Q3 2025 Earnings Call Transcript

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 Mundra that seek to invalidate our U.S. TOPCon patents. Our filings include a reference to comments made earlier this year by the Acting Director of the PTO who stated, "the longer a patent has been enforced, the stronger and more settled the patent owners' expectations should be." We believe our ongoing vigorous enforcement of our decade-old U.S. TOPCon patents, which we consider fundamental to producing that technology is a prime example of a patent holder having settled expectations of the integrity of its IP rights.

The view that module manufacturers and their customers and financing parties should strongly consider the potential hurdles of producing, selling or purchasing modules employing TOPCon cell technology is not one held just by us. For example, earlier this quarter, the CEO of ES Foundry explained that his company's decision to focus on manufacturing PERC technology was due, at least in part, to the "legal troubles that would be encountered by TOPCon producers." Lastly, we're pleased to continue building on our commitment to responsible solar, not simply by exceeding industry norms in sustainability and human rights, but by continuously improving on our own performance.

Our Ohio facilities, which previously earned a silver rating in the Responsible Business Alliance's validated assessment program have progressed to a gold rating in its 2025 audit, which was completed this past quarter. Turning to Slide 4. I will now provide an update on our manufacturing operations. As it relates to our Alabama facility, 2 of our domestic glass suppliers faced manufacturing disruptions that limited our ability to operate at full capacity, which impacted Q3 production by approximately 0.2 gigawatts. The primary supply chain issue resulted from throughput limitations due to insufficient initial facility readiness at a new factory, while simultaneously a different supplier experienced unplanned downtime.

Corrective actions have been implemented at both suppliers and our U.S. glass supply base is again positioned to meet our requirements. While now resolved, this resulted in a temporary shortage of cover glass supply to our Alabama facility, which led to reduced production and increased underutilization charges in the third quarter. Our Louisiana factory has initiated integrated production runs, started plant qualification and the early stage ramp is slightly ahead of expectations. We anticipate receiving required production certificates in Q4 and will begin shipment at that time.

As it relates to our international capacity, we have previously indicated the implementation of the Reconciliation Act earlier this year as well as the evolving universal and reciprocal tariff environment could potentially support a business case to establish one or more lines in the U.S. to finish front-end production initiated within our international fleet. We have made the decision to establish a new production facility in the United States, allowing us to onshore the finishing of Series 6 modules initiated by the company's international factories. While the location is subject to final negotiations, we have -- with an announcement expected in the coming weeks, the planned capacity will be 3.7 gigawatts.

Production will start at the end of '26 and ramp through the first half of 2027. As we previously noted, such an investment is expected to enable additional production in the U.S. market that we expect will be fully compliant with forthcoming FEOC guidance as well as improve the gross margin profile of our sales by reducing tariff charges and logistics costs associated with importing finished goods. Furthermore, we expect that the modules produced at this facility will provide domestic content points benefits for our customers and qualify for 45X module assembly tax credits. We continue to evaluate options for the remainder of our international Series 6 capacity, including options related to long-term U.S. market demand, U.S. market supply and the global tariff environment.

Shifting to the current policy landscape. The U.S. policy and trade environment remains generally favorable. As we have long stated, one of First Solar's key competitive differentiators is the ability to provide certainty to our customers, both in terms of pricing certainty and the certainty of timing, producing, and delivering product. These attributes are particularly valuable in the U.S. solar market, where fiat-compliant suppliers who have domesticated their supply chains and localized their production capabilities provide the surest pathway to enable developers to realize tax benefits and to mitigate the exposure of project pro formas to both the imposition of tariffs and the risk to project schedules associated with relying on imported products.

A number of trade and policy developments over the quarter amplified these competitive differentiators. In August, the U.S. Court of International Trade ruled that the Biden administration's 2-year suspension of circumvention-related antidumping and countervailing duties was unlawful, paving the way for possible retrospective duty payments on solar imports brought into the United States between June '22 and June of '24. Also during the quarter, the U.S. International Trade Commission issued a preliminary affirmative determination in an antidumping and countervailing duty case known as Solar 4, that imports of crystalline silicon cells and modules from India, Indonesia and Laos are causing material injury to the U.S. solar industry.

