Good afternoon, everyone, and welcome to First Solar's Fourth Quarter and Full Year 2019 Earnings and 2020 Guidance Call. This call is being webcast live on the Investors section of First Solar's website at investor.firstsolar.com. At this time all participants are in a listen-only mode. As a reminder, today's call is being recorded. I would now like to turn the call over to Mitch Ennis from First Solar Investor Relations. Mr. Ennis, you may begin.

Thank you. Good afternoon, everyone, and thank you for joining us. Today, the Company issued press releases announcing its fourth quarter and full year 2019 financial results, as well as guidance for 2020. A copy of the press releases and associated presentation are available on First Solar's website at investor.firstsolar.com. With me today are Mark Widmar, Chief Executive Officer; and Alex Bradley, Chief Financial Officer. Mark will begin by providing a business and technology update and Alex will discuss our financial results for the quarter and full year 2019. Following these remarks, Mark will provide a business and strategy update for 2020, Alex will then discuss the 2020 financial outlook. Following their remarks, we'll open the call for questions. Most of the financial numbers reported and discussed on today's call are based on U.S. Generally Accepted Accounting Principles. And in the few cases, we report a non-GAAP measure, such as non-GAAP EPS we have reconciled this non-GAAP measure to the corresponding GAAP measure at the back of our presentation. Please note, this call will include forward-looking statements that involve risks and uncertainties that could cause actual results to differ materially from management's current expectations. We encourage you to view the Safe Harbor statements contained in today's press releases and presentation for more complete description. It is now my pleasure to introduce Mark Widmar, Chief Executive Officer. Mark?

Thank you, Mitch. Good afternoon. And thank you for joining us today. I would like to start by addressing our loss per share results for 2019, which was a $1.09 on a GAAP basis, with earnings per share of a $1.48 on a non-GAAP basis adjusted for litigation losses. We are disappointed with the outcome, which came in below our EPS guidance range. While Alex will provide a more comprehensive overview, I want to highlight several items that had material impact on this result. Firstly, as initially disclosed on January 6, we entered into a Memorandum of Understanding to settle the previously disclosed action litigation, which was originally filed in 2012. Earlier this week, we disclosed that we entered into a settlement agreement that is consistent with the MOU. As part of this agreement, which is subject to court approval, we agreed to pay a total of $350 million to resolve the claims asserted by the class action. The settlement agreement does not contain any admission of liability, wrongdoing or responsibility by First Solar. While we are confident in facts and merits of our position, we believe it was prudent to end this protracted and uncertain class action litigation process and focus on driving the business forward. As a reminder, the settlement agreement does not resolve any of the claims asserted in the opt-out action against us or the derivative action. Secondly, challenges related to our systems business over the last few months have had significant impact with respect to revenue and gross margin. These challenges relate to both project sale and completion timing, as well as higher expected cost due to adverse weather impact. Alex will provide more detail on the impact of these challenges to 2019 results. Despite the EPS result and in the year continued intense competitive…

Thanks, Mark. Before reviewing the financials for the quarter and full year in detail I’m going to provide some context around the factors which led to the 2019 year-end results falling below our guidance ranges. Firstly, in early January, we settled our class action lawsuit for $350 million. As noted earlier, this settlement remains subject to approval of the court. Additionally, we accrued $13 million of estimated losses relating to the separate opt-out case. This represents our best estimate of the lower bound of the costs to resolve this case. These litigation losses were recorded as operating expenses in the fourth quarter of 2019. Secondly, with respect to our international systems business, we did not complete the sales of our Ishikawa, Miyagi and Hanamizu projects in Japan. At the time of our last earnings call, we were still evaluating the impact of the then recent Typhoon Hagibis, which passed near to our Miyagi project. We've since completed our analysis of the impact which shows limited damage to the project site itself and which is largely expected to be covered by insurance. However, the road along which the gen power line is designed to run was seriously damaged which prevented the project sale in 2019 and also impacted the restructuring and timing of the private fund vehicle, which is expected to acquire all three assets. In addition, the sale of approximately 40 megawatts of assets in India, included in our guidance for the year did not close. With respect to our U.S. systems business in Q4 we completed the sale of 150 megawatt Sun Stream's 1, 100 megawatt Sunshine Valley and 20 megawatt Windhub A projects. All three projects, which are being constructed by First Solar EPC achieved substantial completion in December of 2019. During the quarter, we also completed the…

