeure claims we receive from our gas suppliers and marketers had a start date earlier than February 15th when the storm really hit. And the majority were as early as February 12, 2 days in advance of the start of the storm well before they could credibly claim an inability to perform. It is important to note that gas transacts on a Friday for the entire weekend. And this was a long weekend for President's Day. Market participants had to buy a package for the entire 4-day period. So indications of tight supply supported higher prices and force majeure was certainly an influencer. In addition, some gas infrastructure assets that did not voluntarily identify themselves as critical with transmission and distribution utilities were curtailed in the outages. Some gas infrastructure assets voluntarily curtailed as demand response during the storm instead of supplying gas in a high demand situation opting to sell their power instead of producing hydrocarbons, and some gas infrastructure assets experienced freezing issues impacting their ability to perform, all of which further exacerbated the issues with the gas supply chain, such as processing plants and gas compressors and compounded the severity of the outages in Texas. It is also important to note that the outage issues started early on Monday morning, the 15th, with issues on the generation side as some power plants struggled at the outset of the weather event and some tripped offline due to the frequency issues on the grid. However, as those plants came back online, it became a gas deliverability issue. Vistra performed very well on Monday during the start of the power curtailments, but as the gas system experienced issues, so did Vistra. The failure of the gas system in Texas was an unacceptable failure of the state's broader energy infrastructure. For Vistra, this failure meant that our generation capacity was meaningfully reduced, ultimately contributing heavily to our net short position during the storm and driving our negative financial impact. In addition to the issues with the gas infrastructure system, Vistra experienced coal delivery and fuel handling issues that caused our coal plants to run at an average capacity factor of 74% versus 93%, which we were able to fully offset by the additional output from our gas steamers and peakers. On the demand side, the load curtailment in the state resulted in residential households being curtailed at nearly twice the rate in Houston as compared to the DFW area. Given the weighting of our customer base towards North Texas, this means that more of our customers were online as compared to retailers serving customers in the southern part of the state, which ultimately increased our relative financial obligations during the storm. We are unsure as to why this happened, but this is a process that needs to be reviewed with ERCOT and the Public Utility Commission. Last, it is our view that the Public utility commission of Texas' decision to administratively set ERCOT pricing at $9,000 per megawatt hour during the week did not follow the appropriate regulatory process, resulting in further negative impacts to our financial results. We are currently challenging the validity of the Public Utility Commission of Texas' February 15th and 16th pricing orders in state appears court to address this concern in which case, the cap would be removed for the week and prices would be set at much lower levels. Alternatively, we are disputing the PUCT's and ERCOT's decision to leave the prices at the cap on February 18th and for part of the 19th. Turning to Slide 8. As you can see in the table, we are now estimating that the adverse financial impact of the storm on our adjusted EBITDA is approximately $1.6 billion for 2021, which is net of approximately $500 million of self-help initiatives we have identified. You might recall that in February, we first estimated the impact of the storm on 2021 adjusted EBITDA could have been in the range of negative $900 million to $1.3 billion. Since that time, we have received both actual and updated customer load information, which drove a negative variance to our estimate. In addition, we had a line of sight to relatively high probability self-help initiatives that until mid-April kept the net estimate of the 2021 adjusted EBITDA impact at the high end of the previous range with knowledge that ERCOT's 55-day resettlement statements would be forthcoming and that we believe could have gone in either direction. In mid-April, we received those resettlement statements, which resulted in an estimated negative impact of over $200 million, ultimately driving the estimated impact on adjusted EBITDA outside of the former top end of the range. There's still an impact we can absorb due in large part to our strong balance sheet and conservative liquidity management. In fact, nearly all of our obligations from the storm have already been paid for, and our current liquidity situation has improved back to pre-storm levels. For the balance of the year, Vistra has identified various self-help initiatives that we believe will contribute approximately $500 million of benefit to offset some of the negative financial impact from Uri. These initiatives include the monetization of certain commercial positions, optimize spend on our generation O&M project work, retail savings and forecasted performance and IT and SG&A savings. We have a high degree of confidence in our ability to execute on these initiatives. I wanted to spend a few minutes taking you through the high level drivers of our financial loss on Slide 9. Very simply, we estimate that the entire 2021 adjusted EBITDA impact from the storm was less than the negative impact from the gas deliverability issues and the incredibly high gas costs, which we estimate at over $2.5 billion. In a nutshell, the issues stemming from the natural gas system cost us dearly, and there wasn't anything we could do about it, while we were in the middle of the event. Though Vistra did have issues with fuel delivery and handling at its coal plants, as you know, we plan for these types of issues and keep some generation length unhedged to mitigate the potential risk. This length worked exactly as designed, offsetting Vistra's reduction in anticipated production from its coal fleet. Absent the issues with gas deliverability and the increased gas cost, Vistra estimates that the 2021 adjusted EBITDA impact of Uri would have been a slight positive, even with the increased retail load from ERCOT resettlements disproportionately skewed toward North Texas. We never would have imagined that the gas infrastructure system in Texas would face power outages, freeze offs and operational issues and that gas fuel supply, not operational challenges, would have been the significant driver of our financial loss. The gas and power systems are inextricably linked, that the critical infrastructure necessary to ensure the integrated reliability, especially on the gas system was not identified as critical leading to a cascading failure of both systems. This is a risk we are very well aware of now, and we are taking steps to mitigate something like this from happening again in the future, which I will discuss on the next slide. To us, the key takeaway is that we believe we performed well what we control. Unfortunately, the financial results do not reflect these efforts, and we are taking steps to improve our risk profile for the future. We continue to believe that our integrated model is the best way to serve our customers most reliably and cost effectively, while our scale, fuel and geographic diversity and balance sheet strength support our resilience in even the most extreme events. Slide 10 sets forth the actions we are currently taking to meaningfully improve our risk profile in future weather-driven volatility events. As we have noted, the primary issues we faced during the storm related to fuel handling and gas deliverability issues. On the former, we are already planning to invest in improvements to further harden our coal fuel handling capabilities and we are evaluating additional weatherization of our ERCOT fleet for even colder temperatures in longer durations. On the latter, we are pursuing several solutions, some of which are 100% within our control and others that we are advocating for. For example, part of the solution to the gas deliverability issues is to carry more backup generation into the peak season. We can also solve this matter through legislation requiring registration of critical infrastructure. In addition, we contracted for incremental gas storage, which performed well during the storm to support our gas fleet, and we are evaluating installing dual fuel capabilities at our gas steam units and increasing fuel oil inventory at our existing dual fuel sites. While carrying more generation length into the peak seasons might modestly increase the distribution of our future financial results as we would be less hedged, it would also meaningfully reduce the risk of loss from extreme tail events like this one we just witnessed in February, which we believe is a prudent trade-off following this event. In addition to these internal efforts, we are also advocating for the registration of gas infrastructure as critical resources with the transmission and distribution utilities and for the enhanced