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First Solar, Inc. (NASDAQ:FSLR)

December 14, 2011 8:00 am ET

Executives

Michael J. Ahearn - Chairman and Interim Chief Executive Officer

David Brady - Vice President of Treasury & Investor Relations

Mark R. Widmar - Chief Financial Officer

Analysts

Stephen Chin - UBS Investment Bank, Research Division

Timothy M. Arcuri - Citigroup Inc, Research Division

Smittipon Srethapramote - Morgan Stanley, Research Division

Mehdi Hosseini - Susquehanna Financial Group, LLLP, Research Division

Paul Clegg - Mizuho Securities USA Inc., Research Division

Satya Kumar - Crédit Suisse AG, Research Division

Daniel Ries - Collins Stewart LLC, Research Division

Amir Rozwadowski - Barclays Capital, Research Division

Sanjay Shrestha - Lazard Capital Markets LLC, Research Division

Vishal Shah - Deutsche Bank AG, Research Division

Operator

Good day, everyone, and welcome to First Solar's 2012 Guidance Conference Call. This call is being webcast live on the Investors section of the First Solar's website at www.firstsolar.com. [Operator Instructions] As a reminder, today's call is being recorded. I would now like to turn the call over to David Brady, Vice President and Investor Relations for First Solar, Inc. Mr. Brady, you may begin.

David Brady

Good morning, everyone, and thank you for joining us for First Solar's 2012 Guidance Call. This morning, the company issued a press release announcing its guidance for 2012. If you do not receive a copy of this press release, you can obtain one from the Investors section of First Solar's website at www.firstsolar.com. In addition, we have posted the presentation for this guidance call on our Investor Relations website. An audio replay of the call will also be available approximately 2 hours after its conclusion. The audio replay will remain available until Sunday, December 18, 2011, at 11:59 p.m. Eastern Standard Time and can be accessed by dialing (888) 203-1112 if you're calling from within the United States, or (719) 457-0820 if you're calling from outside the United States, and entering the replay passcode 7459995. A replay of the webcast will be available on the Investors section of the company's website approximately 2 hours after the conclusion of the call and will remain available for approximately 90 calendar days. If you are subscriber of FactSet or Thomson One, you can obtain a written transcript.

With me today are Mike Ahearn, Chairman of the Board and Interim Chief Executive Officer; and Mark Widmar, Chief Financial Officer. Mike will provide a background on current market conditions and lay out our strategy to pursue our goal of creating sustainable markets that will drive the future of Solar. Mark will then update 2011 guidance and provide a 2012 guidance and its assumptions. He will also update our long-term roadmaps for marginal manufacturing costs, module efficiency and Balance of Systems costs, and provide an overview on our outlook for operating expenses. During the Q&A period, as a courtesy to those individuals seeking to ask questions, we ask that participants limit themselves to one question.

First Solar has allocated approximately 1 hour for today's call. All financial numbers reported and discussed on today's call are based on U.S. Generally Accepted Accounting Principles, except free cash flow, which is a non-GAAP measure and is reconciled to operating cash flow in the back of our presentation.

Now I'd like to make a brief statement regarding forward-looking remarks that you may hear on today's call. During the course of this call, the company will make projections and other comments about forward-looking statements within the meaning of the Federal Securities Laws. The forward-looking statements in this call are based on current information and expectations, are subject to uncertainties and changes in circumstances and do not constitute guarantees of future performance. Those statements involve a number of factors that could cause actual results to differ materially from those statements, including the risks as described in the company's most recent annual report on Form 10-K and other filings within the Securities and Exchange Commission. First Solar assumes no obligation to update any forward-looking information contained on this call or with respect to the announcements described herein.

It is now my pleasure to introduce Mike Ahearn, Chairman of the Board and Interim Chief Executive Officer of First Solar. Mike?

Michael J. Ahearn

Thanks, David. During the past several weeks, we've been busy developing the strategic framework for First Solar's future, in addition to preparing the 2012 operating plan that Mark will discuss with you. And today I'd like to share this strategy with you. During the first quarter of 2012, we will also share with you a 3-year transformation plan to implement the strategy.

If you turn to Slide 5 with regard to the strategic framework. The first thing we did was look objectively at the realities of the industry and the marketplace, starting with production capacity and volumes. Global production has effectively tripled over the last 3 years, as you know. Two factors have enabled this to occur. First, entry barriers from manufacturing polysilicon wafers and cells evaporated several years ago when equipment suppliers effectively integrated process technology into turnkey production equipment. This enabled relatively inexperienced and unskilled operators to quickly enter the supply chain, and led to an explosion of production capacity in China and elsewhere. Second, silicon feedstock constraints, which we began around 2004, were alleviated in recent years as additional feedstock capacity was brought online by both incumbent and new suppliers. Feedstock availability brought down prices and enabled higher utilization rates for the name production capacity already in place.

The essential point is that the polysilicon supply chain has undergone a fundamental structural change. This is not a cyclical or seasonal phenomena. In a supply chain without structural entry barriers, several things occur. First, production volumes increase so long as capital is available to fund it, and we've seen over the past several years that U.S. equity markets and, more recently, Chinese governmental entities have been willing to provide the capital needed to fund a massive production expansion. Second, production volumes eventually exceed demand and pricing declines as manufacturers attempt to sell the excess product compressing margins. Third, prices and margins continue to decline until the financing eventually stops and only the most resilient producers remain in operation. And fourth, the supply-and-demand equilibrium that is eventually achieved is only temporary. Excess production resumes when capital again becomes available to fund it. And this last point is important. In an industry without entry barriers, which we believe in our case for polysilicon PV module industry, the easy reentry of competitors and expansion of capacity will keep downward pressure on prices and margins indefinitely.

As the supply side of the picture, if you turn to Slide 6, we'll discuss the demand side, which we refer to as installation capacity because the subsidized solar markets in which the industry operates are, in effect, limited in their solar installation capacities by the size of their subsidy programs. And we've all seen industry forecast that predict volumes well into the future by assuming that existing demand levels will continue, more or less at current states ,and projecting various growth rates off of the existing demand block.

