Good afternoon, and welcome to First Solar's Third Quarter 2025 Earnings Call. This call is being webcast live on the Investors section of First Solar's website at investor.firstsolar.com. [Operator Instructions] And please note that today's call is being recorded. I would now like to turn the conference over to your host, Byron Jeffers, Head of Investor Relations. Please go ahead, sir.

Good afternoon and thank you for joining us on today's earnings call. Joining me are our Chief Executive Officer, Mark Widmar; and our Chief Financial Officer, Alex Bradley. During this call, we will review our quarterly results and share our outlook for the remainder of the year. After our prepared remarks, we'll open the line for questions. Before we begin, please note that some statements made today are forward-looking and involve risks and uncertainties that could cause actual results to differ materially from management's current expectations. We undertake no obligation to update these statements due to new information or future events. For a discussion of factors that could cause these results to differ materially, please refer to today's earnings press release and our most recent annual report on Form 10-K as supplemented by our other filings with the SEC, including our most recent quarterly report on Form 10-Q. You can find these documents on our website at investor.firstsolar.com. With that, I'll turn it over to Mark.

All right. Good afternoon and thank you for joining us today. Beginning on Slide 3, I will share some key highlights from Q3 2025. Since our last earnings call, we secured gross bookings of approximately 2.7 gigawatts at a base ASP of $0.309 per watt, including 0.4 gigawatts of Series 7 modules impacted by previously disclosed manufacturing issues booked at an ASP of $0.29. We terminated 6.6 gigawatts of bookings under multiyear agreements defaulted on by affiliates of BP, a European oil and gas major at a base ASP of $0.294 per watt. As a result, total debookings since the last earnings call were approximately 6.9 gigawatts, and our current expected contracted backlog is approximately 54.5 gigawatts. We delivered a record 5.3 gigawatts of module sales and reported Q3 earnings of $4.24 per diluted share, both near the midpoint of our previous earnings call forecast. Gross cash increased to $2 billion, supported by improved working capital, new bookings deposits and accelerated customer payments ahead of the effective date for the new beginning of construction guidance. Alex will walk through our financial results in more detail later in the call. From a manufacturing perspective, we produced 3.6 gigawatts of modules in the third quarter, 2.5 gigawatts from our U.S. facilities and 1.1 gigawatts from our international operations. In Q3, we reduced production in Malaysia and Vietnam, primarily due to lower demand driven by the customer default previously mentioned. We continue to advance our domestic capacity expansion, notably at our Louisiana facility, where we initiated production runs and started plant qualification. We have also continued to pursue the enforcement of our intellectual property rights. During the quarter, we made 3 separate filings requesting that the U.S. Patent and Trademark Office, or PTO, deny petitions filed by affiliates of Canadian Solar, JinkoSolar and…

Thanks, Mark. Beginning on Slide 5. As of December 31, 2024, our contracted backlog totaled 68.5 gigawatts valued at $20.5 billion or approximately $0.299 per watt. Through Q3, we recognized 11.8 gigawatts in module sales and recorded gross bookings of approximately 5.1 gigawatts. This included 4 gigawatts booked between the enactment of the reconciliation bill in early July and the September 2 effective date for the new commenced construction guidance. Since our last earnings call, we had gross bookings of 2.7 gigawatts and an average selling price of $0.309 per watt. This includes approximately 0.4 gigawatts of Series 7 modules impacted by previously disclosed manufacturing issues booked at an ASP of $0.29 per watt. The remaining bookings, 2.1 gigawatts were sold into the U.S. market at a blended ASP of $0.325 per watt. As a reminder, a significant portion of our contracted backlog includes pricing adjustments that may increase the base ASP contingent upon achieving specific milestones within our technology road map by the time of delivery. Accordingly, the ASPs presented exclude potential adjustments related to module bin, freight overages, commodity price fluctuations, committed wattage, U.S. content volumes and tariff changes. Our recent bookings scheduled for delivery in periods where such milestones could be met, the potential value is reflected in our backlog as an opportunity rather than the base ASP represented. And for example, among recent bookings, we secured a 0.6 gigawatt order for 2027 delivery at an ASP of $0.316 per watt with the potential for an incremental $0.046 per watt contingent on achieving specific milestones within our technology road map. Demand in the U.S. remains strong. However, we recorded full year debookings totaling 8.1 gigawatts as of September 30, including 6.9 gigawatts in the third quarter. The majority of these were driven by contract terminations with affiliates…

[Operator Instructions] The first question comes from Philip Shen, ROTH Capital Partners.