Thank you, Alex. Thank you, Alex. Turning to Slide 12, I want to start by highlighting the strong market opportunity in front of us. In the next five years alone as reflected in the graph to the left, the amount of PV capacity installed globally is expected to double. As shown on the graph on the right, PV in many markets is competitive with all major forms of fossil fuel generation. Market momentum for PV continues to build. Our Series 6 technology, product road map and market-leading research and development are all key differentiators, which we believe will enable us to meaningfully participate in this wave of demand for clean and affordable energy. Within this context of the overall market, Slide 13 provides an updated view of our global potential bookings opportunity, which now totaled 18.1 gigawatts of opportunities. This includes 9.8 gigawatts in 2020 and 2021, with the remainder 8.3 gigawatts for deliveries in 2022 and beyond. In terms of segment mix, the pipeline of opportunities includes approximately 15.4 gigawatts of module sales, with the remaining 2.7 gigawatts representing potential systems business. In terms of geographical breakdown, North America remains the region with the largest number of opportunities at 14.8 gigawatts. Europe represents 2.4 gigawatts, with the remainder in other geographies. A subset of this opportunity set is our mid to late stage bookings opportunities of 8.2 gigawatts, which reflect those opportunities we feel could book within the next 12 months. This subset is approximately 72% module only, 70% North America base, with 43% of the deliveries anticipated in 2022 and beyond. This opportunity set combined with our contracted backlog gives us confidence as we scale our manufacturing capacity. Turning to Slide 14. With the addition of our second Perrysburg factory during the fourth quarter of 2019, we exited…

Thanks, Mark. Turning to Slide 21. I'll begin by discussing the assumptions included in our 2020 guidance. Given the uncertainty around any outcome from the evaluation of strategic options for our development business our 2020 guidance assumes no change to existing lines of business. Starting with production, our Series 6 volume is expected to increase to 5.7 gigawatts with an additional 300 megawatts of Series 4 prior to shutting down our remaining Series 4 capacity in the second quarter. As a result of this transition, we expect to incur approximately $20 million of severance decommissioning and other shutdown costs in 2020. 2020 volume sold was expected to be 5.7 to 5.9 gigawatts. As a reminder in 2019, we structured our Cove Mountain and Muscle Shoals and Little Bear projects as sale of their project entity with an upfront development fees and then associated module supply agreements. In 2020, we expect to continue to structure U.S. assets under - sales under a similar structure, including the sale of our American Kings and Sun Streams 2 assets. Optimize for our new approach to EPC execution the structure will have the effect of moving approximately 900 megawatts of sales from our System segment to the Module segment. The mix of 2020 net sales is anticipated to be approximately 70% module and 30% systems. Included in the systems net sales in the United States is the residual revenue recognition associated with the GA Solar 4, Sun Streams 1, Sunshine Valley, Seabrook and Windhub A projects. Additionally, our guidance includes the sale of our Ishikawa and Hanamizu assets in Japan, which may be sold together or individually. Due to the uncertainty relating to the cost and timing of the construction of the Gen 5, we had excluded Miyagi from our 2020 guidance. Our ongoing Series…

[Operator Instructions] Your first question comes from Philip Shen with Roth Capital Partners. Your line is open.

Hey, guys. Thanks for the questions. The first one is on your definition of mid-term. Was wondering, if you could provide a little bit more detail on that. Mark, I think you mentioned that the lead line with copper replacement technology would be starting in back half of '21. So is that kind of mid term target, a back half '21 or early '22 type time frame? And then, as it relates to the systems business, was wondering, if you could walk us through kind of how we should be modeling going forward? Historically, you guys have talked about a gigawatt of system sales per year. I think that's probably what's baked in everybody's model. Should we start to feather that back or just remove that completely? Any thoughts on that would be great. Thanks, Mark.