In addition to a range of alleged illegal subsidies, the petitioners identified dumping margins of approximately 90% for Indonesia, approximately 247% for Laos and approximately 215% for India. Also during the quarter, U.S. Custom and Border Protection issued a notice of initiation of investigation and interim measures against an affiliate of Huawei Solar in response to a claim submitted by the American Alliance for Solar Manufacturing Trade Committee, of which First Solar is a member that Huawei has effectively transshipped Chinese solar cells and modules into the United States through India. In addition, we, together with the rest of the industry, are awaiting the results of the administration's 232 polysilicon and derivatives investigation including the potential for incremental tariffs impacting the crystalline silicon supply chain.

From a policy perspective, the industry also awaits guidance from the administration related to project impacts from foreign entity of concern or FEOC procurement, which may be delayed as a result of the ongoing government shutdown. In short, there continues to be mounting headwinds or uncertainties for U.S. developers associated with procurement dependent on Chinese crystalline silicon supply chain, which we believe enhances the value proposition of our vertically integrated production capabilities. It also validates our approximately $4.5 billion investment strategy of expanding our U.S. manufacturing production and reshoring supply chains, which began under the first Trump administration and continues through the current Trump administration with our most recent facility currently ramping in Louisiana and the announcement of our new U.S. finishing line.

This activity places us uniquely at the intersection of several of the administration's key priorities, including those related to domestic manufacturing job creation, American energy and energy affordability and serving among the generation solutions that enable the U.S. to win the artificial intelligence race against China. Turning to India. Since our last earnings call, there have been several notable policy deployments. First, significantly, the application of tariff rate for imports of finished modules into the U.S. was increased to 50%.

We continue to monitor dialogue between the U.S. and Indian government related to a potential bilateral trade treaty, easing of tariffs between the 2 countries. As it relates to the country's domestic market, the Indian government continues to promote its domestic renewable energy value chain by progressively including cells in the remit of the approved list of models and manufacturers under a recently announced LIST-II. Inclusion in list becomes mandatory for solar OEMs to sell into key segments of the domestic market effective June of '26. Notably, First Solar was automatically qualified in this list, which was released in August of '25. The Indian government also released stakeholder consultation in September of '25 related to a further extension of the ALMM regulations to include domestically made wafers for potential deployment after June of 2028. Once again, First Solar's India's production is expected to automatically qualify.

We anticipate that these regulations will progressively strengthen our position in the Indian market by leveling the playing field. I'll now turn the call over to Alex to discuss shipments, bookings, Q3 financials and guidance.

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 of BP, which accounted for 6.6 gigawatts. Note, aside from the contract terminations with the BP affiliates, a number of other terminations were for project-specific reasons as opposed to reflecting customer pivots from solar project development generally.

For example, our Q3 bookings include volume expected to be delivered to a customer who terminated a project in 2024, but is recommitted to solar development in 2025, continues to source its module supply with First Solar. In addition, we're currently in active negotiations for the procurement of new volume with another customer who previously terminated a contract with us for a specific project of theirs earlier this year. In both cases, these customers satisfied their termination payment obligations. In prior calls, we highlighted the emerging risk of a strategic shift concerning multinational oil and gas and power utilities companies, particularly those based in Europe, with some moving away from renewables project development and back towards fossil fuel investments.

On September 30, First Solar filed a lawsuit against BP Solar Holding LLC and its affiliate Lightsource Renewable Energy Trading following their failure to cure multiple breaches of contractual obligations. According to public reports published earlier in the year, BP has been looking to divest its interest in its renewable's development arm. Despite agreements to purchase approximately $1.9 billion or 6.6 gigawatts of solar modules, these BP affiliates did not meet required payment obligations or provide required payment security. After issuing default notices and providing opportunities to cure, we terminated the contract, which entitles us to approximately $385 million in termination payments.

Of this amount, we've recognized $61 million in previously collected down payments as revenue. We're seeking monetary damages, which includes approximately $324 million in remaining termination payments, along with certain other receivables for solar modules previously delivered and interest. And if realized, the $324 million we recognized as revenue. We were ready, willing and able to continue fulfilling our contractual obligations to these BP affiliates and are disappointed that we must resort to litigation.

The modules that are subject to the contract breach are a mix of domestic and international product, most of which were scheduled to be produced in Q3 and future quarters with deliveries expected to extend into 2029. We're working to address the planned allocation of module inventory that could have been delivered to the BP affiliates, if not for their contract breach. With respect to such planned future module production, the market for these modules may be constrained by the U.S., Indian and European policy and market conditions discussed on the February earnings call and that has since been further exacerbated in the U.S. with our traditional utility-scale customer experiencing transmission and permitting related challenges in large part due to the constraints reflected in the July Department of Interior memo related to renewables project development, the ongoing government shutdown and the impact of tariffs.