First one is on the 6.6 gigawatts of termination with BP. Just want to check in on whether or not in terms of rebooking this volume, it sounds like it's volume from '26 through '29. What kind of incremental pricing do you think you can get for this? Would you expect these bookings to get locked in following the Section 232 tariff announcement, which should be near term. So sometime in Q4, Q1? And then -- or do you think you might wait until things settle down post 232? And then the second question is tied into this as it relates to the 232, is there room for negotiation you think with any of your fixed price contracts that you have out there where they may not have been accounted for in terms of this new tariff. So just curious if you can share some color on that as well.

Yes, Phil. Look, I mean, now with the termination, we clearly are going to be engaging, looking, given our overall pipeline of opportunities to figure out the right opportunities for this volume in the respective windows that it was anticipated to be delivered. We will continue to be very patient in that regard. Assuming we can get good prices. Like if you look at the one deal that Alex included in his prepared remarks, the base price plus the CuRe adders gets that number into a little bit north of $0.36, close to $0.365. And I think that's a number that we would continue to look to engage. But at this point in time, I think there's other catalysts that could put a little bit more momentum behind that pricing as well, especially with the 232, as you referenced, and there's still obviously FEOC guidance that's going to continue to be provided as well. So a lot of insights or information that still is valuable to us to gain. If we can get good pricing, we'll continue to layer on some volumes into the years that we currently have available supply. But I think the value of being patient here is going to only work to our benefit in that regard. As it relates to the fixed price contracts, the value of certainty, I think, is what Alex indicated in his comments, and we said that many times before. The contracts are -- do not have latitude for something like a revised tariff environment that was not assumed at the time of the committed obligations that both parties assumed. So they do not allow openers for 232s as an example, but we still have capacity in the foreseeable future, especially through our international operations that we can use to engage the market and provide supply once we know the outcome of 232. But yes, the existing contracts that are on the books right now, those are obligations for both parties, and we take that seriously. That's also why we took the position that we did with the Lightsource BP transaction and the termination and enforcing our contractual rights. We worked, as we indicated in our prepared remarks, to try to get to an outcome that would be beneficial for both parties. We couldn't get there. So we had to enforce the contract. And we hold ourselves accountable to that as well. We have contracts and obligations to deliver. Pricing is fixed for certain respective adders and would not include tariff-related outcome or any other adjustments that were a result of the 232s that are being currently under investigation.

The next question today is Brian Lee from Goldman Sachs.

I guess, first, I just want to make sure I interpret this correctly. It sounded like, Mark, you're saying given the adders, indicative pricing, $0.36, $0.365 per watt, that's maybe kind of the level of entitlement you think you'll ultimately settle at once this game of patience evolves to, to when you really engage in pricing discussions post FEOC and 232. And then the second question, just on the 3.7 gigawatts finishing line, great to hear on that. But is the CapEx all being spent this year? And then maybe high-level thoughts around just expanding that. Why not simply do a full 7 gigawatts plus to cover both the Vietnam and Malaysia volume capacity?

Yes. So Brian, I think as you summarize what I said to Phil, I think that's the objective of where we'd like to ultimately see, especially with the -- on the other side of understanding of FEOC and the 232. That's kind of the entitlement that we would expect with -- especially for the new technology and the value add that we provide through CuRe. So I think you summarized that well. I'll let Alex talk to the CapEx. But before that, as it relates to where we are right now is 3.7 gigawatts, one of the things that we do want to try to keep measured is the finishing line will bring with it domestic content, right? But it's not going to bring the entire value stack of domestic content that we capture through our production in Perrysburg. The front-end semi-finished product that comes into the U.S., obviously, by definition, will not value -- not create domestic content value. So what we're trying to do is keep that throughput pretty much balanced so we can continue to blend. So even that contract that I referenced with the adders that got into the mid-36, that was still a blend of international and domestic. And so we think that by keeping that balance, it allows us to realize the highest potential value for that finishing line. So that's where our head is right now, 3.7 gigawatts kind of balances very well with the production that we have in Perrysburg, which is north of 3 gigawatts as well. We'll continue to evaluate whether there's an opportunity to bring more into the U.S. using the front-end capacity we have internationally. We'll have opportunities to better reassess that once we understand the outcome of 232 in particular and the FEOC guidance that we're looking forward to, and we'll make that decision at that time.