Yes. So on the mid term. So if you think about the CuRe program, we'll start the initial production, our lead line in the second half of 2021 and then start to see it really realized across the entire fleet in 2022. So if you think about even that, let's say the 2022, we originally have sort of set the mid term goal in '17 or so. So it also gives you some indication of a horizon, which we may be looking towards for the 500 watt module that we dedicated as well. But we're very obviously pleased with the launch of our copper replacement program and we're also - to couple that with where our backlog position is right now, it really hits the window where we wanted to hit, is the window we need to sell through into in '22 and '23. You should look to the majority of that volume in that window. We'll be able to have our copper replacement program out there and competitively pricing into the marketplace and capturing the full value of the energy yield that we would realize from that. The systems business, Alex can give you some insight around modules, but what I want to make sure is clear as well is we have committed to a safe harbor investment and we've talked about that. We've got the capability of safe jarboring couple of gigawatts. We have a mid to late stage pipeline of close to 2 gigawatts here in the U.S. of opportunities that we're actively engaging in. We have purposely looked to try to monetize those projects into a 2022, 2023 window. It also somewhat ties in nicely to where the 201 tariffs start to wind down plus your value of your safe harbor investment is most accretive in…

Yeah. So the only thing I’ll add to that is on the near term, so in the guidance, we said about 70% of the revenue line is going to be on the module, about 30% on the systems, that reflects only a pretty small portion. So there's only somewhere around 300 to 400 megawatts going through that line. However, as I mentioned in the remarks, I want to make sure it’s clear, in the last year or so, we've been structuring deals differently as we've been looking at our EPC capabilities and looking to exit our internal EPC and going to the third-party model. And so what we've done is we've changed how we sell projects to selling a project SPV or entity and then enter into a module sale agreement. And if you look at all the deals we've done with over the last year, the impact that means there is about 900 megawatts of volume that is going to go through the Module segment this year, that had it not been for that new change in structure, would have gone through the Systems segment. So we've historically guided to somewhere around 1 gigawatt a year of volume. If you look at this year, you're going to be somewhere around 1.2, 1.3, 1.4 gigawatts of volume generated by the systems business, all right? That volume was originated through the systems channel, although you're not going to see it flow through the Systems segment this year based on those deal structures. But I think in the long term, for modeling purposes, stick to that roughly 1 gigawatt a year of systems business that we've guided to, absent any changes that we guided to later in the year, pending the outcome of our discussions in the market around the systems business.

Your next question comes from Brian Lee with Goldman Sachs. Your line is open.

Hey, guys. Thanks for taking the questions. I had two here. First, if I look at the module gross margin for Q4 here exiting 2019% at 24%, you assume flattish ASPs, which I think you mentioned on the call and a 10% cost decline for 2020. It seems to imply gross margins for modules in 2020 will be high 20% or so, 28% let's say. First, is that the right read here? And I guess, that's also assuming no mix shift impact from Series 6 either, given 2020 will be almost all Series 6 and you still had a meaningful amount of Series 4 in Q4, but will be curious if you could provide some color around the module margins this year? And then just secondly, on the strategic review for the systems business, just trying to understand the thought process here, what is -- is taking a partner potentially if that's an option or outcome of this review? Does that lower the OpEx? Can you give us some sense of how much of your OpEx is tied to that segment versus modules? And then, if you just end up divesting this segment in one transaction, what would be the motivation of that versus simply slowing down the systems over the course of the next few years implied in the pipeline COD dates? Thanks.