The next few slides look beneath the aggregate historical sales figures to provide an alternative paradigm that we believe more accurately describes the future of subsidized solar markets. Historically, 80% or so of the industry's annual sales came from the few countries with open transparent subsidy programs. These markets, which we refer to as core markets, exclude Japan, off-grid installations and various small fragmented markets. We plotted the annual installations in the core markets from inception, and I'd like to quickly review some of the results.

Slide 7. Spain peaked at over 2.6 gigawatts in 2008, at which time the government took action to sharply reduce the program.

Slide 8. The Czech Republic peaked at around 1.5 gigawatts in 2010, at which time the government took action to sharply reduce the program.

Slide 9. France peaked at 1.5 gigawatts in 2011, at which time the government took action to reduce the program to 500 megawatts, with 2012 being a transition year.

Slide 10. Italy was flat in 2011, but we expect it to decline moving forward, based on government action to reduce the program.

Slide 11. Germany peaked at about 7.4 gigawatts in 2010 and we expect 2011 to total around 5.4 gigawatts as a result of government action to reduce the program.

Slide 12. In California, much of the volume growth projected by analysts is attributable to power purchase agreements, or PPAs, that are already in place. A better sense of future growth can be gleaned by understanding the volume of solicitations from new PPAs. On this slide, you can see that new PPA solicitations peaked for the solicitation year of 2008. This high level of solicitations led to a record level of PPA filings and approvals in 2010 and '11 due to the delay between solicitation year and actual execution. As you know, First Solar is associated with a number of the approved PPAs, which is providing us with a high level of visibility in our Systems business over the next couple of years. However, the rate of new PPA procurement of major California independently-owned utilities is slowing as they edge closer to fulfilling their RPS requirements, and that's reflected on this slide. We do not expect the volumes of new PPA solicitations to approach or repeat the 2008 peak following significant legislative change, which we do not see on the horizon.

Slide 13. The next slide shows a similar pattern for the California small distributed PPA program.

And finally, Slide 14, which shows the aggregate pattern from the core markets.

So the question we raised on Slide 15 is: What explains this consistent inverted V pattern? And we believe the European subsidized markets started slowing while legislation was translated into effective programs and bureaucracy to streamline. And once the markets begin to function effectively, the incentive programs caused an oversupplied industry to descend rapidly and develop project backlogs. The unexpected size and velocity of market expansion, combined with high import volumes, alarm politicians. Worried about high costs and political fallout, politicians reacted by sharply reducing the size of programs, and in some cases, making them less transparent or open to imports. While California follows the same pattern, same inverted V pattern as the European feed-in tariff countries, it does so for a different reason. The California market was capped from the beginning by the RPS, first at 20%, then at 33%. Utilities demand increased sharply as they sought to procure more renewables to meet their regulatory targets, and then decline once regulatory targets were more or less achieved.

So turning to Slide 16. The central learning from this experience is that open, transparent and uncapped markets cannot survive politically in an oversupplied industry with no entry barriers. Policymakers will learn from the past and are unlikely to repeat the policies that led to the inverted V patterns we just reviewed. And although there have not been many new subsidy programs in the past few years, the new programs that have come online have, in fact, been restricted to low volumes and, in some cases, made less open through local content requirements, or less transparent through tendering processes. RPS markets like California, which are another form of subsidy program, are perhaps less volatile but reach the same result because demand is capped by the size of the program and eventually exceeded by an unlimited supply chain.

Well, so turning to Slide 17. In summary, the solar industry is structurally imbalanced. Production capacity is uncapped and growing. Installation capacity is limited by subsidy levels and declining. We believe large, open, transparent markets that enable the industry to achieve the current annual volumes are shrinking, and that that these programs will not be replaced by similar programs in the future.

So turning to Slide 18, that brings us to First Solar's strategy. Our low-cost technology and captive U.S. project pipeline will help us remain profitable in a shrinking, structurally imbalanced industry, although we clearly face challenges in this environment, as Mark will describe. But our goal at First Solar has always been to drive. And to do that, we must find a way to grow dramatically, notwithstanding a challenging environment. And just to throw out an example, to grow at a 20% CAGR would require that we install roughly 65 gigawatts over the next 10 years.

So the external environment presents First Solar with a fundamental choice, either continue to play what we've been referring to internally as the "whack-a-mole" game, where an oversupply supply-chain waits for the next subsidy market to pop up so they quickly descend and battle it out for a share of limited volumes or find another game to play. We've decided to move to another game, which I'll summarize for you now.

Turning to Slide 19. We're shifting our revenue base from subsidies to sustainable markets, starting in 2012. It won't happen overnight and we'll have to transition out of the subsidies we currently depend on, but our goal is to shift progressively over the 2012 to 2014 timeframe so that by Q4 2014, we derive virtually all of our new revenues from sustainable markets. And we intend to make this transformation by providing Utility-scale PV generation to power users in geographic markets with immediate fundamental needs for large scale PV electricity. In essence, we'll be improving and adapting to local market conditions the systems model that has made us the provider of choice for U.S. utility and energy companies, speaking utility-scale solar generation.

But First Solar's uniquely advantaged to expand and lead the global market for utility-scale solar power. With over 2 gigawatts, the First Solar power plants constructed are under construction. turnkey production equipment We have demonstrated our ability to design, engineer and construct large-scale solar power plants to the exacting standards of the utility industry. Our advanced technology, innovative system designs and economies of scale have enabled us to dramatically reduce cost and accelerate construction cycles while increasing output from our utility-scale power plants. Our monitoring and analysis of power plant performance have validated the reliability and uptime of our systems to the high standards of the utility industry. Our ability to take back and recycle our products for reuse at the end of their operating lives and to operate our plants without the need for water or fuel have allowed our customers to harness some life for energy with competitive, environmentally sustainable solutions. And by consistently delivering on our promises and standing behind our commitments, we've earned the trust and business of some of the most respected companies in the electric industry -- utility industry, including APS, Exelon, GE, NextEra, NRG, PG&E, Sempra Energy, Southern California Edison, Southern Company and most recently, MidAmerican.

In summary, we plan to leverage our low-cost Module technology, systems design and engineering capability, data monitoring and analysis capability, strong performance track record and customer validation to expand markets and customers for utility-scale solutions without the need for solar subsidies.