winterization of both gas and power assets in the state. In our view, these are the most essential solutions the state of Texas can implement in order to shore up our energy infrastructure system for the future. We simply cannot expect to run a grid where nearly 50% of the supply stack is comprised of gas assets without confidence that the gas fuel supply will be available. And these are easy fixes to implement. There is no reason why we can't make these changes in the state to improve performance in the future. We had millions of people without power during Uri, countless disruptions of lives in the aftermath and over 100 deaths. We must take appropriate actions to harden Texas' integrated gas and power systems. Outside of these actions, we continue to believe there could be a stronger push by legislators to pursue market reform in the future, primarily related to supporting nonintermittent generation that can be dispatched when called on and is not subject to natural conditions such as wind and sun levels. These reforms could enhance the attractiveness of the market and further improve ERCOT's risk profile for market participants. You are also likely aware of the now 2 offers to build out of market backup generation in the state. We believe these types of solutions are self-serving and expensive proposals that do not address the primary issues that caused the black-outs. In addition, these proposals would depress forward prices and drive out the very generation types that ERCOT market requires, not to mention that the technical details of the proposals are lacking or inefficient, and the terms are egregious. Turning now to Slide 11. The adjusted EBITDA impact from the storm that we disclosed today does not account for the possibility of any recovery from the various legal and regulatory initiatives that are underway. There are 2 primary legal work streams that if we are successful would offset estimated losses from the storm. The first relates to the potential to reprice energy during the week. We have an active case challenging the validity of the Public Utility Commission of Texas' February pricing orders in state appeals court. We are also evaluating legal claims against entities that claim force majeure for alleged inability to deliver contracted gas that caused Vistra to procure gas in the middle of the crisis at prices significantly higher than our contracting costs. In 1 week alone, Vistra spent more than twice the amount on natural gas than what we usually spend in 1 full year to power our Texas generation fleet. In ERCOT, we have the independent market monitor, in the PUC enforcement arm, monitoring pricing of electricity. But on the intrastate gas system in Texas, there is seemingly no one who has oversight of gas prices. If one or both of these legal work streams is successful, we estimate the adjusted EBITDA impact to Vistra would be a meaningful positive, though we recognize that the litigation process will take some time to play out. There are also securitization bills pending in the Texas legislature, dealing with various impacts from the storm that could be helpful to market participants. Vistra is staying close to these discussions. Now that we have a firm handle on the adjusted EBITDA impact of Winter Storm Uri, we are in a position to reissue our 2021 guidance. As we show on Slide 12, Vistra is reissuing its 2021 ongoing operations adjusted EBITDA and ongoing operations adjusted free cash flow before growth guidance ranges at $1.475 billion to $1.875 billion and $200 million to $600 million, respectively. The sole change to Vistra's 2021 guidance ranges as compared to its initial guidance is that if the estimated $1.6 billion adjusted EBITDA impact of Uri, which includes the impact of the self-help initiatives I described earlier. While the operating reserve demand curve price cap in Texas is expected to be $2,000 per megawatt hour as opposed to the standard cap of $9,000 per megawatt hour for the balance of the year, we believe market conditions continue to support the probability of tightness this summer, especially as the economic recovery takes off in Texas, as it is poised to do. In fact, we have already seen a few intervals in April where prices spiked to $500 to $2,000 per megawatt hour on strong demand, low wind and tight thermal generation supply due to units and planned outage during spring maintenance season. We expect we will carry more length into the summer than we have in the past as part of our revised risk management strategy. Our guidance is set utilizing recent vintage market curves. While the extra length going into the summer does expose us to lower day-ahead and real-time summer prices, we believe it is a prudent trade-off to carry more length until the risk we experience with the gas system during this event are alleviated. We continue to believe that Vistra's integrated operations offer the best business model to manage risk and succeed in the ERCOT market. In our view, the storm highlights the importance of maintaining a diverse set of generation resources to support market reliability, especially as the grid increasingly transitions toward renewables resources. Combined with the self-help initiatives I just mentioned, we believe Vistra has the right assets and business model to lead in this U.S. energy transition. We also believe the extreme nature of this event is not representative of our future performance, and we are taking actions today to reduce our risk in the future. Constructive legislative actions aimed at hardening the gas system and adequately compensating generators in order to incent investment and ensure that Texans will have sufficient power, especially nonintermittent resources to meet their demand in the years ahead could further reduce risk for market participants. Such actions would also be favorable for generators like Vistra, who provide the necessary dispatchable generation to balance the grid significant intermittent renewables. We are the largest generator of power in the state of Texas with a diverse fleet that includes nuclear, coal, natural gas, solar and battery storage assets and significant wind PPAs. We have been and expect to continue to have a seat at the table as Texas works to develop solutions for the future. On Slide 13, we highlight our takeaway message from our first Analyst Day in June of 2018 when we told you that we believe our business model would support more than $3 billion in annual ongoing operations adjusted EBITDA generation, with 60% to 70% conversion to free cash flow, all while transforming our company, including via substantial coal plant retirements. In 2019 and 2020, we more than delivered on this expectation with our average ongoing operations adjusted EBITDA coming in at approximately $3.5 billion with an average free cash flow conversion of 70%. In fact, in 2 years, we delivered financial results that were more than a cumulative $400 million higher than our initial guidance midpoint and $1 billion greater than our $3 billion per year expectation. Even with the midpoint of our reissued guidance for 2021, reflecting an extremely rare event, the 2019 to 2021 average adjusted EBITDA from ongoing operations would be nearly $3 billion. While our 2021 financial results will be impacted by Winter Storm Uri, we expect we will be right back on track to our $3 billion-plus ongoing operations adjusted EBITDA and 60% to 70% free cash flow conversion in 2022 and beyond. We have always said that in this commodity-exposed industry, looking at our average results over the long-term is the best way to measure the earnings potential of the business. I still believe this. Clearly, the financial markets do not as under no reasonable multiple or free cash flow yield would have stocked with the ability to generate $3 billion or more annually with approximately $2 billion of annual free cash flow before growth be trading at the levels where our stock has been recently even after accounting for the onetime impact from Uri. And while we recognize that the energy markets are evolving, potentially raising questions about the long-term value of our assets, we believe we have what it takes to play a critical role in the energy market transition. Our diverse capabilities combined with our attractive sites and strong customer relationships make Vistra a natural owner of renewable assets and a strong partner in developing new innovative technologies. The playing field is changing. Environmental stewardship and climate change are increasingly being factored into portfolio managers' investment decisions. Vistra is committed to taking a leadership role, including taking the necessary steps today to accelerate its transformation to a leading sustainable company and to reaching its fair and full value. We have been making this transformation already, and we continue to generate significant earnings and cash flow. We believe the steps we have taken over the last 4.5 years have created a strong foundation from which we can launch our future initiatives. The events of the onetime unprecedented storm hitting Texas, as difficult as they are, have not changed that view, especially as we implement our self-help initiatives; if anything, they have reinforced it as our business remains resilient despite the adversity. I will now turn the call over to Jim Burke.

