First Solar, Inc. (FSLR) Q1 2012 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to First Solar's First Quarter 2012 Earnings Call. This call is being webcast live on the investors section of First Solar's website at 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 of Treasury and Investor Relations of First Solar Inc. Mr. Brady, you may begin.

Good afternoon, everyone, and thank you for joining us. Today, the company issued a press release announcing its financial results for the first quarter of 2012. If you did not receive a copy of this press release, you can obtain one from the Investors Section of First Solar's website at firstsolar.com. And additionally, we have posted a presentation for this 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 May 10, 2012, at 11:59 p.m. Eastern Daylight Time and can be accessed by dialing (888) 203-1112, if you are calling from within the United States; or (719) 457-0820, if you're calling from outside the United States, and entering the replay passcode 3703847. A replay of the webcast will be available under the Investor 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 a subscriber of FactSet or Thomson ONE, you can obtain a written transcript. With me today are Mike Ahearn, Chairman of the Board; Jim Hughes, our new Chief Executive Officer; and Mark Widmar, Chief Financial Officer. Mike will discuss our 5-year plan that lays out select targets, as well as strategies we will implement to achieve those targets. Mark will then review our financial results for the first quarter and update guidance for the year. We will then open up the call for questions. [Operator Instructions] First Solar has allocated approximately 1 hour for today's call. Most of the financial numbers reported and discussed on today's call are based on U.S. generally accepted accounting principles. In a few cases where we report non-GAAP measures such as free cash flow or non-GAAP EPS, we have reconciled the non-GAAP measures to GAAP measures at 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 that are 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 and 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 with the Securities and Exchange Commission. First Solar assumes no obligation to update any forward-looking information contained in this call or with respect to the announcements described herein. It is now my pleasure to introduce Mike Ahearn, Chairman of the Board of First Solar. Mike?

Thanks, David, and welcome to our first quarter 2012 earnings call. I'd like to start by announcing that Jim Hughes will become our Chief Executive Officer, effective today. Jim joined First Solar on March 14, 2012, as our Chief Commercial Officer and had responsibility for overseeing all of our external functions, which included business development, project development, EPC, O&M, government affairs and communications. Since that time, Jim has demonstrated superb leadership across the organization while filling a variety of challenging strategic planning and execution roles. On a personal level, Jim and I have formed a close working relationship, and Jim has quickly earned the respect of our board and senior executives. So in summary, our day-to-day experience has confirmed what the board and I hoped would be the case, Jim Hughes is the ideal leader to execute First Solar's 5-year transition or 5-year plan to transition from serving subsidized markets to becoming a global leader in providing utility scale solar power solutions. Jim has nearly 20 years of experience in global energy industry and most recently served as CEO of ADI, which owned and operated Power Distribution, conventional and renewable power generation, natural gas transportation and natural gas distribution businesses in 19 countries. He has owned and operated utilities, built power projects, created local teams and partnerships and led profitable growth in numerous markets around the world, including many of the markets we are targeting now in our 5-year plan. From a process and timing perspective, I'd like to add that the board conducted an exhaustive search for the CEO position and received significant interest from a number of candidates. And we're honored and gratified by the strong interest in the position expressed by several extremely accomplished global executives. And in the final analysis, we concluded that fit of Jim, in terms of his market knowledge and experience, leadership skills and cultural alignment was the ideal. Jim has been an integral part of the development of our strategy and 5-year plan that we'll be discussing today. The plan will continue to crystallize and evolve based on our market experience. But directionally, Jim, Mark and I, as well as our board and management team, are fully aligned around the plan. I look forward to supporting Jim as the Board Chairman and as a close partner. And so let me invite, now, Jim to say a few words. Jim?

Thanks, Mike. Many of my colleagues in the traditional energy world have asked why I wanted to come to First Solar in the middle of this difficult period for the solar industry, but it's exactly this difficulty that makes it an interesting opportunity for the company and the marketplace. I believe that the rapid cost reductions that have occurred leave solar at the threshold of taking its place as a mainstream part of the power generation complex. I have always endeavored to do things that matter and make a difference in the world. In energy, that the means doing things at a meaningful scale. First Solar is the premier platform from which to execute projects at significant scale. We deliver to our customers’ real power plants that integrate seamlessly into the grid and deliver cost-effective power in meaningful quantities. I believe that the team at First Solar is unrivaled in terms of talent, depth and experience, and I am truly excited to be a part of it and look forward to continuing to work with Mike as the Chairman of the Board.