Slide 20 takes you through where we stand in the planning process. Our focus, as I mentioned, will be on Utility-scale Systems. Right now, we're dedicating all of our resources to reducing the total installed cost of a utility-scale power plant, optimizing the design and logistics around the offering and ensuring that it integrates well into the overall electricity ecosystem. In practice, this means that other initiatives we've been pursuing, such as rooftop products and off-grid applications, will be on the back burner. We may come back to them later. Right now, we need to focus all of our efforts and resources where we stand the best chance of creating a valuable, long-term business franchise.

Our team is focused on delivering an optimized system versus a module component. That implies that the system will be built on a standard design platform, optimized for life cycle cost, and will include controls packages that facilitate grid integration and maintenance planning.

I mentioned during the last earnings call that we believe that in addition to the U.S. and Europe, places like the Middle East, India, China and Africa have fundamental energy needs that can be met with solar energy solutions. These markets are all located in regions with very good solar resources that can be harnessed to augment indigenous fuels and minimize import dependence. We are in the process of prioritizing geographic markets as part of the 3-year plan and development. We intend to build a deep local presence in each of our priority markets, and the planning and execution effort has already begun. As I mentioned, we intend to finalize a 3-year plan in early 2012 and we will get back to you to provide additional detail regarding the plan in the first quarter of 2012.

Turning to Slide 21. Transitioning away from the subsidies have put us on an entirely different trajectory from the rest of the industry. The business we're describing will be capable of strong, consistent and profitable growth for decades. We are targeting markets that are underserved and growing on a macro basis at rates of 5% to 10% per annum, and for which renewable energy can serve a disproportionate amount of low growth. But we are not underestimating the difficulties achieving this transition.

There are 3 major hurdles to overcome, which I'd like to briefly describe. First, we cannot even begin to have a serious discussion with policymakers, regulators and utilities about large-scale solar generation until we're prepared to price it on subsidized levels at scale. We believe this translates to a Levelized Cost of Electricity, or LCOE, of $100 to $140 a megawatt hour, or $0.10 to $0.14 a kilowatt hour in most markets. As Mark will discuss, achieving these LCOE levels without subsidies will require that First Solar reduce its manufacturing costs, increase module efficiencies, streamline operating expense and transition its business model to deliver superior returns at much lower gross margins than in the past.

Second, while First Solar's ability to profitably price at grid parity levels is necessary, it may not, in every case, be sufficient to create large sustainable markets. Electricity markets are regulated and planned years in advance. In some cases, policymakers will have to refine their policies to create market environments conducive to large scale adoptions of solar power, including such things as providing priority access to the grid, implementing streamlined permitting and interconnection processes, developing new approaches to land planning, building additional transmission and facilitating regional -- reasonable project capital costs.

Third, a significant amount of our capital, expense and revenue still drives from subsidized markets that are in decline. While we create the future, we will have to manage to the transition in a manner that preserves cash and assures profitability.

Let me close by saying that First Solar's leadership team, associates and Board of Directors are firmly committed to the vision and strategy that I've outlined and prepare to do what is needed to achieve the 3-year goal I've described. We look forward to sharing additional details with you in early 2012, once we've completed our 3-year transformation plan.

Now I'd like to turn the call over to Mark, who will update 2011 guidance, review our 2012 guidance and describe our financial model upon completing the transition I've described. Mark?

Mark R. Widmar

Okay. Thanks, Mike, and good morning. Before we discuss 2012, I'd like to update 2011 guidance. As announced in our 8-K filing this morning, we have undertaken a series of restructuring initiatives intended to accelerate operating cost reduction and improve overall operating efficiency.

In the fourth quarter, we anticipate charges related to these actions to be up to $0.85 per share, which includes up to $0.75 per share for impairment and associated charges primarily related to certain equipment, and up to $0.10 of severance charges as we reduce headcount by approximately 100 positions. Excluding the impact to these charges, we now anticipate 2011 results to be net sales in the range of $2.8 billion to $2.9 billion, operating income in the range of $575 million to $600 million, diluted EPS in the range of $5.75 to $6, operating cash flow in the range of a use of $100 million to net neutral, CapEx in the range of $750 million to $800 million. Anticipated net sales are lower than previous guidance due to weather and project financing related delays in a couple of our system business projects. In addition to the lower net sales, operating income is also adversely impacted by underabsorbed manufacturing costs as we slow Q4 2011 Module production due to a lower-than-anticipated Q1 2012 market demand.

Moving to Slide 24. We will talk about our guidance assumptions for 2012. We've made several key assumptions for our guidance for fiscal 2012. Pricing is fixed for the vast majority of our anticipated systems volumes. For our third party Module sales, we will align pricing to the anticipated 2012 feed-in tariff charges -- changes, excuse me, and to sell-through at a highly competitive market environment. Given the difficulty to project market pricing dynamics, it is important to provide a sensitivity to our assumed third-party module ASP. Assuming a $0.05 decline in 2012 third-party module ASP, then EPS will be negatively impacted by approximately $0.35. We expect to install approximately 1.2 gigawatts of modules via our Systems business, of which approximately 80% is already under contract. Included in this anticipated volume is 175 megawatts for Desert Sunlight, which will not result in revenue being recognized in 2012 under U.S. GAAP requirements as previously mentioned in our 8-K filing.

In our third party business, we expect to ship approximately 720 megawatts of modules. For sensitivity purchase, a 10% reduction in the anticipated 2012 third-party module volume would reduce 2012 EPS by approximately $0.30 and impact operating cash flow by approximately $10 million. We expect to produce 2 gigawatts of modules in 2012, or about 80% of our capacity. We will continue to qualify the Mesa plan in 2012 but we will not -- but we do not expect to start commercial production there until 2013. We will also be taking downtime from manufacturing plant upgrades to support our go-fast efficiency actions and better align production with demand.