Thank you, Curt. I'm on Slide 15. In the first quarter of 2021, Vistra took various steps to strengthen our liquidity following the impacts of Uri, including increasing borrowings under its accounts receivables financing agreements executing a new $1.25 billion 364-day term loan A and implementing a new PJM forward capacity agreement. Following Uri, we thought it was prudent to enhance our liquidity cushion heading into the summer and better position Vistra to, among other things, take advantage of potential opportunities, to continue to grow and strengthen our business and to address any unforeseen liquidity events. We believe these actions were prudent in the wake of a very rare event, and we're taking the necessary actions to further derisk our business in the future. As a result of these transactions, as of April 19th, Vistra had total available liquidity of nearly $2.8 billion, which was primarily comprised of cash and availability under its revolving credit facility. As is always the case, we do expect to evaluate opportunities to further optimize our balance sheet during the remainder of the year. On the leverage side, Vistra closed 2020 at our long-term leverage target of 2.5x net debt to adjusted EBITDA from ongoing operations. While our leverage metrics will increase meaningfully in 2021, reflecting the onetime adverse impact from Uri, we expect to return to approximately 3x net debt to adjusted EBITDA from ongoing operations by year-end 2022. Before we open up the call to Q&A, we wanted to provide a brief 2021 capital allocation update on Slide 16. Through March 31, we executed approximately $175 million of our $1.5 billion authorized share repurchase program, repurchasing approximately 8.7 million shares at an average price of $20.21 per share. Given the reduction in the amount of available capital in 2021 as a result of the financial impact from Uri, we currently do not plan to repurchase any additional shares this year. We remain committed to our quarterly dividend of $0.15 per share or $0.60 annually in 2021, subject to Board approval at the appropriate times. We intend to continue our dividend into the future. We also remain committed to advancing our renewable development projects. We are continuing to evaluate financing alternatives or partnerships to help fund and/or to potentially accelerate the pace of development of our Texas and California renewable and energy storage projects. Maintaining a strong balance sheet has always been a cornerstone of our strategy, and it is one we remain committed to today and in the future. As a result of the financing transactions we executed in the first part of the year, our total debt increased by approximately $2.2 billion in the first quarter, with our net debt increasing by just over $2 billion. In the balance of the year, we expect to reduce net debt by approximately $1.25 billion. While Winter Storm Uri was a significant onetime financial hit and has altered our ability to execute on our capital allocation plans for the year, our business and its underlying assets and growth projects remain intact. We expect we will emerge from this event as an even stronger company. We're a resilient team, and we will stay focused on creating value for our stakeholders over the long term. With that, operator, we are now ready to open the lines for questions.