And Brian, just on the spend. So what we said is about $330 million of direct spend. Of that $260 million is CapEx. And of that $260 million, we'll spend about 10% of it this year, so $26 million. The remainder will be spent in 2026. The other $70 million, so $260 million of CapEx, $330 million of total spend, the other $70 million is non-capitalizable spend. So that's going to be decommissioning of the current tools, taking them out, cleaning, packing them, the freight to get them to the U.S., some tariff on the import, reinstallation. So all of that will be expensed versus capitalized. Of that $70 million, we're only forecasting spending about $2 million this year. The rest will come in 2026. There is some incremental charge that will hit this year. We said about $10 million. That's indirect associated with what we're doing. So it's not part of $330 million. That's some severance for some associates that will be impacted in Southeast Asia. And then there'll be some equipment write-off as well. There may be more associated with that in 2026, and we'll give you more color on that when we guide for next year.

Your next question comes from Moses Sutton from BNP Paribas.

In the past, Alex, you delineated, I think, 85% of either gigawatts or customers were in like a true take-or-pay structure contractually and 15%, maybe it was 16%, were supported by the nonrefundable deposits or termination fees. Was BP in the latter bucket, hence, the 20% that you're going after and litigating for that. Given BP is over 10% of the backlog or was at least, I would assume that they weren't in the take-or-pay bucket. But I just want to confirm and if you can comment on which bucket they are, and can you update how firm the rest of the contracts are? I think it would be a good time to give a mark-to-market on that.

Yes. So when you say take-or-pay, I think maybe what you're referring to is termination for convenience potentially. And so correct me if I'm wrong, but if you're referring to that piece, then the BP contracts were not contracts that had an ability to terminate for convenience. So they had no ability to exit those contracts. Now if they had wanted to cancel, they could have certainly worked with us. We would have had a discussion as potentially a solution we could have come to. But as Mark said, unfortunately, despite working with them for a long period of time, they chose to default on these contracts. We did have some cash deposits from them, and that's the piece that we recognize as revenue associated with the termination. We also had some LCs. Generally, that was going against some of the accounts receivable that we had outstanding. So we have pulled those LCs as well. And then the residual is generally parent guarantees, and that's the piece that we will be litigating to recover.

The next question comes from Jon Windham, UBS.

Just a quick point of clarification, and then I'll get on to my real question. Was the cancellation related to BP, was that all from international factories?

No, it was a mix of products, both international and domestic.

The supply -- just clear on this, the current year supply was essentially all international. So it was a mix. But the -- again, the contract goes out multiple years with delivery anticipated to go out through '29. So think of it as the front of that is mostly international. And as you get more longer-dated, it then transitions into domestic.

And then so thinking about it sort of net-net, is it half-half? How should we think about it?

Yes. I mean it's more than half of it being domestic, but a very -- a significant chunk of it being international.

Up next, we'll hear from Julien Dumoulin-Smith from Jefferies.

Just following up a little bit on the earlier commentary about the CapEx. You suggested that maybe one or more lines. Can you elaborate under what conditions you would look to seek to open multiple new lines on the finishing front? And how you would think about that in terms of the sourcing front as well internationally?

So just -- yes, it's also a distinction of how do we refine it. So right now, the -- there will be 2 lines in -- that we will be bringing into the U.S. for finishing. So there'll be 2 finishing lines, okay? And that is 3.7 gigawatts of capacity. We could bring more lines in, right? It doesn't have to be another 3.7 gigawatts. It could be effectively half of that to be another line, or we could potentially bring in 2 lines if need be. It's something that we're continuing to evaluate. There's enough front-end capacity to enable more finishing here in the U.S., obviously. A number of variables, number of items that we've already referenced will inform our decisions around that. We're very excited about getting the first 2 lines, which adds up to the 3.7 gigawatts capacity up and running here as we exit next year. And as we continue to evaluate market opportunities and demand, then we will form our decisions do we make additional investments and how do we bring those lines in, in terms of timing? And do we do just only 6? Or do we also look potentially to bring in Series 7 as well.

