Earnings Call Transcript - FSLR Q3 2025

Operator, Operator

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. 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.

Byron Jeffers, Head of Investor Relations

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.

Mark Widmar, CEO

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 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 an announcement expected in the coming weeks, and the planned capacity will be 3.7 gigawatts. Production will start at the end of 2026 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 supply chain-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 2022 and June 2024. 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. Customs 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 and 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 continue to be mounting headwinds or uncertainties for U.S. developers associated with procurement dependent on the 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 two 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 the list becomes mandatory for solar OEMs to sell into key segments of the domestic market effective June 2026. Notably, First Solar was automatically qualified in this list, which was released in August 2025. The Indian government also released stakeholder consultation in September 2025 related to a further extension of the ALMM regulations to include domestically made wafers for potential deployment after June 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.

Alexander Bradley, CFO

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 roadmap 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 roadmap. 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 renewables 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. 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 roadmap 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 two 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 while simultaneously 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 from 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 two 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 a 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 are expected to decrease by 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, from which we recognized a partial termination payment and have filed a lawsuit for damages for breach of contracts. With this, we conclude our prepared remarks and open the call to questions.

Operator, Operator

The first question comes from Philip Shen, ROTH Capital Partners.

Philip Shen, Analyst

The first question is about the 6.6 gigawatts of termination with BP. I'm checking on the rebooking of this volume, which sounds like it's from 2026 to 2029. What kind of incremental pricing do you anticipate? Do you expect these bookings to be finalized after the Section 232 tariff announcement, which should happen soon, possibly in Q4 or Q1? Or do you think you might wait until things stabilize after the 232 announcement? Additionally, related to the 232, is there room for negotiation on any of your fixed price contracts that might not have accounted for this new tariff? I'm curious if you can provide some insight on that.

Mark Widmar, CEO

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 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.

Operator, Operator

The next question today is Brian Lee from Goldman Sachs.

Brian Lee, Analyst

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?

Mark Widmar, CEO

Yes, Brian, I believe you captured my thoughts regarding Phil well. Our goal is to achieve a particular outcome, especially in relation to the understanding of FEOC and the 232. This is the entitlement we anticipate, particularly for the new technology and the value we add through CuRe. I'll let Alex discuss the CapEx shortly. Currently, we are at 3.7 gigawatts, and it's important for us to maintain a measured approach because the finishing line will bring some domestic content but not fully represent the total domestic content value generated from our production in Perrysburg. The semi-finished product entering the U.S. will not qualify as domestic content by nature. We're aiming to keep that throughput balanced so we can blend effectively. The contract I mentioned with the mid-36 adders was still a combination of international and domestic sources. We believe that maintaining this balance will allow us to maximize the value of the finishing line. At this stage, 3.7 gigawatts aligns well with our Perrysburg production, which exceeds 3 gigawatts. We will continue to assess if there's potential to increase imports into the U.S. using our front-end capacity internationally. We will have further clarity to reevaluate once we receive guidance on 232 and FEOC, and we'll make our decisions based on that information.

Alexander Bradley, CFO

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.

Operator, Operator

Your next question comes from Moses Sutton from BNP Paribas.

Moses Sutton, Analyst

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.

Alexander Bradley, CFO

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.

Operator, Operator

The next question comes from Jon Windham, UBS.

Jonathan Windham, Analyst

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?

Alexander Bradley, CFO

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

Mark Widmar, CEO

The current year's supply was primarily international, representing a mix. The contracts span multiple years with deliveries expected to extend through 2029. Initially, most of the supply is international, but as the timeline progresses, it shifts to domestic.

Operator, Operator

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

Julien Dumoulin-Smith, Analyst

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?

Mark Widmar, CEO

We are currently planning to introduce two finishing lines in the U.S., which will have a combined capacity of 3.7 gigawatts. There is potential to bring in additional lines; it doesn't necessarily have to be another 3.7 gigawatts. For example, we could add a line that has a capacity of half that amount, or possibly even two lines if necessary. We are actively assessing this possibility. We already have sufficient front-end capacity to support more finishing operations in the U.S. Several factors that we mentioned previously will guide our decisions on this matter. We are particularly enthusiastic about launching the first two lines, which will total 3.7 gigawatts, as we approach the end of next year. As we continue to explore market opportunities and assess demand, we will determine if additional investments are warranted and how we can phase in those lines, including the timing and whether to proceed with just six lines or also consider adding Series 7.