Note these same factors, which are further exacerbated by the breach of contract to these BP affiliates given our loss of contracted offtake for the product may drive further underutilization charges being realized in 2026 as it relates to our Southeast Asian production facilities for the planned module volume expected to be delivered to these BP affiliates. As a result, our quarter end contracted backlog stood at 53.7 gigawatts valued at $16.4 billion or approximately $0.305 per watt. And as of today, our total expected contracted backlog stands at 54.5 gigawatts, excluding any volumes sold after the end of the quarter.

Moving to Slide 6. Our total pipeline of mid- to late-stage booking opportunities remain strong with bookings opportunities of 79.2 gigawatts and mid- to late-stage booking opportunities of 17.8 gigawatts. Our mid- to late-stage pipeline includes 4.1 gigawatts of opportunities that are contracted subject to conditions precedent. As a reminder, signed contracts in India will not be recognized as bookings until we received full security against the offer. I'll now cover our third quarter financial results on Slide 7. We recognized 5.3 gigawatts of module sales during the quarter, including 2.5 gigawatts from our U.S. manufacturing facilities.

Our net sales totaled $1.6 billion, representing an increase of $0.5 billion compared to the prior quarter. This increase was primarily driven by higher shipment volumes and the anticipated back-weighted profile of deliveries over the course of the year. Our sales included $81 million in contract termination payments with $61 million related to the contract breached with the BP affiliates. This amount was recognized from existing cash deposits.

Gross margin for the quarter was 38%, a decrease from 46% in the prior quarter. This decrease was primarily due to a lower mix of modules sold from our U.S. manufacturing facilities, which benefit from Section 45X tax credits. Additionally, we incurred higher underutilization costs due to continued production curtailments in Southeast Asia, the BP affiliates termination and glass supply chain disruption at our Alabama facility. As an update on warranty-related matters, we've resolved certain obligations and advanced negotiations with additional customers regarding manufacturing issues affecting select Series 7 modules produced prior to 2025. Based on our settlement experience, the estimated number of effective modules and projections of probable remediation costs, we believe a reasonable estimate of potential future losses will range from approximately $50 million to $90 million.

Within this range, we've recorded a specific warranty liability of $65 million, an increase of $9 million from our prior estimate, representing our best estimate of expected future losses associated with these manufacturing issues. As of the end of the third quarter, we maintained approximately 0.6 gigawatts of potentially impacted Series 7 inventory, including 0.2 gigawatts under contract and included in our backlog. SG&A, R&D and production start-up expense totaled $145 million in the third quarter, an increase of approximately $6 million compared to the second quarter. This increase was primarily driven by start-up costs associated with the accelerated ramp-up of our Louisiana facility, aimed at providing resiliency to our U.S. production for the year.

Operating income for the quarter was $466 million, which included $138 million in depreciation, amortization and accretion, $49 million in ramp and underutilization costs, $37 million in production start-up expense and $7 million in share-based compensation. Nonoperating income resulted in a net expense of $6 million in the third quarter, representing a decrease of approximately $4 million compared to the prior quarter. This was primarily driven by higher interest income as a result of an increase in investable cash, cash equivalents and marketable securities. Tax expense for the third quarter was $4 million compared to tax expense of $10 million in the second quarter.

This decrease in tax expense was primarily driven by a $19 million discrete tax benefit associated with the acceptance of a filing position on an amended tax return in a foreign jurisdiction, partially offset by higher pretax income. This resulted in third quarter earnings of $4.24 per diluted share. Turning to Slide 8, I'll discuss select balance sheet items and summary cash flow information. At the end of Q3, our total cash, cash equivalents, restricted cash and marketable securities stood at $2 billion, an increase of approximately $0.8 billion from Q2, driven by improved working capital, new bookings deposits and accelerated customer payments ahead of the effective date for new beginning of construction guidance.