Next up is Ben Kallo from Baird.

Just following up, I think, on Brian's question earlier on pricing, the 4.1 gigawatts of opportunities confirmed but not booked. Can you talk anything about pricing there? And then with your cash balance, how do you think about that? Maybe, Alex, just the priorities of cash going forward over the next 2 years? I know there's a lot of uncertainty but thank you.

Yes. On that 4.1 gigawatts, Ben, that's more I would -- historical, I would say, pricing. Some of that's India, that's contracted that we don't count as a booking until we received all the security. And some of that is kind of variable pricing dynamics that we have with customers effectively, they can flex up or down from their MSA, their module sales agreement. So I wouldn't say that that's really a reflection of kind of current market pricing. All I would say is that we're happy with the market pricing that we're seeing. We believe there could be additional tailwinds that could further support a very favorable pricing environment for us, and we'll continue to engage the market and react accordingly.

Yes. Ben, as it relates to cash, clearly, cash positions increased quarter-over-quarter. We saw some activity during that safe harbor window where we saw some volume that was 100% prepaid. Some of that was taken at the same time within the quarter, some not. So you saw the deferred revenue amount increase. We also had some improvement in the working capital position, which we talked about expecting to improve as we got further into the year. So an increase in cash, no doubt, we're announcing some more CapEx for next year. As Mark said, we'll continue to look at additional finishing lines and see if there's an opportunity there. But the overall framework we use to evaluate cash is one we've talked about before, it hasn't fundamentally changed around running the business day-to-day, looking at additional capacity, looking at M&A, especially as it relates to R&D. And then if we get to a point where we can't accretively deploy that capital, we'll look at capital return. We'll give a further update as we go into next year's guidance, how we think about capital structure longer term.

David Arcaro from Morgan Stanley has the next question.

I was just wondering if you could give a little color on your confidence level in the 54.5 gigawatts backlog now. Are there other customers that you think could be at risk that you're aware of that you're risk weighting in there? Or any other market dynamics that make you think or customer-specific dynamics that make you think this debookings pace could continue or not?

Yes. So we've been saying now for, I don't know, it could be going on close to 2 years now, something along those lines. There's been indications by a number of large oil and gas multinationals, international companies that are continuing to evaluate their commitment to renewables, right? And obviously, BP falls in that bucket. There's been others as well. Just think about NatGrid. NatGrid, obviously, a large European company that made a decision to sell down its development business going back to now Geronimo, sold it over to Brookfield. You could look at Enel as another example of a commitment to the U.S. market that had been reevaluated. Now I think they've changed their perspective in that regard. And there's a couple of others, which I won't name, but it's -- EDF is, I guess, maybe another one I would throw into that bucket a little bit. I mean it's not oil and gas, but obviously, a large European company that's reevaluating its commitment to the U.S. market. So there's -- obviously, that risk profile is something we foreshadowed. It's something that has played itself out. If you go back and if you look at what's in our contracted backlog, you can go back and look at announced deals that we've done, who some of our larger partners are, you're going to find that, that profile is dramatically different with what sits in our contracted backlog. Now having said that, I mean, we all know that a number of developers and IPPs here in the U.S. I mean, they're working through a number of challenges, right, and permitting issues and project-related issues and what have you that things could evolve in such a way that at a project level, we could potentially see some movement. We said in the…

Next up is a follow-up from John Windham, UBS.

Perfect. I wanted to ask about a topic we haven't covered much on this call is how the ramp in product quality is in Louisiana and Alabama. Can you just touch on how that's running next to expectations?