Thanks, Jim. I'd next like to discuss our strategy and 5-year plan. And turning to Slide 6, the excess capacity in the industry is by now well known. Because the silicon supply chain has become commoditized, we believe the industry will be prone to cycles of overinvestment and production capacity in the future. The traditional subsidies that enabled PV markets are declining, and we do not expect similar subsidy programs of any consequence in the future, and this has resulted in a dramatic drop in near-term demand in some markets. This basic imbalance between supply and demand required First Solar to seek a new strategy for delivering profitable growth that can be sustained over an extended period. Moving on to Slide 7. As we previously discussed, our strategy is to develop new sustainable markets by providing utility scale solar power to regions in the world that are blessed with abundant sun and a need for more peak electricity. We define sustainable markets as markets characterized by competitive pricing dynamics where generation costs are borne by consumers and public budgetary financing is not essential to creating demand. We're no longer devoting efforts to developing demand in traditional subsidy markets, including rooftop applications. Simply because we do not believe these markets offer prospects for sustainable growth, and a successful execution of our strategy requires that we focus our time and resources on our new markets. In the future, subsidized markets may make up a part of our total sales, but their contribution as a percentage will decline significantly going forward. In order to open new sustainable markets for solar electricity, we will need to do 3 things: first, be prepared to price solar electricity at levels sufficient to make solar-generated electricity a compelling value proposition, ensure that we meet demand without the benefit of subsidies; second, design and engineer utility scale solar power plants that will deliver reliable levels of energy production with sufficient mitigation of intermittency that allows the plant to behave more like a renewable generation from a conventional power source; and third, effectively integrate large-scale solar generation onto the transmission grid without destabilizing the grid or imposing excessive grid management costs on the local grid operators. Now I'd like to explain how First Solar's uniquely capable of delivering on each of these 3 requirements, starting with pricing. On Slide 8, we give some indications of the major components of the solar powered product, and how each can impact LCOE. The price of solar electricity is determined by the cost of capital, total installed system cost and project development costs, together with the irradiance level of the specific site. As you can see from the slide, the evolution of LCOE for any market and specific site is a multi-variant and complex relationship, and LCOE is highly sensitive to project cost of capital. We believe solar electricity cost in the range of $0.10 to $0.14 a kilowatt hour will be sufficient to trigger new demand and open sustainable markets. We're planning to achieve these price levels in 2 ways: first, as shown on Slide 9, successfully executing our system cost reduction roadmap will enable us to reach $1.15 to $1.20 per watt by 2016, which we believe will enable market clearing pricing under a broad range of variables and irradiance levels. While this cost reduction roadmap is not fully addressed, it is based on a reasonable bottoms-up plan that we are currently executing, and we have sufficient confidence in the plan to forward price against it under appropriate circumstances. Also, should market conditions require further cost reductions to remain competitive, we believe we can react to that circumstance by accelerating qualification cycles, the process in product improvements, albeit with a greater degree of risk. The second, we plan to execute a vertically integrated business model in each market, either directly or with strategic partners, which will enable us to participate in sufficient components of the value chain to both capture the market opportunity and deliver an attractive return on investment capital. Our vertically integrated model will allow us to reduce cost and normalize margins across multiple stages of the value chain in order to achieve the lowest all-in cost possible. Turning to Slide 10. In moving from PV subsidy programs to sustainable markets, we're asking utilities, grid operators and other power users to integrate solar energy as a mission-critical part of their infrastructure. To adopt solar energy at this scale, these stakeholders must be convinced that solar power providers can not only deliver energy at market-clearing prices, but also reliably predict solar energy generation and deliver on those predictions. This requires that the system hardware perform to expectations, that the performance impacts from building large-scale systems as opposed to smaller arrays be well understood, and that the prediction models used to forecast solar generation over both the long term and short term be accurate. In addition, these performance expectations will need to make their way into the system planning processes of the local market stakeholders. We have deep experience predicting energy yields from power plants to employ our modules, including, since 2008, power plants that we've designed, engineered and constructed. Since 2009, we've employed our own O&M function to monitor and analyze our utility scale power plants in the U.S., supported by a sophisticated utility grade network operating control center. Over the course of this experience, we have analyzed the performance of literally millions of solar modules and numerous system designs and sizes and across many different environmental conditions. We've used this extensive data in learning to continually improve our system hardware, optimize system designs, improve the accuracy of prediction models, correlate power plant performance to predictions and accelerate diagnostic capabilities. Our depth of data, understanding and sophistication regarding solar power plant performance is unsurpassed in the industry and has met the exacting standards of leading utilities, project lenders and rating agencies, as evidenced by our performance to date, which includes 2.4 gigawatts AC of solar power plants constructed or under construction; 1.1 gigawatts AC at solar power plants that have received debt financing rated investment grade, exceeding $1.5 billion in the aggregate; and approximately 2/3 share of the PV projects worldwide that exceed 100 megawatts in size that are either completed or under construction with financing secured. 