We expect module manufacturing costs to average $0.72 per watt in 2012. Our comps will be negatively impacted by plant underutilization. Without this impact, that is, if we were to run our plants at full utilization, our module manufacturing cost would average $0.67 per watt. Note, to support our go-fast efficiency improvement roadmap, we will accelerate the replacement of certain components of our manufacturing equipment. This will require us to reduce the use of life of the equipment and accelerate the depreciation. The impact of this accelerated depreciation is approximately $21 million. When calculating our cost per watt in 2012, we have excluded this expense as we believe it's not reflective of the recurring module production cost. For module efficiency, we expect to average 12.6% in 2012. As we move our business mix away from Europe, the euro-dollar exchange rate is becoming less of a factor in our results, so we are no longer providing the assumptions around currency.

Moving to Slide 25. Based on these assumptions, we expect the following financial performance in fiscal year 2012: Net sales to range from $3.7 billion to $4 billion, which includes around $1.7 billion of EPC sales. We expect plant start-up costs of $10 million to $20 million, primarily related to the qualification of the Mesa plant. Stock-based compensation is estimated at $110 million to $120 million, with approximately $35 million to $40 million associated with our cost of goods sold. Operating income is expected to range from $425 million to $450 million. We expect an effective tax rate to be in the range of 14% to 16%. Earnings per fully diluted share are expected to be in the range of $3.75 to $4.25. Capital expenditures for the year are expected to be $375 million to $425 million, of which approximately $200 million is for capacity expansion and $30 million is related to our go-fast efficiency actions. Operating cash flow is projected in the range of $0.9 billion to $1.1 billion. Improved working capital management in our Systems business, due to a better alignment of our construction scheduled to the underlying contracted milestone payments will benefit 2012 operating cash flows. For Desert Sunlight, we will not recognize revenue in 2012. However, we will receive milestone payments under the contract. The projected 2012 net cash receipts for Desert Sunlight are $85 million. Please note that this is included in our operating cash flow guidance that we provided.

Turning to Slide 26. Slide 26 illustrates how significantly our geographic mix has shifted since 2010. Europe has become the home -- was the home for approximately 80% of our modules sold in 2010 but will consume less than 1/3 of our modules in 2012. North America will take up most of the slack, representing about 60% of the volume in 2012. We are starting to make inroads in India, the Middle East, North Africa and Asia-Pacific, but in 2012, our presence in these markets will be relatively small.

Moving to Slide 27. To achieve our goals, create and develop new markets and change the landscape of the electricity market, we must continue to drive down our costs. The next set of slides discusses our key metrics that affect costs.

Slide 27 shows our module manufacturing costs from 2007 to 2012. For 2012, we break down the data by quarters and show the cost and total without the unfavorable impact of plant underutilization. For 2012, we expect the average cost per watt of $0.72, assuming plant utilization at approximately 80%. If we ran our plants at full capacity, the average cost per watt would be $0.67 or $0.07 below in 2011. On an exit-rate basis, assuming full capacity, we expect the cost per watt to be $0.65 across the global platform and $0.63 at our lowest cost plant. While plant underutilization will affect our short-term results and increase sequential average module cost in the first half of 2012, it is prudent to better align our production with demand. In addition, exercising discipline in production and making plant upgrades will enhance our long-term competitive position.

Moving to Slide 28. Slide 28 shows that our module efficiency is expected to improve meaningfully in 2012, with the exit rate of 12.7%, a full percentage point higher than the average module efficiency in 2011. We expect our module efficiency across our global platform to average 12.6% efficiency in 2012 and our best performing plant to average 12.9% efficiency. We have been able to leverage our learnings from our record NREL Cell Efficiency and started to implement these learnings into production and have quickly seen the benefit. In fact, so far in the month of December, our best performing line is running close to 13% efficiency. This performance helps provide confidence that we can accelerate module efficiency as we implement our go-fast efficiency actions. One point to note, if we're able to increase the module efficiency at our lowest cost of plant up to 13% efficiency, the 2012 exit rate cost per watt for this plant will be approximately $0.60.

Looking at Slide 29. Slide 29 shows that we expect to continue and to make solid gains in reducing Balance of System costs, as these costs will average less than $0.90 per watt in 2012, which is below our previously communicated 2014 goal of $0.91 to $0.98 per watt. Our ability to continue to drive down the module in BoS system cost as a true differentiation of our model and enable our mission to provide a portable solar electricity.

Moving to Slide 30. On Slide 30, we show a profile of our operating expenses over time, including our expectations for 2012. Our operating expenses as a percent of sales have gradually declined over time and we expect this trend to accelerate in 2012 as we reduce operating expenses to around 12% of revenue. We will continue to invest in R&D to drive our efficiency roadmap, as well as sales and marketing to help develop new markets. Reductions in G&A will help fund these investments and improve our overall optic scaling. To enable grid parity, we tend to drive to unsubsidized pricing. We need to create sustainable markets. We will need to reallocate our resources and to take aggressive measures to continue to scale our operating expenses. Longer term, our goal is to reduce operating expenses to 7% to 8% of revenue by 2014.

Looking at our long-term business model, we will provide more detail on our 3-year plan early next year, but Slide 31 shows how we view our long-term sustainable model as we price at levels that drive demand without subsidies. We believe an LCOE of $100 to $140 per megawatt hour will open up most markets. To achieve that requires a module and BoS system price of around $1.40 to $1.60 per watt. This system price does not include other development costs incurred by the system owner, which we assume typically to be around $0.20 and of which, of course, must be factored into the LCOE calculation. For our updated cost structure, we will discuss more on the next slide. The economics updated or equate to a gross margin of around 15% to 20% and an operating margin of around 8% to 12%. Given the capital requirement to invest and operate this model, we estimate that our long-term free cash flow will be around 60% to 80% of net income. This model is based on revenue that is fundamental, certain, visible and sustainable, revenue that we think can consistently grow at 5% to 10% per year. This model is more like an industrial one than a technology one. In our opinion, that is positive. There are compelling reasons for large industrial companies to perform at the levels that they have for the decades. They have helped their customers solve this problem as opposed to feeding off fleeting subsidies. And they are protected by sustainable competitive advantages in terms of scale, global presence, learning curve advantages and returns that add value. This is a model we like and one that we are now implementing.