Yeah, Brian. I'll give you a little bit of color on the gross margin. So we haven't broken out by module and system, but you can see in the guidance, we are guiding to a 26% to 27% on a consolidated basis. You're right that there is limited reduction on the ASP side as we go from '19 into '20, although we are seeing some - we are seeing a cost per watt drag largely associated with Perrysburg. So we talked about ending the year about $0.005 [ph] higher than our expectations on a fleetwide basis, largely driven by cost per watt at Perrysburg. If you think about the mix shift, although we get some benefit from moving Series 4 to Series 6, as we ramp Perrysburg 2 this year on a mix basis, we're going to have more relative volume coming from our higher cost factories than we did last year. So that drag now across the fleet is going to be around $0.01 cost per watt in 2020. On the system side, we've got lower volume, hence you're seeing lower revenue on the - in revenue line, but on the margin side, there is three other things I'd point to that are dragging down consolidated gross margin through the year. You've got start-up and ramp costs, which is coming in and about $60 million to $79 million coming through, and that's associated with bringing Perrysburg 2 up and Malaysia 2. So you've got a pretty significant track there. We've also got about $20 million of shutdown cost associated with closing the Series 4 factory in Malaysia and you're going to see that coming through the gross margin line as well. And then, finally, about $10 million of severance cost. So as you look through the gross margin line this year, just bear in mind, you've got somewhere close to $100 million relative to that 2.8-ish [ph] point of revenue line that's impacting gross margin on a negative basis.

Yea, but I think when you normalize for those items that are impacting the Module segment, Brian, I mean, you're going to get to a number that's in the range that you referenced from that standpoint. The systems business, first off, as we think about - the way I look at this is that there is the market need and then there is internal capabilities. And we have to understand, given the market needs, how do we best address that and then what's the most efficient way and OpEx way of doing that. And to sort of replicate or to invest in certain capabilities, let's say the power trading capability as an example, right. I don't know, if we want to step into that space. And so to me, a partnership can bring a lot of value to us in the fact that we can create a complementary offer. We've got a great development team with great development sites, interconnection positions and capability with safe harbor that we made the investment in. The real question is, how do you monetize that and capture the optimal value with it. And for me, it's rather instead of internally create something that maybe is externally already in the marketplace and is already performing well, it makes more sense from my standpoint to say how do we engage with those types of partners and then create a synergistic impact versus trying to invest heavily and create maybe not as strong market capability we would with - otherwise with the partnership. So that's kind of the motivation. As it relates to the OpEx, look, there is a meaningful mark - a portion of OpEx that - it not only resonates with just the direct, let's say, the customer-facing team from development, but it's my project…

Your next question comes from Paul Coster with JPMorgan. Your line is open.

Yeah. Thanks for taking my question. It looks like something in the region of $1 of the shortfall in the fourth quarter was attributable to Japan, India, et cetera. How much of that $1 approximately carries over into 2020?

Yeah, Paul. So if I look at...

The Japan business, sorry.

Yeah. So if I look at it, you've got about $1 shortfall, about $0.70 of that is related to timing. So you've got Japan, India, U.S. projects and U.S. module. But there's also another, call it, roughly $30 million of true cost increases. So impacts from U.S. project, weather issues. We had an accrual change relating to this deal with a customer. We have some severance and other miscellaneous costs. So if I look at those, you've got, call it, $0.70 of the roughly $1 is associated with timing versus true cost impact. When I roll that forward into 2020, about $0.50 of that is going to roll into 2020. So the breakdown there is, in Japan, two of the three assets are being pushed into 2020. Our Miyagi asset, however, is not just based on where we see the timing of construction and the Gen 5 today. Now, if that changes that could get pulled in later, but as of now, that's not in the guidance for 2020. The other pieces that previously we'd assumed the structuring of our Japan assets will go through this private fund that I mentioned in the prepared remarks, based on pulling the Miyagi asset out and the complexity we've have seen, I think we're targeting now selling those assets on a bilateral basis versus in a fund with a small impact to that. So that $0.50 to Japan, you are going to pull about $0.35 through. The other timing piece, you're going to pull about $0.15 of the $0.20, that's a function of - in the U.S., although we hit substantial completion on the projects that we were targeting by year-end, we had some small cost increases to do so, as well as the fact that on the India assets, we just had some diminishing value, as we've been negotiating those sale contracts. So if you look at it, you can assume about $0.50 gets rolled 2019 to 2020.

Your next question comes from Ben Kallo with Baird. Your line is open.

Hi, guys. So I guess, could you talk about like your low cash balance point, what do you think it is with all your CapEx? And then my second question is just on, I guess, we're all trying to figure out like cost per watt, we're using $0.21 or something like that and how off are we on the mark there going forward? Thanks.