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 utility and energy industry, including APS, EDF, Exelon, GE, NextEra, NRG, PG&E, Sempra, Southern California Edison, Southern Company and MidAmerican. Turning to Slide 7, third requirement to opening new sustainable markets with utility scale solar power solutions is that the solar provider must be able to effectively integrate large-scale solar generation onto the transmission grid without destabilizing the grid or imposing excessive grid management cost. Solar power has several properties that differ from conventional power. Unlike conventional power, it cannot be dispatched at will; it must be used when available or not at all. Unlike conventional power, it is intermittent. It's only available when the sun is out. And finally, it's availability in the short term is subject to a greater degree of uncertainty as compared to conventional power due to unforeseen changes in weather. These characteristics pose unique problems for grid operators, who must instantaneously balance supply and demand on the grid and regulate voltage fluctuations in order to maintain grid stability. At the low penetration levels typical of most solar subsidy programs and distributor generation programs, including rooftop, solar power can be added to the grid without triggering these issues. However, at the higher penetration levels implied in sustainable markets, these grid management issues must be well understood and solved before integrating solar power generation. Failure to address these issues can lead to power market distortions and grid problems. Our experience building and operating large solar power plants, combined with our data acquisition and analysis capabilities, have allowed us to characterize and predict grid stability issues under a variety of conditions. As shown on Slide 11, First Solar has developed sophisticated software control solutions that can actually contribute to, rather than disrupt, reliability of the grid. This includes features such as active power control, voltage regulation through reactive power capabilities and the ability to ride through faults. Grid operators can interact and control our solar plants in real time. We can deliver an energy forecast using our advanced prediction capabilities. In some cases, we use satellite imagery to forecast cloud cover that our plants can use to predict weather patterns hours ahead of time. System integrators tell us these capabilities will be critical to enable them to effectively manage large concentrations of solar power. We believe our existing grid integration solutions, together with our innovation pipeline in this area, and our experience at this scale will enable grid operators and utilities to effectively manage the integration of the large-scale solar power plants we intend to provide, keep us at the forefront in this key area. Turning to Slide 12, in summary to the question how will you win business with your strategy? The answer is by delivering on the 3 key requirements to these markets: a market-clearing solar electricity price; demonstrated reliability; and great integration capability. First Solar is well equipped in all of these areas. To the question: How do we compete against PV component manufacturers or other system integrators that use cheap silicon-based panels? The answer is that we not only provide the lowest cost hardware solution, but a combination of power plant reliability, strong local presence and grid management capabilities that cannot feasibly be achieved without effectively executing an integrated business model over multiple years and multiple gigawatts and installations. Our targeted customers are technically adept, risk averse and sophisticated. They have and will continue to appreciate the unique value we provide. So turning to the 5-year plan, the cornerstone is our existing multiyear project pipeline. As shown on Slide 13, our existing captive pipeline is supported by long-term power purchase agreements or PPAs with financially sound utilities. As Mark indicated on our April 17 call, we expect our pipeline installations to be approximately 1.2 gigawatts DC in 2012 and 2.8 gigawatts DC in the aggregate for the period 2012 to '14, and to generate on a net cash receipts basis an aggregate of $3.4 billion. Slide 14 depicts the runoff of our existing project pipeline and the additions of new sustainable business over the next few years. Our project pipeline, combined with our recent actions to restructure in order to substantially reduce our cost structure, provide a degree of time to develop and execute the strategy. As a baseline, we are targeting, for the full year 2016 sales in the range of 2.6 to 3 gigawatts DC, which is the estimated annual module production capacity with our current factories in some of our spare equipment, with essentially all of the revenue coming from sustainable markets. We're now focusing on the new markets, although we're still early in the process. As shown on Slide 17 or 15, Slide 15, we’re screening markets based on a combination of power demand, price level in other power sources, price level availability of other power sources and irradiation levels. Slide 16 presents our financial targets for 2016 with several important assumptions. First, we're assuming we were able to sell 2.6 gigawatts to 3 gigawatts DC at power plants in a 100% vertically integrated business model, but we do everything from development through sale of the power plant. The second, we assume we achieve our conversion efficiency and cost reduction targets. And third, we're assuming average power plant economics as described on the slide. As you can see, the net result under these assumptions would be a return on invested capital for the full year 2016 of between 13% and 17%. In reality, we'd likely to deviate from the assumptions on Slide 16 in a number of ways as we execute the plan. For example, we will probably execute a vertical business model through joint ventures or partnerships in some of our markets, resulting in a sharing of the economics, as well as potential upside to the 2016 volume targets. Also, power plant economics for individual projects will likely vary from the assumptions on Slide 16, in both negative and positive respects. Regardless of market variations, our plan is to manage to a range of 13% to 17% return on invested capital, starting in 2016, and to adjust operating expenses and capital as needed to achieve the targeted return. We believe the business platform we're targeting for 2016 will enable attractive long-term growth and value creation. Now I'd like to turn the call over to Mark Widmar, who will discuss our financial results and update our 2012 financial guidance.