Turning to Slide 32. In the top left of the slide, we show our new roadmap for module manufacturing costs. In 2015, we expect our cost per watt will be in the range of $0.50 to $0.54, a solid improvement from our prior goal of $0.52 to $0.63 in 2014. The figure on the top right of the slide shows that we expect our module-efficient improvements to accelerate through 2015. Our updated cost for module efficiency -- our updated goal, excuse me, for module efficiency is 14.5% to 15% in 2015, up from our prior goal of 13.5% to 14.5% in 2014.

The most significant improvement in our roadmap is the Balance of Systems, as we show in the bottom left of the slide. We are now targeting a goal of $0.70 to $0.75 per watt in 2015 versus our prior goal of $0.91 to $0.98 in 2014. We have worked hard to improve our manufacturing and EPC process to update these roadmaps and we will continue to do so. We have no choice. We must do so in order to achieve our goals. Along these lines, we will reevaluate all the cost levers in our value chain, including supplier procurement, supplier payment terms, manufacturing efficiency and EPC activities. We are looking to better leverage the capabilities to -- of our partners and customers, and as we discussed earlier, we are streamlining our operating expenses.

As we think about our long-term business model and how we create and penetrate sustainable markets, we believe that our competition will mainly come from electricity generation from fossil fuel plants. That said, we recognize that some of our crystalline solar competitors have significantly reduced their cost structure. The solar industry has become intensely competitive so we thought it would be illustrative to evaluate the cost structure parity between us and the theoretical cost parity targets for crystalline solar competitors in 2015.

The midpoint of our module cost per watt goal in 2015 is $0.52. To evaluate the crystalline silicon cost parity, we will -- we need to increase our cost per watt by the average BoS cost differential due to the module efficiency differences. In addition, we normalized our cost per watt to be consistent with the reporting of the top-tier crystalline competitors. Most of our competitors account for shipping and warranty costs in their operating expenses while we account for it on our cost of goods sold. Based on our analysis, the crystalline silicon cost parity per watt $0.52, and it's $0.57 by 2015. On a percentage reduction basis, the top tier crystalline competitors would have to reduce their cost per watt by approximately 45% from the Q3 2011 reported costs.

In summary, on Slide 34. To summarize, we are accelerating our efforts to create and develop new markets. This entails developing customer-focused, compelling solutions; establishing right price without subsidies to clear existing markets and create new ones; aggressively reducing our cost structure, including to drive down cost roadmaps to grid parity; and reallocating spending; and focusing more on long-term economic value generation.

With this, we've concluded our prepared remarks and open up the call for questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Sanjay Shrestha with Lazard Capital.

Sanjay Shrestha - Lazard Capital Markets LLC, Research Division

Two quick question, guys. I'm just trying to sort of understand. How do you go from operating income of $425 million to $450 million, then operating cash flow of almost $1 billion? So if one were to back into it, it sounds like your cash EPS would've been twice as high as the GAAP EPS guidance you guys are providing. What am I missing there?

Mark R. Widmar

Yes, I think that the biggest -- the delta there is -- one of the things that we've made a decision today and I think we've discussed this in prior conversations is that we're going to build out our EPS pipeline to the constructed contracted schedule, whereas in 2011, we got a little bit ahead of ourselves. We took some risk in some projects and that really drove a much higher working capital requirement for the Systems business than what was required. So in 2012, we'll actually align that. We'll build out those projects in accordance with the contracted, committed construction schedule, and that'll allow much better working capital management. So if you may remember at the end of the third quarter, we had a relatively large unbilled position of around $300 million or so related to one of our large projects. That’s essentially consumption of working capital and cash. Next year, we'll make sure that we align the construction much better to avoid those types of working capital investments, and what we'll see then is a benefit of flowing into '12 will be about $700 million or so working capital reduction primarily related to the System business.

Sanjay Shrestha - Lazard Capital Markets LLC, Research Division

Okay, great. And if I may, just a quick follow-up. Right, so when I'm looking at your 1.2 gigawatt installed solar power system and then look at your sort of the system revenue guidance of $1.7 billion, that sounds like that is really the margin going into the System business but not the entire System business, right? So if you're doing 1.2 gigawatt of Systems business, even on a GAAP basis, given the high profitability associated with the business, EPS number should have probably come in higher than the number you guys are talking about, even on a GAAP basis here?

Mark R. Widmar

Well, the EPS numbers we were reporting are on a GAAP basis. I think, Sanjay, if you're trying to get to the point of -- included in our 1.2 gigawatts installed, there's about 175 megawatts associated with Desert Sunlight, in which, from a GAAP purpose, it will not be recognizing revenue. Yes, the EPS adjusted for that would have been higher. We provided the net cash receipts associated with Desert Sunlight. So to give you some indication, at least on a cash basis, what the impact would be that’s not reflected in our earnings.

Operator

Our next question comes from Stephen Chin with UBS.

Stephen Chin - UBS Investment Bank, Research Division

So just a clarification on the 2012 Systems guidance. Does that assume any revenues from this big Solar Millennium project that's been publicly discussed in the industry? And just another clarification, is First Solar still targeting the high-efficiency rooftop market going forward, given the focus on these sustainable markets?

Michael J. Ahearn

Yes, there is no impact in some of the public disclosures that may have been made as it relates to Solar Millennium that -- none of that is reflected in our 2012 results. As we've indicated, I think that the 1.2 gigawatts, approximately 80% of that is under contract. So high level of confidence associated with that volume in 2012. But we have not assumed any type of project acquisitions or anything related to that, that is not already contracted at this point in time.

Mark R. Widmar

And on the rooftop issue, we've shifted all of our resources to the Utility scale business and really driving system optimization and new market creation. So rooftop is back burnered. We're not going to do anything on that right now. We might come back to that later, but we're going to execute the 3-year plan around the Utility System business.

Operator

Our next question is from Dan Ries with Collins Stewart.

Daniel Ries - Collins Stewart LLC, Research Division

The -- you mentioned that the rooftop effort. There was a story in the Wall Street Journal today that the -- that there have been some departures from the Santa Clara operation. On Slide 30, you show an R&D. And if I eyeball it correctly, the R&D looks like it's consistent with the $38 million per quarter spend that you did in 3Q. Will there be any R&D benefits if things like the rooftop effort in the Santa Clara operation are wound down a bit?