[Operator Instructions] Stephen Byrd with Morgan Stanley.

Thanks for the update. I wanted to get your views on the legislative outlook and specifically interested in whether you see the political willpower to put in place something along the lines of a fixed payment for resiliency, deliverable capacity, whatever you want to call it, but just to sort of shift the market design away from extremely high peak prices more towards some kind of more sort of reliable payment, but also ensure that power plants comply so that they can actually deliver power under extreme weather conditions. What's your latest thinking on the outlook there?

Yes. Thanks for the question, Stephen. Look, I would say that it's pretty clear that Texas is still not interested in a capacity market or anything like that. I think that got surfaced in one of the bills, and it was resoundingly rejected by market participants and elected officials and others. I do believe though that there is some openness to taking the current model and making some changes to it. For example, reducing the cap but extending the amount of reserves where the ORDC would actually kick in and increase pricing. And this would apply to nonintermittent dispatchable resources exclusively and notintermittent resources in order to bridge the gap between development of renewables, new renewables and the development of new dispatchable resources, but also to get revenue into the system to maintain the dispatchable resources that actually exist. We now have a situation in ERCOT, where we have less dispatchable resources than we have peak load. And that means we rely on some level of intermittent resources for capacity and for reliability. And I think that was part of the issue that happened during winter storm. So I think there is an appetite here to make some changes. The other alternative that has surfaced that I mentioned in my comments is some sort of backup generation. We don't see that as being the right answer to the problem. But it has received some interest and so we're obviously working with the elected officials to make sure that we put the right thing in place. My sense of this is that market design changes may not get done in this session, but it may need to go into something a special session, although I think most people would like to get something done in this session. But I do think that there is interest in trying to reduce the volatility in the market, but to get more revenues in the system for nonintermittent dispatchable resources. And especially given the fact that we're seeing more and more renewables coming in. I think we saw it in Texas, we've seen it in California, where the balancing between cost, reliability and emissions have gotten out of whack. In California, emissions reductions got out of whack with reliability. In Texas, costs got out of whack with reliability. And we need to bring those things back together in order to have a reliable grid. And I think the way to do that is really to build off the ORDC and the current market structure, the competitive market structure, which has been largely successful. The market actually designed, Stephen, actually worked. It worked as designed. Our market is set up for scarcity. And it's set up to hit the cap so that we can get enough revenues to stimulate new investment, but also to stimulate investment in existing assets. So we got exactly what we asked for. What we didn't expect is a gas system that did not function properly. That was the thing that nobody on the electric side was prepared for. So we have to fix that as number one. That issue has to be fixed. And then I think we need to focus on getting the proper amount of revenues in for dispatchable resources to harden the reliability of the electric system.

That's helpful. I could see how you could shift to the ORDC so that it's sort of triggers more often and you have greater visibility there and just greater impact to prices in a way that's more understandable and predictable. Maybe just 1 follow-up...

And Stephen one other thing just to add, we need more reserves. This is logical. This isn't a construct that's forced. We need more reserves of dispatchable resources. So the idea that you would be paying on the ORDC for -- sooner on the reserves makes logical sense in a market that is increasingly adding intermittent resources that are not capacity and they're not dispatchable. So the logic behind this makes a lot of sense. So hopefully, we'll get some people to coalesce around it. Sorry, but thank you.

No. No, that's helpful. And then maybe just 1 follow-up. With respect to renewables, are you seeing more opportunities there? Are some of the smaller developers having challenges with either hedging or financing and could we see sort of more opportunities there? And at the very end, you all talked about approaches to financing that. I just wonder if you could expand on that a little bit?