Yeah. So on -- Ben, on cash, so you've got two big things this year, you've got the remainder of the Series 6 CapEx, so we talked originally about $2 billion of capital associated with what was then 6.6 gigawatts of capacity. So we are largely through that about 250 of the midpoint $500 guidance announced for the year is the finalization of that initial capacity. Of the remaining, there's about $100 million that is associated with increasing Perrysburg's capacity and that takes us from the current $1.9 billion up to the long term run rate by year-end 2021 of about $2.4 billion. So that extra $100 million is getting you about 0.5 gigawatt of capacity. And then in the year, there's about another $150 million, which is other miscellaneous capacity expansion plus other spend. So if you think about that by the end of this year, we're largely through, not only the initial CapEx program, but a lot of the CapEx that is going to take us through the increasing capacity that we showed on the slide that takes us up to a nameplate of 8 gigawatts by the end of 2021. The other piece that you have got to remember is, you're starting the year out by immediately pulling $350 million of cash out when we settled the class action lawsuit. So when you think about the low point, this should be the low point we think by the end of the year. If you look at anticipated CapEx going beyond assuming no incremental greenfield or brownfield expansion that isn't counted in these numbers today, we should be at a high point spend. We are through a lot of our CapEx by the end of the year and we should start to build cash thereafter.

Yeah, I think, the thing about this, Ben, when you go into, especially in 2021 CapEx, burn rate is down significantly and then you've got, as we show in the production plan, supply plan that we anticipated to have about 2 gigawatts of incremental shipment in 2021, so you've got 5, 7 relative to a high end of 7, 7 in 2021. So that is going to drive incremental - significant incremental cash flows because that contribution margin largely is going to flow through to cash. As it relates to cost per watt, Ben, look I think the - we haven't given a discrete number, but there is many numbers that are right around that range and those are numbers that we, as said before that we're comfortable with and we've got a near-term issue, we're still working through with Perrysburg and got headwind against the fleet, which I highlighted in our remarks of about $0.01 and we expect it to work that out over time, but not in 2021 and we've got actually into 2020, but we've got ramp-related costs and other things that are flowing through and severance as we make the commissioning costs and other things like that are starting to flow through the results for 2020. But the other thing I want to make sure, that we don't miss is that we have many levers to go, let's use your leaping off point just as an example. The levers on which we can continue to drive cost down are significant and highlighted in the slide that we showed in the - during the call. Just the increase, today we're at an average of 435 type number, slightly lower than 435 and if we take that up to 500 that's tremendous increase in watts, which largely is scale correlates specifically to a reduction in cost per watt throughput that we have, the team has done a tremendous job of putting forth a road map that can take our original nameplate capacity of a factory and increase it by a third, that's another significant lever. So I think, there is a near-term issue that we're dealing with, but when we look across the horizon and where we can ultimately go from a cost and performance standpoint of our product, we're extremely happy with where we are and what the potential is in front us.

Your next question comes from Michael Weinstein with Credit Suisse. Your line is open.

Hi, guys. Hey, on Slide 18, is it your intention to show that costs are coming down about half of where they - half of the starting point? Is that diagram for scale or is that non-intentional?

No. Mike, if you - it may not be clear, but you look at the footnote there, it says, not to scale. So that's non-entity.

Okay. I mean is there any particular reason why you don't give an exact number? Is it competitive reason for something or is there some other reason?

Yes. It's exactly right. So look, we are out selling the value of the product, right? So if you look at - I'll give you an example. If you look at our 2.6 gigawatts kind of gross basis that we booked within the quarter, the average ASP across that 2.6, which includes volume that goes out into '22 and '23 is slightly down from the average that we reported in the last Q, which I think if you do the math on the last Q was somewhere around $0.34 or something like that. We're selling through out into an horizon that's '22 and '23 and we're still holding very strong ASPs. And the value of CuRe hasn't been captured in that horizon yet. So we have -- our contractual structure as we go that far out will allow us to capture the value of the energy that the product can ultimately deliver on a long term degradation benefit, temporary coefficient benefit, spectral response efficiency, everything. So it all can accrete value, as we move forward. If we were to provide a discrete costs that gave you a number that's out into '21, '22 and '23, then my customer starts to hold me accountable to a cost-plus model. And that's not what we want to do, we want to be out there selling the full entitlement of the value that we create and not get stuck on a cost plus. And so we have purposely moved away from giving discrete cost per watt. There is - if you or adapt that modeling, you can easily take the inputs that we've given to give you is an indication. There is room still to go as we move forward and I think that's really what's most important. As you think through the window this business is going to continue to scale, we're going to maintain and hold a relatively tight fixed cost structure and we'll leverage that and drive incremental operating margin, right. And that's what we've been saying since day one. And the more transparent I am with our cost number the more vulnerable I am to really realize the full potential of the business model that we've created and the technology and we want to capture the value of that technology.