Michael J. Ahearn

Yes, so if you look at -- the actual R&D spend year-on-year will be down slightly. If we would have continued at the same rate of -- if you look at the investment requirement for the activities that were previously being performed in Santa Clara, the R&D spend in 2012 would have been substantially higher. So that number has been brought down now as we repurpose those activities, so that the actual number will show relatively flat year-on-year. However, if we would have continued with the previously performed activities there, we would've seen a significant increase.

Operator

We go next to Satya Kumar with Credit Suisse.

Satya Kumar - Crédit Suisse AG, Research Division

Mike, a couple of things. You talked about how limited entry barriers of large competitors to add capacity aggressively. Can you perhaps opine on what prevents your competitors to follow a similar strategy on the Systems business in the new markets? And what entry barriers might look like? And secondly, the liberty of 1.2 gigawatts of installation targets for 2012. How should we think about -- as you look at your pipeline of activities, to add or subtract to this pipeline, do you expect to take in more than that 1.2 gigawatts in new commitments to the pipeline, contracted commitments versus what you're actually fulfilling?

Michael J. Ahearn

Sure. Well, so to open new markets for non-subsidized solar power, I think the threshold thing that has to occur is you have to be able to price on an installed system basis at $1.40 to $1.60, the range we talked about. We don't think our Chinese competitors can get there directly or indirectly. And I would underscore profitably. It's one thing to sell through existing capacity and recover your cash costs. I think it's another thing to invest billions of dollars in new capacity knowing for a fact you could never make a profit. And so I don't see it. I mean, our cost sensitivity model from the slide Mark took you through assumes cash costs recovery from a silicon perspective where we've got returns in excess of our cost to capital built into ours. So that would start with -- we have a sustainable significant cost advantage at a system level if we can execute our 3-year plan. The second thing is, it's going to take a lot more than a module component to open utility-scale markets. What we found is that these customers, which are essentially risk-averse, reliability-focused electricity generation and system operators, are concerned about installed systems, reliability, the data that verifies reliability, know-how in terms of how this is going to integrate into the grid. And to be able to provide that level of solution and inside, you’ve got to have a vertical model that is proven. And we've invested in that for the last 3 or 4 years and spent the time and money and effort and have the validation. You can't get that or build that easily. In the fullness of time, I mean, could somebody vertically integrate? I suppose so. I'm not sure that would be even be all bad by that point because the real competition, as we shift, is thermal. I think Mark had that right. And we need to focus on that, the road ahead, as opposed to the rearview mirror of these silicon guys.

Satya Kumar - Crédit Suisse AG, Research Division

Pipeline?

Michael J. Ahearn

I'm sorry. Yes -- Satya, you had a question about the pipeline. So I think, if I understood the question, as we construct against our contracted pipeline, that would -- we imagine that it would be replenished at the rate -- at or above the rate that we're constructing, those slides on the California PPA markets seemed to us to provide a pretty good leading indicator as to where the market's going, which is down relative to the '08 solicitation year. So I think it would be very challenging to replenish the pipeline to those levels. That doesn't mean the U.S. won't be a big utility-scale market at some point. But these things go in cycles and procurement patterns, and we had a big procurement cycle driven by the California RPS. We're on the downslope of that cycle. And while we're waiting for another cycle, I think this is going to been opportunistic market. It’d be tough to replenish at those rates.

Operator

We go next to Vishal Shah with Deutsche Bank.

Vishal Shah - Deutsche Bank AG, Research Division

Mike, just one follow-up on that question. I mean, how do you get to that target of sustainable demand by 2014? I mean, it looks like India is the only market that stands out where there's an opportunity, but do you, A, agree that you'll have to maybe acquire some pipelines over there in order to have a comfortable 2014 outlook based on your current planning? And then secondly, how much of an impact do you think low-cost financing plays from Ex-Im Bank? And what do you think the repercussions are for some of the recent disputes between China and U.S. around some of the solar policies?

Michael J. Ahearn

Yes. Actually, I do think there are 5 or 6 -- our team believes, and I agree that there are 5 or 6 geographic markets that can yield significant unsubsidized opportunities. And so part of the work that's happening on this 3-year plan is a bottoms-up end-market planning process and a lot of this continues off of discussions in meetings that have been going on for 12, 18 months now in some of these markets. But I believe what we will show in the 3-year plan is actually several markets that can roll up, assuming things break right, because it can roll up to non-subsidized, sustainable volumes by the end of 2014. There will be uncertainty around that. Part of the uncertainty, I think, you alluded to has to do with project financing. In some markets, I’m sure we're going to find project financing, at least reasonably priced, is going to be an issue. In other markets, it won't be that, but there'll be a transmission issue. And in other markets, it'll be in a permitting approval and process issue. It's, I haven't -- we haven't found yet the market that rolls from a policy point of view all of the pieces in place and adds just the perfect setting. And that's part of the legwork that has to happen. And we need to start now because there's a lead time involved and it's important in starting to be able to say, "Look, we are prepared to price at grid parity levels, at volume, over this 3-year period," so we can engage in a serious discussion. So that's part of the details of that are being rolled up now. It's viable to us, although risky, or we wouldn't have taken this direction. And I think when you see the full picture, you'll probably have the same view. So the dispute in China and how does that impact it? Now I think, potentially, in a favorable way, China has obviously a big energy problem. They have a big carbon problem. I've been going there long enough and spoken with enough people. I think that Chinese government's sincere in their desire to shift on a going-forward basis, portions of their incremental load to renewables as much as they possibly can, consistent with good economics and so forth. That means there’s a pretty big role for solar. I mean, not just to support Chinese manufacturers, but to meet real energy needs. It's got to hit a price point, and it's got to be scalable. And that's really the discussion that led us to the 2 gigawatt MOU in Ordos. I think we can use these discussions to, hopefully, elevate the discussion in China away from trade skirmishes, and sort of the small conversation, to the larger one. How can we bring the most advanced technologies in the world to a market with one of the biggest fundamental needs for energy and help them solve the problem? And we've got good relationships there, and I think with the renewed emphasis and the right price points, I'm optimistic that we can make something happen in China.