Look, the ramp for DRT, I would say that it has gone well. It's an aggressive ramp that we've had -- sorry, Alabama referred to it by acronyms. It actually has gone well, but it's also had its own set of challenges that we've been working through in terms of the ramp process and getting to full entitlement and throughput. And where I see the factory at right now for Alabama, I see it at a very good level. It's hitting its throughput requirements. It struggled, as we indicated in our prepared remarks, with a disruption on our glass supply chain. And obviously, that had an adverse impact on the factory. Louisiana is going extremely well. We're in the midst of going through our product qualification and that will be complete here in Q4, and we'll start shipping product. And right now, the ramp is ahead of schedule, which is all very positive for us in that regard. As you said, I think you may have mentioned product quality and the like. We are continuing to do, as always, being very diligent as we manufacture our product and to ensure that we have a high level of indication of field performance based off of not only accelerated life testing, but obviously, field deployment as well. And it's something that our level of rigor and intensity around that is only going to continue to be more heightened as a result of the initial launch of Series 7. Again, that was the launch of a new product. In this case, both Alabama and Louisiana are just replications of the factories that we launched our Series 7 technology from. And the key learnings that we captured from that launch and some of the changes that we've already communicated that we needed to make to our manufacturing process, both were implemented into Alabama and Louisiana before we started production. But it's something we know with the reputation, it's a brand issue, we got to stay on top of it, and we're going to continue to do everything we can to meet our customers' expectations in that regard.

The next question comes from Vikram Bagri from Citi.

Just a quick question. Mark, can you remind us of if there is a precedent of successful litigation against a customer who is in a similar breach of contract or this case with BP will set a precedent for future?

Yes. I don't have my GC in the room right now because I could ask that question. But what I can tell you is that we are using outside counsel. We have -- we believe very strong contracts that enforce the rights and obligations of both parties. And we believe that if either of those parties are in default, and there's consequences associated with that. I would also use whether there's legal precedents, and I'm sure there are, while I can't cite them to you right now, what I would go back to is if you look at the -- I believe we've had a number across the last couple of years, somewhere in the range of north of $200 million, $250 million or so of various terminations. I think we've also disclosed that about $70 million is sitting outstanding, okay? That means that the vast majority of that -- those terminations were paid because the counterparties understood the obligations and the terms and conditions of the agreements, which are essentially identical across our contracts. And they have honored that obligation in respect of that obligation, and they've remitted payment. They would not have done that unless they thought -- if they thought that there was a reason why underneath the contract that they would not have an obligation to for solar -- for their default. So I can use 2 data points. One is just look at experience and the other is the input that we're getting from outside counsel around our contracts. And we feel very good about the contracts, the way they're structured and the enforceability of the contracts. And my understanding is that, again, this will be -- the filing of the litigation is in the state of New York. I think my understanding is the state of New York has taken a very strong position around this type of condition underneath the contract for default and associated with termination payment. And generally, the courts in New York have cited with the plaintiff in the situation of similar circumstances. So that's about as much information as I have. I do believe, though, we're in a strong position.

Our final question today will come from Joseph Osha, Guggenheim Partners.

As we think about the timing of the finishing fab coming up in the U.S. and what the commercial environment looks like, I'm wondering what conclusion we can draw about under-absorption of Malaysia and Vietnam next year. And perhaps to put a sharper point on that is, is there any market at all for products being shipped directly out of either of those 2 fabs?

Yes. So one thing to remember is that we're using the front-end capacity of our international facilities in order to fund that into the U.S., right? And when you think about the cost structure and the absorption, especially around the capital intensity of the equipment, it largely sits on the front end of the processing. So you're going to see reasonably good absorption for that front-end manufacturing that then is finished in the U.S. We also identified that we have taken some headcount reductions. So we are minimizing the back-end processing of the labor associated with that. And then those tools that are being used in the back end are being brought into the U.S. So therefore, the depreciation there will be absorbed against the finishing processes that are being done here in the U.S. So just to put that in perspective. Yes, as it relates to the balance of that production, one of the things we're continuing to work through, and we are in negotiations with a couple of counterparties to almost do a bilateral for that offtake of that volume and to structure a deal around that so we can get to terms. We'd like to find potentially a couple of large customers with large offtake requirements that we can then sort of just sole source that into those opportunities. But clearly, we believe there is an opportunity subject to the tariff environment, subject to what happens with 232, subject to FEOC guidance and everything else. So there's some more triggering events that would have to happen. I think we said in our prepared remarks; we have something like 6 gigawatts of contracted backlog or something like that for Series 6 international still. So we've got some runway in terms of volume and absorption for those production assets, and then we'll continue to evaluate them as we learn more about some of these policy decisions that will be made.

Everyone, that does conclude our question-and-answer session. This also concludes our conference for today. We would like to thank you all for your participation today. You may now disconnect.