Thanks, Mike, and good afternoon. Starting with operations on Slide 18, in Q1, we ran our plants at approximately 85% of capacity, producing 504 megawatts, down 7% quarter-over-quarter. In order to meet our goals to better align supply with market demand, we suspended 4 production lines in Frankfurt-Oder for the month of March. In addition, we did not run production during the Q1 Malaysian holiday period as we have historically. Finally, in support of our efficiency roadmap, we idled and upgraded lines in Perrysburg and Malaysia. The average line conversion efficiency for our modules was 12.4% in the first quarter, which is up 0.7 percentage points year-over-year and up 0.2 percentage points quarter-over-quarter. Note, the year-on-year average module efficiency improvement has helped reduce the standard installed system costs by approximately $0.08 to $0.10 per watt. Our best plants improved to 12.9%, which is up from 12.6% last quarter. We continue to make progress on our technology roadmap as the average line conversion efficiency for the second quarter today is 12.5%, up 0.1 percentage points over the first quarter. And the current efficiency rate of our modules produced in our best line is 13.1%. Module manufacturing cost per watt for the first quarter was $0.73, which is unchanged quarter-over-quarter. The cost includes the $0.03 headwind from plant underutilization and factory downtime. Had our plants run at full utilization, our module manufacturing costs per watt would've been $0.70 per watt or $0.02 below Q4 on a comparable basis. Our best plant is manufacturing modules at a cost of $0.66 per watt, excluding underutilization. The restructuring actions we have announced on April 17 will help improve the plant utilization rate going forward and reduce the underutilization estimate on our cost per watt basis. Moving to Slide 19, we show our updated view of available capacity and anticipated production utilization. This updated slide no longer includes our manufacturing facility in Frankfurt-Oder and reflects 20 production lines in operation in Malaysia and 4 in Perrysburg, Ohio. As previously announced, we expect our modular production to be between 1.4 gigawatts and 1.7 gigawatts in 2012. Turning to our Systems business, we continue to have a robust, active list of projects that we are bidding on. In the first quarter of 2012, for example, we added 20 megawatts AC for a project in Maryland via an acquisition. We also added 26 megawatt AC for the Avra Valley project located near Tucson, Arizona, which we are building for NRG. We continue to make progress on other projects in our pipeline. In March, Enbridge acquired our 50-megawatt AC Silver State North projects in Nevada and NextEra completed the acquisition of the 40-megawatt AC St. Clair project in Canada. In April, Exelon received the first funding from the DOE to finance the 230-megawatt AC Antelope Valley project in L.A. County, which eliminates the risks that we might need to repurchase that project. Also in April, Tenaska completed the financing for its 130-megawatt AC Imperial Solar Energy Center and we have final notice to proceed on construction there. Lastly, NRG in MidAmerican celebrated Agua Caliente's first 100 megawatts being delivered to the grid, making it North America's largest PV plant in operation. Today, MidAmerican and First Solar held a groundbreaking celebration at Topaz, marking start of major construction at the site. These milestones demonstrate that many of the world's most sophisticated, renewable energy investors continue to invest in projects using our technology which is being deployed in some of the largest sites in the world with the toughest desert conditions. Moving on to the P&L portion of the presentation on Slide 20. Net sales for the first quarter were $497 million, down from $660 million last quarter. The decrease was primarily due to reduction in module volume for both third party and system business sales, offset by an increase in EPC revenues. Our EPC revenue mix increased from 30% of total net sales in the fourth quarter to 53% of net sales in the first quarter. Our solar power systems revenue, which includes both our EPC revenue and solar modules used in the Systems business, increased from 64% of sales in the fourth quarter to 86% of sales in the first quarter. Aggregate module ASPs decreased 13% quarter-over-quarter. Module ASPs in the Systems business decreased 27% sequentially, whereas third-party module ASPs declined 12%. The decline in third-party module ASPs quarter-over-quarter was primarily the result of some favorable legacy pricing from our existing module supply agreements declining in 2012 to reflect current market conditions. On a year-over-year basis, module ASPs in the Systems business increased 24%, whereas third-party ASPs declined 32%. Given current market conditions, we would expect the third-party module ASPs to continue to climb throughout the year. Slide 21 provides a list of nonrecurring charges we are taking in the first quarter. The first quarter was impacted by pretax charges consisting of: $43 million related to our previously announced 2008, 2009 manufacturing excursion, of which $27 million affects cost of goods sold; and $401 million for restructuring, which includes approximately $270 million related to the April 17 restructuring announcement and $130 million related to asset impairments and other related charges, including those for discontinued work, our proposed plant in Vietnam as highlighted in our 2011 10-K. The charge for the manufacturing excursion relates to claims we had not processed by year end, which we had previously estimated could cost up to $44 million if they all require remediation. We have now processed all the claims, and based on our completed analysis, we have accrued an additional $31 million to remediate those claims. The remaining manufacturing excursion charge of $12 million related to a change in estimate associated with our power loss compensation and the recovery value of the refurbished modules were claimed through remediation. Regarding restructuring actions, upon completion of these initiatives, we will reduce our ongoing annualized cost by between $100 million to $120 million, post 2012. So it'll be clearly between cost of goods sold and SG&A. For 2012, we expect these initiatives will reduce our cost of goods sold and SG&A by between $30 million to $60 million. Gross margin in Q1 was 15.4%, down 5.5 percentage points from the prior quarter. Excluding nonrecurring charges in the fourth quarter of 2011 and those in the first quarter of 2012, on a comparable basis, gross margin were 40.9% and 20.9%, respectively. The gross margin decline was reflective of lower sales volume, lower ASPs, inventory write-downs and the Systems business project sales mix. Operating expenses were down $90.4 million quarter-over-quarter to $533 million. Operating expenses in the fourth quarter of 2011 were impacted by a series of nonrecurring charges, including goodwill impairment, manufacturing excursion-related charges and restructuring charges. Similarly, operating expenses in the first quarter of 2012 were impacted by restructuring and manufacturing excursion-related charges. Excluding these charges in the fourth quarter 2011 and those in the first quarter of 2012, on a comparable basis, operating expenses were $138 million and $116 million, respectively, or 16% lower in the first quarter of 2012. We anticipate that operating expenses will trend downward throughout the year as savings associated with our