Yes. So look, I think we have early indications that -- and we've heard this more out of the capital markets than we have from developers, although we're beginning to see it at our developers, too. There is a little bit of a pullback here because as you -- I think you know this, renewable developers were nicked in this as well. And I think some investors were as well. So whenever that happens, people step back. I think what's really important is they want to see what market reforms are going to go in place. Because they took on the same kind of risk that we did, which was largely -- in the middle of storm, there was nothing you could do about it. So I think they're wanting to see what the state is going to do, the legislature is going to do. But I also think it's just a natural reaction when you have this kind of event for people to step back and take stock of it. I still think the ERCOT market is a very good market. I think we can make some changes to it and improve it, and it will continue to be a very good market. But changes are necessary. And in particular, we got to do something about the critical infrastructure on the gas side being registered with the transmission and distribution utilities. That is an absolute must and everybody that participates, both on the gas side and electric side, have to spend the money to weatherize their assets. That doesn't -- you shouldn't get an extra payment for that. That's just part of doing business. We produce gas and oil, and we move gas on pipelines and process it and compress it in Siberia, North Dakota, Canada, all these adverse climates. There's absolutely no reason why we can't handle the kind of weather that we had in Texas. And people are going to need to step up to the table and do that. And you would think they would because the incentive is to produce your product and get it to a customer.

Shahriar Pourreza with Guggenheim.

It's actually James for Shar. So I guess if I could start on the guidance side, I see there was a footnote on Slide 8 about an ongoing impact to EBITDA from C&I resettlements in future years. Is that final or will it shift around? I guess, more broadly, is there any chance you could speak to directionally how '22 is looking at this point?

Yes. So look, I think we believe that with the 55-day data, historically, that information has held up pretty strong against -- there's another 180-day true-up, but that information on the 55 day has held up pretty well. So that's why we wanted to come out quickly once we got that and processed it because we feel like those estimates are pretty good. So those out-year effects we think are pretty good. A couple of things with those out-year effects. We still believe that and as we said earlier, that we're in -- even with those we can produce that $3 billion-plus and 60% to 70% free cash flow before growth, conversion ratio. And we feel that way about '22, and we feel that way beyond that. So -- and we believe that there are opportunities. But one thing that's -- if there's any silver lining on those C&I obligations, commercial, industrial customer obligations, is that we're aware of them and that we can plan for those. They will be in our guidance for 2022 and 2023, and we can come up with ideas to mitigate those. So we have degrees of freedom to mitigate them. And so we feel like '22 -- and it's a really important point that you raise that the strength of our company bounces back in '22 and '23. In fact, it's going to -- it's starting right now. The remainder of '22 should be solid, just like we expected it to be and into '22 and '23, and we can absorb those future effects in that future guidance but also in our future performance of those obligations and we expect to do so. And we feel very good about our ongoing earnings. One of the things that's interesting that came out of this storm as well is that you've noticed that the curves have moved up. And that's because people are believing that there may be less development on the renewables side, which I think is probably true, but also that there are generators that may have been wounded and distressed in this situation. And so we think that the ongoing market is probably stronger today and then the cost of doing business has gone up in ERCOT, and we can handle that, but there are a number of people can't do that. In order to properly deal with the risk in ERCOT now that has surfaced, you've got to be able to have length of generation. You've got to hold it back. That costs you a little bit to do that, that's an insurance premium. And then on the retail side, the cost of doing business has gone up to capitalize yourself in a way that you can withstand these types of events. When the cost of a business goes up, those who are the strongest end up doing well. And so we feel good about the prospects for our company going forward.

Got you. I guess just kind of building off that last thing you said on the retail side. The capital allocation slide doesn't mention any opportunistic retail growth. Is that still a possible area of interest for you guys, given what we've seen in recent weeks?

Yes, absolutely. And we're waiting -- what's happening is there's some securitization bills that could help out some retailers. There's also some retailers that are going through bankruptcy. We're sort of watching all that. But one of the things we wanted to do is to make sure that we -- even though we took on more debt in '21, we wanted to put ourselves back in the liquidity position and a strength position in order to be opportunistic. And in particular, on the retail side, we think there are opportunities that have -- that will surface over time, and we're obviously prepared to be a part of that. We love our retail business. It continues to be one of the strengths of our company, and I would not be surprised that you'll see us do some things in that in the next year or 2.

Got you. I guess just last 1 really quickly. Can you give us any idea of what proportion of the gas deliverability issues were tied to force majeures? I mean is it half of that $2.5 billion?

Jim may have a better sense on that one. I'm not sure I have a percentage that I'd like to give up. But Jim, do you have a sense to that?