Mark R. Widmar

The one other comment is the project finance, because you referenced Ex-Im financing, I just want to bring that into the discussion, especially as it relates to the assumptions around our long-term business model that we've given some key performance metrics around. We have tried to structure that in such a way that while we obviously will be strategic and try to leverage if there is low-cost financing available through Ex-Im as an example, but we don't want that to become constrained as it relates to where we have to produce modules. So the assumption in our long-term business model enables flexibility so there's not a dependency per se, because if you think about servicing Asia-Pacific, it's somewhat unnatural to do that from the U.S. versus Malaysia where we have a very competitive low-cost facility that's in the geography. Right? So I just thought to make sure you had some clarity around that. Yes, if it's available and it makes sense, we'll do it. But we're trying to create a model such that we have flexibility and don't become dependent upon that financing in order to price through at grid parity.

Operator

We go next to Mehdi Hosseini with Susquehanna International.

Mehdi Hosseini - Susquehanna Financial Group, LLLP, Research Division

Two things. First, on the Slide 24, you are talking about -- or highlighting as much as 720 megawatts of module shipment into Europe. I assume this is the Module business. Given the financial situation in Europe and some of your customers that are under immense amount of financial stress, what is the confidence that this sell-through could actually happen, even with lower prices even if it seems like there is no elasticity there? And I have a follow-up question.

Mark R. Widmar

Yes. So the 720 megawatts is global, all third-party Module sales, right? So it's not just Europe. In the Europe, obviously, this is a substantial portion of that. But we will realize sales similar with this year into India and other parts of Asia-Pacific and even opportunities in the U.S. if we recognize some sales here in 2011. Europe is going to be a challenging market for us in 2012, given a lot of the items that you just referenced. We've tried to de-risk as much as possible. We've tried to align to better understanding transparency around our specific customers' project and their pipeline into incorporate those volumes into our planning assumption. There's always risk, though. That's one of the reasons why we provided the assumption around volume already. There's a 10% reduction in volume and those module sales that will impact our EPS at around $0.30 or so. So we've given you that level of visibility. But we’ve scrubbed it. We worked very closely with our sales team trying to understand customer requirements and underlying market demand. We've aligned it to the new feed-in tariff that will be effective in 2012. So we believe from a pricing standpoint, the economics will still be very viable. But as you point out, there's a lot of uncertainty in the market and that's one reason why we've given some level of sensitivity around volumes, which would mean to be reflective of risks that we would see in Europe. Now the opportunity will be to see growth outside of Europe and maybe do better, and Asia-Pac as an example. And we've seen some pretty good progress here in '11 as it relates to India. We're seeing some other traction in markets such as Thailand. And as Mike mentioned as well, China's obviously a big market opportunity for us in 2012. So I think it's going to be more of a diversification portfolio play that'll help us balance of out the risk in Europe. It makes sense that we are -- we do have volume risk, we would at least give you a sensitivity of what that would mean to EPS.

Mehdi Hosseini - Susquehanna Financial Group, LLLP, Research Division

But to generate more than $6 per share of free cash flow, and given where the stock is, do you have any plans for like a buyback or something that would help bring back confidence?

Michael J. Ahearn

Well, look, I mean, I think confidence comes from a fundamental view of the road ahead for the business. I mean, taking cash ,which we can totally use to fund our growth and to buffer variation to buy back stock, to drive the share price, doesn't strike us as a smart thing to do from a fundamental point of view. So we've listened to several suggestions that we consider it and we've rejected that idea.

Operator

We go next to Smittipon Srethapramote.

Smittipon Srethapramote - Morgan Stanley, Research Division

I was wondering if you can give some more details on what percentage of the downward revision to your 2012 guidance was due to weather. And what percent was due to other factors? And can you go into more details in terms of what the other factors were?

Mark R. Widmar

No. I mean, I'm not going to break it out. There was about 3 projects that were impacted and some weather delay impacting 2 of them. And the other one was more of timing around the closing of the project financing. All right? So those are -- that's kind of the risk that we have and inherent in our EPC business because of those variables that you can't control. And from our standpoint, the right thing to do in terms of preserving the economics, to allow those events to happen, and if it means the revenue flows into the following year, it flows into the following year. We could have thrown incremental costs at it. We could have put over-time and throw additional resources on it to try to overcome the weather delays. It just would've came at a cost. And we look at the incremental costs associated with it versus the benefit of having the revenue flow out one month, economics will completely say let the revenue flow the way it would. And that's what ended up happening. We've got a slight miss to the top line revenue as a result of that.

Operator

We go next to Timothy Arcuri with Citi.

Timothy M. Arcuri - Citigroup Inc, Research Division

I had 2 things. First of all, a lot of the launch from cost reduction is based upon higher efficiencies. And you've recently had some issues out in the field with some product that, talking to some of your customers, seems to be related to the higher efficiency product. So I'm wondering sort of what the resolution and the risk around some of these issues, some of these power issues going on in the field are? Number one, if you could help us with that risk? And then secondly, I was wondering if you can give us what's the development cost that's on top of the core Balance of System cost in your 2012 number? So you're taking that core number ,but there's a development number that goes on top of that. And I'm wondering, is that $0.30, $0.40, what is that number?

Michael J. Ahearn

Yes, Tim. So I would say on long-term field reliability, I mean, that's always a risk when you're changing processes, and it has been from the time we went into production. We have had, on occasion, issues and they're dealt with. We felt they're all resolved, and reflect in our financials. The -- any Issues that have been reported, that I'm aware of, relate to prior year's productions. And when we have fuel problems, when we have positive experience or negative, we take that back into the factory and improve processes, but also improve our metrology and our accelerated reliability testing, our predictive ability. And as a result, we're much better able today to measure and assess the long-term fuel performance of modules coming off the line than we were a year ago, 2 years ago, 5 years ago. So we -- based on that knowledge, we established criteria -- qualification-release criteria, and we don't deviate from that in order to drive higher efficiency. So the efficiency roadmap we're presenting is, one, that we believe is attainable with very tight parameters around the metrics that we think indicate good, long-term fuel reliability. That's the way I can put it. So it's not about abandoning quality for -- to try to drive efficiency or numbers. We feel pretty good about it because of the results we've been able to demonstrate in a pretty rapid, pretty short timeframe, integrating process improvements off that record sale into real production. And the productions run long enough now and the results have been consistent enough on both stability and efficiency that we're comfortable talking about it. So I think -- look, it's 15% challenging, does that have more uncertainty than other aspects of our business? Yes, it does. But we have a lot of reason to believe that, that's achievable. There's an entitlement to that around it, technically, based on the 17.3% Cell Efficiency with the other...