recently announced restructuring actions are operationalized, partially offset by investments managed to enable growth in sustainable markets. As we exit 2012, we anticipate our operating expense quarterly run rate will be less than $100 million. On a reported basis, including the impact of nonrecurring items, the first quarter 2012 operating loss was $456.3 million compared to an operating loss of $485.3 million in the fourth quarter of 2011. Slide 21 presents the walk of our GAAP EPS to our non-GAAP EPS, which excludes the impact of nonrecurring items for Q1 2012. First quarter net loss was $449.4 million or $5.20 per share. Before the charges, highlighted on this slide, the first quarter net loss was $6.7 million or $0.08 per share. The complete reconciliation of GAAP to non-GAAP numbers can be found at the back of the presentation. As the Systems business mix increases, our quarterly results may be more lumpy, which is primarily driven by the timing of project revenue recognition. For example, even though Silver State North was sold in Q1, revenue for this project will not be recognized until substantial completion is achieved in Q2. Also in Q2, we anticipate to begin recognizing revenue for AVSR as Exelon's ownership of the project has been finalized with the first advance of the loan guarantee by the U.S. Department of Energy. With the revenue and associated gross margin for these projects, we anticipate our results sequentially will improve significantly. Turning to Slide 22. I'll review the balance sheet and the cash flow summary. Cash and marketable securities were $750 million, down $38 million from $788 million at the end of last year. Accounts receivable trade balances increased slightly quarter-over-quarter, and our unbilled accounts receivable increased by $18 million quarter-over-quarter due to increase in unbilled revenues at Agua Caliente and St. Clair. Our unbilled accounts receivables have increased significantly since the first quarter of 2011. We have taken actions to reduce the unbilled accounts receivable by better aligning our project construction build to the underlying contract and milestones. In addition, we successfully negotiated a change to the Agua Caliente milestone payment schedule, given the significant progress we have made and collected nearly $200 million of the unbilled accounts receivable since quarter end. Inventories increased due to higher inventory of our Systems businesses to support increased project activity, both for modules and balance of systems, and third-party module demand that may [ph] will occur third-party module demand as we did not go through our Q1 production. Project assets decreased as we recognized the sale of St. Clair to NextEra, and Silver State North to Enbridge. Deferred project cost increased as we constructed projects we had sold, although funds for which we cannot recognize revenue yet. As a reminder, when a project sells, the project assets turn either into revenue or deferred project cost, depending on whether all applicable revenue recognition criteria have been met. Our debt level increased by $201 million from the end of last year, primarily to fund working capital increases in our Systems business as certain projects anticipated to close were pushed out of the quarter, and we made our annual module EOL, end of life funding in Q1. As announced on April 5, the AVSR received a first advance of a loan guarantee by the U.S. Department of Energy finalizing Exelon's ownership of the project. We used these funds and other sources to repay $200 million of the revolver since quarter end. Also as previously announced, we voluntarily repaid the entire outstanding balance under our Germany credit facility. These payments had reduced our end-of-quarter outstanding debt by $342 million or approximately 40%. Operating cash flows for the quarter were negative $16.1 million and free cash flow was negative $212 million. We spent $125 million for capital expenditures, up $7 million from last quarter. As we complete capital commitments related to previously planned capacity expansions, we anticipate capital expenditures to decline in the second half of this year. Depreciation was $72.7 million compared to $67.9 million last quarter. First Solar is in a strong financial position to navigate the current market turbulence. However, we recognize the market has changed rapidly and failing to adapt to this new reality would have serious financial repercussions. Also, and we feel the restructuring initiatives we have taken in recent months to enhance our balance sheet, and we have the financial wherewithal to undertake those restructuring initiatives. We will be constructing a project in our project pipeline over the next several years, which will provide a buffer against demand fluctuations in the market and the restructuring initiatives will further conserve our resources as we develop new sustainable markets. This brings me to our updated guidance for 2012, starting with the assumptions that [indiscernible] our guidance, as shown on Slide 23. As we've mentioned on our April restructuring call, we expect demand to range between 1.5 gigawatts to 1.8 gigawatts and our average module manufacturing cost to range from $0.70 to $0.72 per watt. Our expectation for average module efficiency are 12.7%. It’s unchanged from prior guidance. We expect our effective tax rate to be in the range of 17% to 19%, excluding the impact of any restructuring or impairment charges. It is up slightly from our prior guidance due to the jurisdictional mix of income. Turning to Slide 24. Despite the operational results for the quarter, our internal business forecast remains intact. And based on reductions in our ongoing cost structure related to our restructuring initiative, First Solar is increasing 2012 guidance as follows: Earnings per fully diluted share of $4 to $4.50, compared to prior guidance of $3.75 to $4.25. Operating cash flows of $850 million to $950 million compared to our prior guidance of $800 million to $900 million. We are maintaining our guidance for CapEx as nearly half of this relates to our proposed plan from Vietnam and Mesa, which we are required to complete. In addition, we will continue to invest the required CapEx to achieve our module efficiency roadmap. Beyond 2012 with our manufacturing footprint excluding Frankfurt-Oder, we expect our overall CapEx to range between $150 million to $300 million annually through 2016. Regarding anticipated restructuring charges, we expect to incur between $40 million to $80 million over the balance of the year, which will result in the full year charges consistent with our April 17 announcement. Note, these charges are excluded from our EPS guidance. Our operating cash flow guidance includes approximately $75 million of net cash receipts from the Desert Sunlight and $80 million to $120 million of cash expenditures associated with our restructuring actions as previously announced. To summarize on Slide 25, our strategy is to win business in sustainable markets by delivering on 3 key requirements: one, achieve a market-clearing solar electricity price; two, reliably predict solar energy generation; and three, integrate into the grid in ways that enhance grid reliability. We target to sell between 2.6 gigawatts, 3 gigawatts in 2016, earning return on invested capital in the range of 13% to 17%. Based on reductions of our ongoing cost structure, we are increasing our 2012 EPS guidance. With that, we conclude our prepared remarks and open the call for questions. Operator?