Operator, Operator

Next up is Ben Kallo from Baird.

Ben Kallo, Analyst

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.

Mark Widmar, CEO

Yes. Regarding the 4.1 gigawatts, I would describe the pricing as historical. Some of that is from India and is contracted, but we don't consider it a booking until we receive all the security. Additionally, there are variable pricing dynamics with customers that allow them to adjust their module sales agreements. Therefore, I wouldn’t interpret that as a true reflection of current market pricing. Overall, we’re satisfied with the market pricing we are observing. We believe there may be additional factors that could further enhance a positive pricing environment for us, and we will continue to engage with the market and respond as needed.

Alexander Bradley, CFO

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.

Operator, Operator

David Arcaro from Morgan Stanley has the next question.

David Arcaro, Analyst

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?

Mark Widmar, CEO

We've been discussing this for almost two years now, and many major oil and gas companies are reassessing their commitment to renewables, including BP. For instance, National Grid, a large European firm, chose to divest its development business by selling it to Brookfield. Enel is another illustrative example of a company that has recently shifted its stance on its U.S. market commitment. EDF, although not in the oil and gas sector, is also reconsidering its U.S. engagement. This shifting risk profile is something we've anticipated, and it reflects in our contracted backlog, which is quite different from what we've previously reported. Several developers and independent power producers in the U.S. are facing challenges such as permitting and other project-related issues, which might lead to some changes at the project level. Recently, two customers have terminated specific projects. One of these companies, which had terminated last year, is now back with over 0.5 gigawatts of volume, and we are actively negotiating with another customer who terminated this year. While I acknowledge the possibility of further terminations, I don’t foresee something as significant as we experienced with Lightsource as a high risk. That said, there is always the potential for change, especially if our partners decide to alter their direction. However, while challenges remain, there are also substantial opportunities in the market. The policy landscape remains favorable following the One Big Beautiful Bill, and there is an increasing demand for electricity. Project economics and power purchase agreements continue to be robust. I believe these fundamental factors are strong, and we have a good level of confidence in our contracted agreements. Still, we need to recognize that risks do exist, but overall, the market holds significant opportunities for our partners and us moving forward.

Operator, Operator

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

Jonathan Windham, Analyst

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?

Mark Widmar, CEO

The ramp for DRT has been going well, although it is aggressive. While we've faced challenges during the ramp process, particularly with achieving full entitlement and throughput, the factory in Alabama is currently performing at a good level and meeting its throughput requirements. We did encounter an issue with our glass supply chain that negatively impacted operations. In Louisiana, things are progressing very well as we work through product qualification, expected to be completed in Q4, with shipments starting soon. The ramp there is ahead of schedule, which is promising. We are diligently maintaining high product quality, focusing on field performance through both accelerated life testing and actual field deployment. Our attention to detail in manufacturing will intensify with the launch of Series 7. Both Alabama and Louisiana are replicating the factories where we rolled out our Series 7 technology, and we've already integrated the key learnings and necessary changes to our manufacturing process. We recognize that maintaining our brand reputation is crucial, and we are committed to meeting our customers' expectations.

Operator, Operator

The next question comes from Vikram Bagri from Citi.

Vikram Bagri, Analyst

Just a quick question. Mark, can you remind us 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?

Mark Widmar, CEO

Yes. I don't have my general counsel here right now to ask that question, but I can share that we are working with outside counsel. We believe we have strong contracts that outline the rights and obligations of both parties, and if either party defaults, there are consequences. While I can't cite specific legal precedents at this moment, I can point out that over the past couple of years, we have had terminations totaling more than $200 million, around $250 million. Additionally, we have about $70 million outstanding, which means that most of those terminations were resolved because the counterparties recognized their obligations and the terms of the agreements, which are consistent across our contracts. They honored their obligations and made payments, indicating that they believed they had a duty to fulfill their contractual responsibilities. We base our confidence on our experience and the advice from outside counsel regarding our contracts. We feel assured about the structure and enforceability of these contracts. My understanding is that the litigation is filed in New York, where the courts have taken a strong stance on contractual conditions regarding defaults and termination payments. Generally, New York courts have favored plaintiffs in similar situations. That's the extent of the information I have, but I believe we are in a solid position.

Operator, Operator

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

Joseph Osha, Analyst

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?

Mark Widmar, CEO

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 would 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.

Operator, Operator

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.