Mark R. Widmar

Yes. I guess, maybe, can you repeat the other question as related to the development costs just to make sure we understand that?

Timothy M. Arcuri - Citigroup Inc, Research Division

Sure, Mark. So I'm just trying to sort of get at what we the embedded module pricing is in your U.S. utility pipeline. And to do that, I have your core BoS cost, but I sort of need to know what your -- what the additional costs are, development, things like that, that sort of go on top of that so I can strip that out and then whatever's left is the module selling price?

Mark R. Widmar

Yes. So we don't provide the specifics of that by project. They -- it can vary by project given the unique circumstances of each of the projects. We did indicate in our, at least, our long-term model, is that those development costs range around $0.20. At least, that's our assumption, but it can be anywhere from $0.20 to $0.30 depending on a particular project. And we don't provide by individual discrete project what that impact is.

Operator

We go next to Amir Rozwadowski with Barclays Capital.

Amir Rozwadowski - Barclays Capital, Research Division

If we take a look at your sort of shipments by geography, and certainly in 2012, we do expect -- at least based on your estimates, do expect sort of an increase of shipments in North America. And just telling on -- in your prior commentary about backfilling your own installs, how should we think about that trajectory going forward? I mean, it should -- we think that, at least as you work towards your 2014 target, really, we should think overall sort of Systems business continuing to come under pressure as some of this pipeline gets built out in North America? And then I've got a follow-up question.

Michael J. Ahearn

Well, I think the -- so you should probably think about the mix moving from modules to standalone towards systems and the pricing on systems to be moving down because what's embedded in our contracted pipeline right now are PPAs that were negotiated in the last -- over the last several years at higher PPA prices that are likely to prevail in the future. So I would think about it, if you want to take a base line and take the LCOE pricing that Mark provided to drive market and assume that sort of base line system-level pricing. And in some cases, it might have to be lower. There may be opportunities for it to be higher in situations as we go forward. But that's pretty good baseline of where we're headed.

Amir Rozwadowski - Barclays Capital, Research Division

Helpful. And then you folks have discussed sort of on the -- for the broader market that, clearly, the installation capacity is fairly high at this point. You folks are continuing to focus on driving down costs in order to be competitive in this environment. When do you expect sort of a tipping point when it comes to consolidation of that installation capacity? It seems like based on your cost outlook, you don't believe many of your competitors can be profitably competitive within this market. And I think that the sense that we have, or at least industry has, is that there needs to be some consolidation here? And we're wondering what your thought process was on that consolidation.

Michael J. Ahearn

Well, I think you can take all these markets that are based on subsidies and just picture that as a pool or a pawn that's evaporating and drying up. And every -- I think the short-term answer is try to get more share out of that but it keeps getting smaller. You could consolidate to try to get more share. I mean, that's certainly one way. That doesn't seem like a very prudent use of resources since the overall pie – pawn, I guess to keep the metaphor - shrinking, not growing. And so we would rather think about that transitionally and move into different space which is not subsidized. Which is hard to break into, but if you can get there, then you've got significant growth ahead. You've got some true visibility year-over-year in the business because it's based on fundamentals rather than politics. And that's where I think our PV competitors will have a hard time following us, at least in the short term. But on the other hand, I don't know that it would be such a bad thing to have other PV companies make the shift into the non-subsidized world because, really, you got -- it's such a massive market and the real competition are the thermal plants that we will be replacing, or at least substituting for, on a go-forward basis. So I think we can lead this as we have other aspect of the industry and markets, and be positioned as a first mover. And we can leverage the validation we've got from great utility companies and record companies in the U.S. on all these projects, I think effectively.

Operator

Our final question comes from Paul Clegg with Mizuho.

Paul Clegg - Mizuho Securities USA Inc., Research Division

In your long-term cost comparison, you were targeting a $0.10 efficiency penalty in 2015. What's that efficiency penalty today? And then can you talk a bit about the specifics of Balance of System cost reduction?

Mark R. Widmar

The model that we've carried out to 2015 takes us towards our efficiency destination, which is around 15%. And that we believe that, at that point, we’ll be on average about a 2% efficiency difference between where the crystalline silicon will be. And that will be the $0.10 assumption that was embedded in there, right? So today, the efficiency delta, if you look at the average for 2011, we’re a little bit wider of that, which would mean that the current efficiency delta discount's going to be little bit north of $0.10. But that's just how we've assumed it as we move forward. And so it will come down a little bit. Today it's a little bit wider than that, given relatively flattish improvement in efficiency from beginning of 2011 to the end of 2011. But as we move forward, as we indicated as a full-step, 1 point improvement in 2012, and an exit rate over what our average was for 2011, we'll start to see that gap close a little bit.

Michael J. Ahearn

EPC, on the BOS cost reduction, there's a few aspects to it. One is the development of a standardized system design -- a set of standardized system designs that can be replicated in deployment, which drives learning cycles, which increases throughput or reduces installation time, if you want to think about it that way, and drives economies of scale from a bond perspective. Another aspect is the ability to quickly and efficiently do the site-specific design work -- system design work, which is a product of a lot of learning. The other aspect is conversion efficiency improvement itself, reducing the need for area-related Balance of System components. So it's really all that coming together. And our vertical integration into this aspect of the business a few years ago, combined with the volumes of projects that they've been able to work have really been what's driven this is the learning cycles. It's why they were able to achieve the 2014 target last year and it's what gave us visibility into the additional roadmap.

Operator

Thank you for your participation. That concludes today's conference.

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Source: First Solar, Inc., 2012 Guidance/Update Call, Dec 14, 2011
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