[Operator Instructions] And at this time we will go to Stephen Chin with UBS.

This is Mahavir Sanghavi for Stephen Chin. A quick question about 5 year plan. Your next 5 year plan assumes about additional 5 gigawatts of project pipeline. Can you give us some sense of what investment is required for that? And what the geographical breakdown could broadly look like?

Yes, we didn't have a pipeline assumption really on the 5-year plan. What we assume, what we're targeting is, at the baseline anyway, for the full year 2016, the annual installations of 3 gigawatts, and the way that we got to that was simply to try to take our existing production capacity, including the standard tools and maximize that. There are a lot of unknowns here, if things break in a more favorable way, it'll be larger. But we have to have a baseline to try to size resources, financial and otherwise, to be -- as far as the capital to execute it, a lot of that's going to depend on the model, the partnership, the partnering arrangements and what role we play in some of these markets, which is a reason to continue to bolster our liquidity and our cash position as we execute though these projects.

It begins, I guess, as a range of understanding the capital required, putting aside the capital remaining to make in order to create various relationships and alliances in different markets is that the capital expenditures will be in the range of $150 million and $300 million on an annual basis which, the way I would look at that is in on the front end of the curve, it's going to be lower; and then on the back end of the curve, it'll be closer to 2016. You'll see it ramp up a little bit.

At this time, we’ll move to Sanjay Shrestha with Lazard Capital.

A 2-part question for me, guys. First up, are you guys in sort of active discussion right now, Mike, when we talk about the JV partnership as a way to sort of go after some of these sustainable markets? And the second part, if I may, can you update us on some of those 4,000 remaining warranty claims? Are they completely behind us, or what's the status of that?

Let me ask Jim Hughes to comment on the partnerships and then Mark can update you on the claims, Sanjay.

Sure. I don't want to highlight the specific margins unless we have conversations for competitive reasons, but we have multiple joint venture conversations underway. We actually are currently bidding in a number of markets with partners. We're discussing longer-term, broader arrangements with other partners, but we think it will be a regular feature of the business model as we move into these new markets and we have numerous conversations underway, so we are, we have boots on the ground and our -- in advanced discussions with a number of parties.

Yes, as it relates to the LTM [ph] claims, as I indicated, we have now processed all of the claims. We determined which ones would be required for mediation and we have provided for those claims. We believe that the valuation that we've done, that we have completed has been very thorough, and we do not believe that in a meaningful amount, if any of those unremediated claims would then determine to be later to have to require remediation.

At this time, we'll go to Amir Rozwadowski with Barclays Capital.