As disclosed in our Form 8-K on October 20, 2025, we executed 2 Section 45X tax credit transfer agreements totaling up to $775 million in tax credits, a fixed agreement for the sale of $600 million in tax credits at a purchase price of $573 million payable by year-end and a variable agreement for sale of up to $175 million in tax credits with payment expected in Q1 2026. These transactions highlight the liquidity of the 45X credit market and strengthen our near-term liquidity to support our technology road map and expansion priorities. Accounts receivable decreased sequentially driven by higher cash collections.

At quarter end, total overdue balances were approximately $334 million, including a deferred payment settlement of $93 million with a customer, for which interest payments remain current. In addition, we have approximately $70 million in uncollected receivables related to termination payments. We currently have $82 million in accounts receivable for delivered modules that are aged and past due with the aforementioned BP affiliates. This does not include any additional anticipated proceeds from potential recoveries associated with the breach of contract.

Although termination payments remain contractually due, these balances are expected to persist pending the resolution of arbitration and litigation. In all instances of contract termination, we're actively pursuing all available remedies, including arbitration and litigation to enforce our contractual rights and recover amounts owed. Deferred revenue increased by $395 million, primarily due to accelerated customer payments ahead of the effective date for new beginning of construction guidance, partially offset by revenue recognized from delivered modules and termination payments. Capital expenditures totaled $204 million in Q3, mainly driven by investments in our Louisiana facility, where we initiated production runs and started plant qualification.

As a result, our net cash position increased by approximately $0.9 billion to $1.5 billion. Before addressing our updated guidance, I'd like to revisit the policy and trade environment that shapes our operational decisions throughout the year. These evolving dynamics influenced our strategy, impacted quarterly performance and informed our adjustments to forward guidance. Our 2025 shipment profile required sustained production to fulfill contractual commitments concentrated in the second half of the year amid significant trade and tariff uncertainty.

During this period, we navigated a range of potential tariff scenarios, customer negotiations and regulatory developments, including Section 232 actions, FEOC restrictions and AD/CVD investigations. At one point, we managed 2 possible tariff regimes, a continuation of a 10% universal tariff or adoption of reciprocal tariffs initially set at 26% for India, 24% for Malaysia and 46% for Vietnam, later amended to 50%, 19% and 20%, respectively. Our strategy has been to maintain sufficient capacity to fulfill international module commitments and to actively pursue tariff recoveries from customers, at the same time as temporarily curtailing or idling capacity and recording underutilization in circumstances where tariff recovery was unlikely and module sale economics would be challenged.

The upper end of our prior guidance assumes sustained production with partial tariff recoveries, whereas the lower end reflected risk by termination-related impacts, including additional underutilization costs and margin erosion from terminated contracts. Three significant updates drive our revised guidance ranges today. Firstly, the decision announced today to establish a new 3.7 gigawatts U.S. production facility, enabling us to onshore finishing for Series 6 modules initiated by our international fleet will result in approximately $330 million of total program direct spend, including approximately $260 million of capital expenditures and approximately $70 million of non-capitalized expense associated with equipment de-installation, cleaning, packaging, shipping, import tariffs and reinstallation.

Of this, we expect an incremental $26 million of CapEx and $2 million of production start-up expense in 2025. In addition, we forecast approximately $10 million of incremental indirect charges in 2025 associated with this decision, including severance and asset impairment expenses. As previously noted, we continue to evaluate options for our remaining Malaysia and Vietnam facilities. Today's guidance excludes any additional costs associated with potential restructuring charges or asset impairments that may impact 2025 or future operating results. Secondly, as it relates to the termination of contracts with affiliates of BP, the loss of gross margin assumed in 2025 was largely offset by the termination payment recorded in Q3. Increased underutilization expenses from reduced plant throughput as we curtail production given this termination of demand were incorporated in the low end of our guidance range.

Thirdly, as previously discussed, simultaneous incidents at 2 of our glass suppliers led to a shortage of glass available at our Alabama facility in Q3. This reduced full year production by approximately 0.2 gigawatts, resulting in a reduction to gross margin and Section 45X tax credits and increased underutilization costs. Turning to Slide 9. I'll now outline the key updates to our 2025 guidance ranges, which incorporate the cascading impact of our third quarter operational and financial results. Our net sales guidance is projected at $4.95 billion to $5.20 billion, reflecting a downward revision of approximately 0.5 gigawatts from the top end of our prior guidance.