Your next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch. Your line is open.

Hey, can you hear me?

Yeah.

Excellent. Hey guys, just wanted to talk a little bit about the systems business again, sort of status quo, as the independent of monetization here, what systems volumes are we talking about nominal terms, I know the things are moving around here, you recognized in 2020 and then on an ongoing basis, as you think about the size and scale of your operations today. Again, this is also with the thought process of what is this business worth in the monetization scenario? As we think through these peak systems years coming up here as you guys have previously talked about hedging upwards that gigawatt size number in terms of annual systems business, where does that stand now '20, '21, and sort of go forward if you will?

Yeah. Julien, so we previously guided to 1 gig and sometimes up to 1.5 gig and that 1.5 gig a year was also partly EPC project. So as we've now moved away from internal EPC to a third-party execution model, the best we can give you is to anchor around that gigawatt a year of volume. As I mentioned in 2020, you are not going to see that relatively flow through the Systems segment, just given how we structured some of these deals. So the same volume as that was approximately originated through the Systems segment through that channel, but on the accounting side, by virtue of how we structure those deals, you're going to see that mostly flow through the Module segment in 2020. But absent any change to -- any strategic change here that we've been discussing, continue to model around that gigawatt a year. The other thing I'd say is, as you go further out, we have safe harbor 2 gigawatts of capacity, we would like to try and use that out in more in '22 and 2023. That was largely sold through a lot of our capacity in the near term and we've done so capturing full value entitlement for the module. So we've been able to do that without losing much money relative to a system sale, but without taking the risk of those systems deal. So I think from a relative risk perspective, we've captured full value in the next couple of years. We think if you look through into 2022 and 2023, when the relative delta between a safe harbor 30% ITC project relative to going down than towards China is great. So that's when we're looking to deploy that product. And so in terms of value, the significant value creation now in '22 and '23.

Your next question comes from Moses Sutton with Barclays. Your line is open.

Thanks for taking my question. For the systems business, assuming you find a partner that, let's say, solves the basis and related risks, how might cost need to come down, the core cost itself, given you're moving to third-party EPC to let's say allow you to bid at PPA prices of $30 a megawatt hour, while still maintaining say around the 20% margin as a developer?

Cost, as it relates to our own development cost to achieve that margin, first up, I don't -- I never -- given where we are right now and where PPA prices or module prices or anythings move toward, I'm not sure that a margin percent is always necessarily the best way to look at it, partly because the development revenue stream number from a sense perspective is relatively low. I would actually like to ensure that we can capture at least 30% to 40% margin on our development activities in order to say that it's sustainable and a position that we want to maintain, because you have to look at the risk profile that you're taking, I mean, every time - and this is why our preference is to do more EOG and that's what we're trying to position ourselves. Every time there is a change in emerging curve that gets published every six months, there is a risk that you're taking, because you did a of merchant curve two years ago, a year ago, whatever it is, that every time that gets updated, especially with shorter tenure PPAs, I've got a risk for every time a merchant curve moves one way or the other. And so we prefer to try to find long tenure of PPAs, we also prefer to look to EOG which I just have to worry about either providing a site with a module agreement or building a power plant and transferring that to the long-term owner, but there's others that are willing to take those other types of risk and it's the risk they're comfortable with taking and we just would like to see if there is a path out there that we could partner with someone that is comfortable with those risks and has…

That is all the time we have for questions. This concludes this conference call. You may now disconnect.