If we talk a bit more about sort of the pipeline progression, in the past, you folks have discussed that the pace at which you expect to backfill your pipeline, perhaps slows going forward. Between now and 2016, I mean, can you give us a sense as to how we should think about the progression of pipeline? Is it much more a conversion for the near term as you target some of these newer opportunities? I'm just trying to understand sort of how we should think about that sort of longer term?

I think what you'll see is as we progress through the 5 years is in the near term, there is some remaining activity to be conducted in the U.S, and we think it could be meaningful in size but it will be at lower margins than what we have done historically. But we have a talented team that's pursuing that. Over time, we will begin to develop and action new opportunities in these new markets and you'll begin to see a pipeline grow and we'll be able to, over time, as we get a deeper understanding, be able to get some visibility as to what the pipeline opportunities look like in these new markets, so it will be a gradual transition over the 5-year period.

At this time, we'll take a question from Brian Lee with Goldman Sachs.

On the 3 gigawatts by 2016, what kind of market share would that imply you’re capturing of the utility scale market? And I guess how does that compare to your positioning in the U.S. over the past several years? And then maybe related to that, I'm just curious given how the component cost gap has closed here recently, where do you feel the competitive differentiation for you in building systems is over the longer run?

The estimates of the total market size in 2016 are a bit all over the map, depending upon which source you look at. But the midpoint would be somewhere between 37 to 40 gigawatts of total market size in 2016. So a 3 gigawatt -- if we use the upper end of our range of 3 gigawatts, that's less than a 10% total market share. If you look at our participation in the U.S. markets through the California compliance with their RPS, we would be at a market share that is above that level. When we look at it globally and further subdivide that market into free-field versus distributed, it would require a greater market share in the distributed segment -- I mean, in the free-field segment, but would -- that's where we believe is our sweet spot from a competitive standpoint, and we think the assumption is reasonable. We also think that there is upside potential in terms of the total market size as prices continue to come down and as these prices begin to turn into LCOE and as the markets begin to understand what these LCOEs look like, we think there's significant potential to increase that demand from currently projected levels. But we're not counting on that. We have sized our expectations off of general market expectations about what the size of the market will be. In terms of competitive differentiation, it's all about the product that we deliver to the customer at the end of the day, which for us, is going to be a power plant, and it's going to be a power plant that looks and feels to the grid like the power plants that has control systems that interface in ways that the grid operators are accustomed to with performance prediction capabilities that allow the grid to increasingly treat it as reliable capacity instead of negative demand which brings real tangible value to the grid operator. So we think on a total quality basis, we'll have a competitive advantage. However, that doesn't mean we think we're going to have a cost disadvantage. As we execute our cost roadmap and as the industry ultimately rationalizes itself, we believe we will continue to have a very cost-effective, cost-competitive product in the marketplace and a product that has quality characteristics associated with it, that give us the opportunity to learn.

At this time, we'll move to Timothy Arcuri with Citi.

I have a question on these partnerships that you're actually talking about. So the 2016 guidance you're giving us, you're saying 2.6 to 3 gigawatts. But it sounds like that's based on basically covering your module production. But then you're talking about partnering. So are you talking about partnering with respect to buying modules from third parties? Or what is the partnering specifically referring to? And second of all, on the warranty expenses, if there was a project where you just installed modules, say, like in India, and if there has not been a claim yet from that customer, has that been reserved, i.e., are you going into the market and sort of thinking about what could be reserved in the future and reserving against that now, or do you only reserve against it when it gets claimed?

Yes, I'll take the easy one first. The market provision is associated with our forward-looking projection of modules that are installed. And at that point in time, the girds are provided for the anticipated return rates for those modules that have been shipped or installed are actively being used by the end customers. And if you may remember at the end of the year, we did adjust our warranty rate up, a small 1% increase for a reason of understanding the mix of installations that'll happen going forward. And again, that was done as a forward-looking view. We did not provide for warranty as we incur it. We provide for warranty as we anticipated the return rate associated with product that has been shipped.

In terms of partnering relationships in these markets, the current focus and discussions are really around either project development type relationships allowing joint development of projects or around EPC relationships, which allow the joint execution of engineering procurement and construction contracts, both of which are relatively common structures in other elements of the energy industry. As we move forward in time and we have visibility in the demand in these markets, we could see broader partnering arrangements that included manufacturing, but that's not something we have visibility to at this point.

And at this time, we will now move to Hari Chandra with Auriga.

Regarding your 5 year plan and to presume sanity to prevail in an insane solar PV market, one is on the demand side in terms of policy and also more importantly on the supply side in terms of subsidies and also credit access coming from China. And what would prevent that into leaking into downstream as we go into fully -- as we the transition fully into non-subsidized markets by 2016? So would you not be still be modeling [ph] around with the same dynamics as you go forward?