This adjustment primarily reflects reduced international volumes sold due to customer terminations, partially offset by termination payments as well as 0.5 gigawatt reduction in assumed domestic India sales following the midyear redirection of India product from the U.S. market to the domestic book and bill market, driven by the high tariff for imports into the U.S. Additionally, U.S. manufactured volumes sold is expected to decrease 0.2 gigawatts at the high end of the guide as a result of Q3 glass supply constraints at our Alabama facility, partially offset by 0.1 gigawatts at the low end by expected increased supply from our Louisiana factory.

Gross margin is expected to be between $2.1 billion and $2.2 billion or approximately 42%. This includes approximately $1.56 billion to $1.59 billion of Section 45X tax credits and $155 million to $165 million of ramp and underutilization costs. The bottom end of our previous guide has increased significantly due to further curtailment of our Southeast Asia manufacturing capacity following the contract terminations by affiliates of BP. SG&A and R&D combined expense is expected to total $425 million to $445 million and total operating expenses, which include $90 million of production start-up expense, are expected to be between $515 million and $535 million.

Operating income is expected to range between $1.56 billion and $1.68 billion, implying an operating margin of approximately 32%. This guidance includes $245 million to $255 million in combined ramp, underutilization and production start-up expense as well as approximately $1.56 billion to $1.59 billion in Section 45X tax credits, net of the anticipated discount associated with the sale of these credits. This results in a full year 2025 earnings per diluted share guidance range of $14 to $15. In summary, the upper end of our EPS guidance range is reduced by $1.50 per diluted share. This includes approximately $0.60 per share from the supply chain impacts at our Alabama facility, which resulted in increased underutilization costs and lower volumes sold.

Contract termination by BP affiliates reduces EPS by another approximately $0.60 per share due to increased underutilization costs and lower volumes sold, partially offset by termination payments. The remaining $0.30 per share is a combination of reduced India volumes sold, increased production start-up expense, finishing line costs and warranty expense, partially offset by non-BP affiliate termination payments and decreased full year tax expense. Capital expenditures for 2025 are now expected to range between $0.9 billion and $1.2 billion. Our year-end 2025 net cash balance is anticipated to be between $1.6 billion and $2.1 billion.

Turning to Slide 10, I'll now summarize the key messages from today's call. Despite some near-term headwinds, we continue to believe that our integrated domestic manufacturing platform and reshored domestic supply chain position us for long-term success. We're building a new 3.7 gigawatts capacity module finishing line in the U.S., which is expected to begin production in Q4 of 2026 and ramp into the first half of 2027. We delivered a record 5.3 gigawatts of module sales, and our Q3 earnings per diluted share came in above the midpoint of our guidance range at $4.24 per share. We saw an improvement in our gross cash position to $2 billion and recently executed agreements to sell additional Section 45X tax credits, which we expect to further enhance our liquidity position.

We've revised our full year guidance to reflect the impact of third-party glass supply chain disruptions as well as the termination of 6.6 gigawatts of volume by affiliates of BP which we recognize a partial termination payment and a filed a lawsuit for damages for breach of contracts. With this, we conclude our prepared remarks and open the call to questions. Operator?

[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.

Julien Dumoulin-Smith: 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 call today, we had a couple of customers that have project-specific terminations, one of them who terminated last year project specific, and then now they're back on our order book for more than 0.5 gigawatt of volume. And then we had another one who terminated this year that we're actively negotiating a meaningful contract with. So I don't want to give an indication of there may not be further terminations. But I also want to somewhat reflect that I don't think something as large and structural as what we saw with Lightsource is a high risk.

But at any point in time, things can evolve, things could change. A number of our partners have sponsor capital behind it. If Brookfield decides to go a different direction, if KKR decides to go a different direction, if TPG decides to go, Macquarie, I mean, you name whoever sponsor you want to say is behind a portfolio business, if they decide to pivot and go a different direction. I mean there's always an inherent risk in that regard.

But what I would say is that while there's still challenges and issues that are being dealt with, there's an opportunity here. The policy environment, I think, is very -- still very positive with what came out of the One Big Beautiful Bill. There is a need for more electrons on the grid. The load profile is only going to continue to grow and project economics and PPAs are still strong, right?

So I think those fundamentals, I think, still I would say it's enduring and that we would have a higher level of confidence in contracted offtake agreements that we have on our books right now. But I also want to be balanced in understanding that there could be some amount of risk. But I do think that on balance, there's a lot of market opportunity for our partners and obviously, for us to continue to supply into the market.

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.