Yes. I do. Thanks, Curt. It's a combination, James. We hedge physically and financially. The physical hedges were the ones where the vast majority declared force majeure, but we don't hedge on a predominant way through physical. We do have storage in addition to the physical hedges, and our storage performed really well. But force majeure was a factor, but since the vast majority of our hedging is financial, it wasn't the main driver. But if you break down the incremental gas cost, the $1.1 billion or so of the $2.5 billion we think is related to higher gas cost, about half of it is due to the incremental cost of just spot prices going through an extremely high period during the week, and we were 77% volumetrically hedged going in. So that balance was very impactful that was not hedged. So half of it or so came from that. And the other half came from the fact that even though we were financially hedged upwards of 77%, the actual spot prices in the week dislocated from some of the hubs that we were financially hedged to. And that's just an in-the-moment where spot prices were trading to procure gas. And our focus was find the gas, run the fleet, get as much power on the grid as possible. So force majeure played a role on the physical, but the dislocation of buying gas that dislocated from the financial hubs was also a factor.

Julien Smith with Bank of America.

Thanks for the time to connect here. Listen, maybe we could start it off on the credit side. I'm just curious if you can elaborate a little bit on perhaps initial conversations with the agencies and just the trajectory for IG. I know we're not necessarily getting ahead of ourselves here on '21 versus the future years. But if you could speak to that, and I've got a couple of clarifications on the last question.

Okay. Well, Jim just had discussions I was not part of them with the agency, so I'll let him talk. But I'll just say something on the front end. We've been in discussions all along with the agencies. In my view, they've been constructive. They view this as a onetime event. They don't view this as an ongoing event. Nevertheless, it was an event, it was a big one. So it set us -- the way I think about it is it set us back about a year in terms of what our progress in getting there. And my sense is that, that's probably where we are. We're probably talking into 2023 before we're back talking about something like investment grade, unfortunately, but that's what happens when these types of events occur. But Jim, you have more detail than I do on the recent discussions.

Yes. I think you captured it, Curt. The only thing I would add is, they're obviously wanting to make sure that we stay focused on a strong balance sheet, which we are. They have communicated they view this as a onetime event. I think folks are looking for some reforms in Austin. We do expect to pay down debt in the balance of the year. We have quite a bit of free cash flow from our operations in the balance of the year. And of course, they're going to look to what the 2022 capital allocation plan looks like as well. But we've had very constructive conversations. And I think given the strength of our integrated business, they're going to look for just more detail on how we think about using that capital for the balance of '21 and '22. So Julien, we keep an open dialogue with them, and we understand what they're sensitive to in terms of we added some leverage here to make sure that we had sufficient liquidity. Our liquidity is above where we started the year. And so we're going to work hard to burn that off quickly here in the balance of '21.

Got it. So it sounds still committed to IG even if it's in '23. If I can pivot to a further question here, just to clarify, I know you have the $450 million to $500 million of cost savings that nets out in '21. What is that due into '22 onwards? You made some illusion in your prepared comments, but if you can clarify that, it sounds like perhaps you're accelerating realization of hedges, et cetera?

Yes. Julien really -- go ahead. Jim, let me just say, it's really modest in terms of that component of it. And some of what happened in the -- from the storm in terms of the long-term forwards have enabled some of that to happen. I'm going to be very careful about what I say on this, though, because there's a sensitivity around transacting in markets and I'm not trying to avoid anything, Julien. I am just -- these require us to to go out in the market and transact. But all I'll say is that the future effects of those, because it was over a long period of time, are pretty modest on an annual basis. And one of the things we did not want to do is sacrifice the future to help 2021. So we embarked on this activity to figure out what we could do to strengthen '21, which we thought was important because all of this has underlying cash to it, which is really important that we continue to generate a lot of cash. And so we found ways to do that without sacrificing, number one, not investing in our power plants because power plants will come back to haunt you if you don't invest in them; and that we're not sacrificing a significant amount in any given year in the future. And I think we found ways to do that. And frankly, our company is going to tighten its belt a little bit in the balance of 2021, things that we might have wanted to do in terms of increasing staffing and things like that or replacing open positions. When you have something like this happen, you rally around it, and that's what we're doing as a team. And so we found some cost savings and other things that we can do as well. So we don't feel like we're cutting into the muscle of the company, and that will have a big future effect. Jim, do you want to add anything?

Curt, the only thing I would add is I think these are unintended, but at the same time, real opportunities given the storm event and the fact that the market is responding, Julien, to the fact that it's tighter loads responding in a very significant way to some of these weather events and then the renewables queue that we talked about. So I think for us, this was a way to monetize some of the natural effects that created the impact for us in Q1, and we get a chance to monetize some of the effects in the future, and it's very modest on '22, as Curt said.

Steve Fleishman with Wolfe Research.

Could you just maybe -- Curt, could you just go through a little bit, Slide 24, note C? And it sounds like there will be GAAP hits for the ERCOT default uplift and the Koch, I guess, lawsuit, but you're excluding those from these numbers. Could you give -- why the GAAP hits? And why are you excluding them?

Yes. Good question. So on Koch, there are certain things we go through from an accounting standpoint, from a GAAP standpoint that make a determination whether you record a liability. And we went through those and made the determination to be conservative that we should record a liability. We obviously feel good about the suit that we filed. And we don't believe that we owe these funds. But according to GAAP and following those rules, but also our view to be conservative on this, we recorded a liability. And so you're right, that's one of the reconciliation items on the reg G reconciliation. On the uplift side of things, which stems from the short pay that gets then uplifted to the ERCOT participants, our number is just a little bit under a couple of hundred million, Steve, on that. But if you remember, the rules are such that are clearly in place. There's no effort to get rid of them. This would get paid out over about 90 years. And so the NPV of this is very, very low. And so it's just a number that from our stand -- and by the way, the rules on GAAP, you cannot discount this particular type of a liability, even though it gets paid out over 90 years, the rules don't allow you to discount it. And so we pulled that out because it's such a small number, and it's also obviously from a onetime effect. But those are the 2 things. The other thing was the bill credits that is also in that reconciliation as well. And I think I described those pretty well in terms of our viewpoint on those and our ability to offset those. But those are the reasons we treat them the way that we did. And Jim has been very close to this. So I want to give him an opportunity to step in and make any additional comments.

The only thing I would add to the discussion is it's very consistent on the bill credit side with how application would work from a cash impact because it's offsetting future usage. And same thing, the uplift in the Koch cash timing, very unclear of how and when that would actually play out, Steve. So we tried to provide all the details that we could in the footnote so that we could reconcile the adjusted EBITDA impact in '21 with a GAAP impact. And obviously, there's going to be more to come on how some of those things will unfold in the future.

Yes, one other last thing, Steve, I'd like to say. We look at the Koch liability a little bit different than we do the other liabilities that have flowed through, in that they are -- the other liabilities are -- have to do with the natural price and a volume and a customer. And the Koch deal is a contractual dispute. And we view it as, number one, a onetime event, but also a contractual dispute, which is why we backed it out of ongoing adjusted EBITDA. And so we see it a little bit differently, but we want to disclose it. And we're not -- there's nothing about trying to avoid it or anything. I mean, it is a real dispute, and we'll see where it lands. And it could be a liability at some point in time. But we also obviously want to follow GAAP rules and be conservative on that.

Okay. My second question is on the gas contract issues and such just, were these firm contracts that you had that were not met? And just was there any particular counterparty that represented a large portion of what you are saying might be kind of illegal or inappropriate kind of breaking of those commitments?

Are you talking about the force majeure, Steve?

Yes.

Yes. On the -- yes, so I really don't want to get into individual counterparties on this, but fairly widespread that especially, I think the bulk of these force majeures were triggered on Friday when gas actually transacts for the weekend. But you can do this same research and you have -- I'm sure you have lawyers, but there has to be a reasonable effort by parties to fulfill their contract obligations. And the question is going to end up being, in my opinion, is whether they took reasonable efforts to deliver the gas to us or not. And is weather rising infrastructure or ensuring that who you're getting the gas from is weather-rising infrastructure. Is that a reasonable effort? In my opinion, it is. But we'll fight all this out in core. But I'm not -- I don't -- I'm not saying that anybody here did anything equal or anything. But sometimes there are contractual disputes between 2 parties. And you have to sell those in a court of law, and that's what's going to probably end up happening here. We work with these parties every day. We're continuing to do that. We have to do that. But we have a question about whether they fulfill their obligations under their contract. And we'll see whether that -- when we have a number of arguments on that.

Okay. And then last question, I guess, maybe for Jim, just on some of the financial disclosures. Just the potential other optimization transactions this year, is it fair to say none of those would be equity or equity-like, they would all be debt related?

Steve, I want to make sure I understand your question here. Are you speaking to a specific slide?

The slide when you're saying balance sheet optimization.

I know what you're speaking to, Steve. Yes, Steve, I know what you're talking about. You're talking about the balance sheet and optimizing the balance sheet.

Balance sheet, yes, right. The...

Yes. And in particular, with the optimization of the balance sheet, we're not talking about equity-like or equity transactions. But Steve, I want to be clear, on the growth projects, that may be different if we brought in a partner or something like that to accelerate the growth, and I'm talking about the renewables and batteries. But we never have done any of that. But with regard to just the pure balance sheet, we're talking about optimizing the cost of debt by transacting in the market.

That was my question. And just my other question was going to be on the partnerships. So that might be someone you bring in as an equity partner to help finance the partnerships?

That's right, Steve. We have -- since we've announced the pipeline last fall, there has been consistent interest from other parties to participate with a company that has operating capabilities. And so we've been approached for that. And that was part of the discussion that even started last fall. I think given our desire to stay in a position with a strong balance sheet, but still see these projects move forward, it's been an opportunity that we've continued to refine, and would look more like an equity-type partnership for the build-out of the renewables portfolio.

Jonathan Arnold with Vertical Research Partners.

A quick one. Do you have an early sort of thought around what your own weatherization efforts may cost and what the timing of those outlays would be?

Yes. So it will vary, Jonathan, but it's in the tens of millions, not multiples of hundreds of millions. The one thing that I like about what we can do, and this gives me an opportunity to mention this again, that we can do things that are 100% within our control and largely mitigate everything that happened to us. We can carry additional length, which will have a very modest cost to the overall performance of the company, and we can invest some money into our coal handling and coal freezing issues, this is sort of tens of millions of dollars. And then what we're looking at is weatherizing our system down to particular low temperatures. And depending how far we decide to go on that will depend on how much we're talking about and also just what things we decide to do because there's multiple ways of doing things. But the good news is that we're not talking about numbers that break the bank here. And if you combine carrying our length and weatherizing our assets, we should be able to largely mitigate the risk that we saw. So we can do that 100% ourselves. The question will ultimately end up being is if legislature does things, for example, on registering gas infrastructure and requiring weatherization and some other things, that might then even balance it further for us, where we don't have to spend as much money because there are other things that are going to reduce risk in the market. And so it's all a balancing act. What we are preparing for right now is that we're going to do all this 100% ourselves. And we're not going to sit here and wait for the legislature. But I think we're going to get a good indication from the legislature by the end of May anyway. And so we will not spend a bunch of money and be out a bunch of money before then anyway. So I think there's modest spending we can do here and actions that we can take that have very little impact on our overall financial performance and mitigate this risk, which is the biggest thing for us at the end of this is that we come out of this with a company that is strong, but also has mitigated the risk that exists in the market.

Okay. Great. And just sort of picking up on some things you've mentioned. One of the -- there seems to be a number of builds that are trying to push ancillary costs onto renewables side. Can you just maybe talk about how significant that could be and what your view is about that as an element of reform?

Well, there are some people in the legislature that would like to see that happen. I think they view that the federal tax credits, the incentives, I mean, that have been given to renewables in Texas have been a big driver of the build-out. And then they've also -- because they have 0 to negative marginal cost pricing, they've driven out dispatchable resources. And because of that, the market now is short on dispatchable resources that because the driver of that is renewables, that they ought to pay for some of this. I'm not sure that's the best market construct to put disincentives in the marketplace. I think we prefer incentives. And so I would prefer to incentivize dispatchable resources rather than disincentivize renewables. Having said that, I understand that, that costs money. And so there are some that believe that because we need more reserves of dispatchable resources because of renewables that they ought to pay a fair share of that. We'll see how that shapes out. I can't really get a good sense of whether there's a lot of support for that type of measure. But there are certainly some people and influential people in the legislature that have that mindset. And I don't think it's out of whack or anything. I mean, I understand it. I just don't know whether there's a groundswell of support for it. We're trying to -- and what we've proposed, which is along the lines of increasing reserves and lowering the overall ORDC is to obviously be mindful of cost, but also make sure that enough revenues in the system for not intermittent dispatchable resources that we keep the ones that we have around and we incentivize new build. And I think there's a real opportunity to do that. And I think it will be -- it would strengthen the market in a big way. How we end up paying for that, I think that we'll see whether there's something that is related to renewables or not in that.

Great. Can I just wrap it with 1 financial one. Just given what you've said about 2022 and beyond directionally in terms of EBITDA and what -- the way you're forecasting that debt for the end of this year, it would imply that you probably aren't looking at much in the way of incremental debt reduction as part of '22 capital allocation? Is that going -- reading too much into what you have up there? Or any thoughts about -- is 2.5x, I guess, still where you're intending to get to as well?

Yes, yes. I mean, look, we still have ways to go on '22. We haven't come out with guidance or anything. I think we have a -- we do have an idea of where we want to put capital. I think we're looking at a little bit less than $0.5 million -- $0.5 billion into debt repayment, which you're exactly right. That puts you roughly 3x. I think 3x is a comfortable place for us to be because the one thing we don't want to do is also get our capital allocation plan, so lopsided that we missed growth opportunities and that we don't have a balanced approach. I mean we're disappointed we're not going to be buying back our shares already in 2021. And I think we need to get back to that balanced capital allocation plan, and we need to be patient in doing so. And we'd like to pay the dividend. So there's only so many things you can do. But we think that continuing to pay down debt at some level is important with the agencies as well, but also just for the company to maintain its financial strength. I think we proved in spades that our idea when we came out of bankruptcy to keep our debt low and to have a strong balance sheet really helped us survive and not only survive but come out of the back end of this in a strong way. Had we been levered like the IPPs in the past, I think we'd be having a very different conversation, if even having a conversation with you guys right now. So I think what we've done is the right thing, but we're going to -- we're also -- we need to get back to a balanced plan in '22, and I think we're going to do that.

This ends the time allotted for Q&A. I will now turn the call back over to CEO, Curt Morgan, for final remarks.

Well, I'll reiterate again real quick that we're disappointed in this loss. It goes without saying, but I want to say it anyway, but we view this a bit as to get this information out to you guys. We want to move to the future. It is what it is. We're going to fight our way through this. We have a strong company. We're going to build from that strength. And we're going to move this company forward in a positive way. We got a big transformation of the company going on, and we can do that and continue to put up sizable EBITDA and free cash flow numbers. And that's our job, and we'll continue to move forward with the strength of the company. So thank you very much for your time. And as always, we're around to have further conversations.

This concludes today's call. We thank you for your participation. You may now disconnect.