Well, if the question is, what does the plan contemplate in terms of irrational market participants, I think we recognize that, that is a factor in the market today. And if the industry becomes somewhat cyclic with respect to excess capacity, it could be a factor in the future. I think we feel comfortable that it will not get so severe as to render us unable to compete. Again, if you refer back to the prior question and look at the kind of market share that our plan represents, we believe there is going to be a component of the market that is not going to want to do business with an irrational market participant. They're going to have concerns about quality, long-term staying power and reliability. Enough that will reserve an element of the market, if you have these irrational market participants, for what the quality providers. We recognize that this is an industry that may face capacity excess situations in the future and that you could see irrational participants for periods of time as a result of that, and we feel comfortable that the business model is robust enough to withstand that.

And then on the demand side, when you -- I think the question was around dependency around policies and subsidies. I mean, again, our strategy is to go in and to enable and create markets without that dependency. All right, we can do that with pricing competitively to other alternative sources of electricity and combine that with the value proposition of solar, we're very confident that we’ll be able to do that.

Moving forward, we'll hear from Vishal Shah with Deutsche Bank.

This is actually Susie Min calling on behalf of Vishal Shah. I just had a quick question. What percent of your module sales to India are to the National Solar Mission program? And what percentage to state programs or other capital projects?

Unfortunately, we don't disclose that type of information.

And at this time, we will move to Kelly Dougherty with Macquarie.

It seems that there's not a whole lot of visibility into where that 2.6 to 3 gigawatts for 2016 will come from, but maybe if you could give us some kind of insight as to what you think the rough geographic breakdown might look like by major market at that point?

The challenge is granularity. When we look out to 2016, we can look to areas of the world, we can look to China, we can look to India, potentially Brazil, the Pacific coast of South America, including Peru and Chile, potentially Central America and the Caribbean, Australia and South Africa. These are all markets in which we are active today, in which we see long-term potential. When we look at the aggregate demand we think is going to exist in those markets, we're comfortable with our projection. It could be very lopsided as it actually plays out. We could see India being a very dominant opportunity and less so in some of the other jurisdictions. We really look at it from a portfolio standpoint and believe that given the large number of markets where we think solar is a compelling value proposition, that the combination will yield the numbers that we have in our plan. I would be very reluctant at this stage to provide much granularity in terms of the breakdown because in all honesty, it would not have a robust bottoms-up analytical basis for that.

And at this time, we will take a question from Mehdi Hosseini with Susquehanna Financial.

Yes, as a follow-up to the previous question, I'm a little bit confused. On Slide 16, I see LCOE that is still above $0.10 kilowatt hour. But most of the PPAs that I see have been finalized with connection starting $0.15 are in the high single digits. So does that mean that you're making a top-down assessment that market outside the U.S. are going to be much bigger and much higher PPA rate? Or is there something I'm missing here? Is just the LCOE on Slide 16 and what's going on in the U.S. don't add up.

Yes, I think maybe, so the PPA pricing you're seeing today, at least if it's the same data set we're looking at. It's a function of RPS program, for example, in California with an ITC, an accelerated depreciation. So you've got direct and indirect subsidies embedded in that. And within that market, supply and demand dictates where pricing goes, so there is strong downward pricing pressure, and we would agree with those price levels you quoted. If you take that out of the equation, assume that, that market gets filled up, the RPS quota gets met, there may be some ongoing procurement but it will slow down. And we move to other markets where those types of subsidies don't exist, then the competitive dynamic really is around supply and demand for peak electricity as measured by other non-solar sources that are available in that market. And in that type of market setting, based on a look we've done to-date we think a market-clearing price of somewhere between $0.10 and $0.14 will work, will be quite attractive, relative to other non-solar alternatives.

And at this time, we'll take a question from Josh Baribeau with Canaccord.

Could you remind us what the provisions for favorable tax treatment in Malaysia are? Obviously, it doesn't look like you hit them yet with the idling lines and the layoffs or whatever, but at what level, if any of idle lines or layoffs or idle workers do you lose or are you in danger of losing the favorable tax treatment?

Yes, what I -- I guess I don't want to get into too much details around the specifics of that, but you’ve got to remember that tax holiday was originally generated when we began our initial production at, in KLM, which was initially, I believe, 4 lines when we started production. So as I think, when we look at it from that perspective, we've got 20 lines up and operational. We've given a plan that we believe will generate somewhere between 2.6 and 3 gigawatts of demand, which would say that we're going to need KLM essentially at capacity for the foreseeable future.

And a final question today will be from Chris Kovacs with Robert W. Baird. Christopher M. Kovacs - Robert W. Baird & Co. Incorporated, Research Division: In the past, you guys have talked about some demonstration projects doing in China and obviously you have Ordos going on there, and I know you’ve done some work in India. Can you give us a sense of what your potential pipeline is possibly outside of North America, maybe separate, still in their [ph] early development work, but so we kind of have a sense of the size of early-stage work you're doing outside of this, your core pipeline here?

I think we're reluctant to put specific numbers out right now. They are very large projects that are out there, but they are at such an early stage that it would be potentially misleading to quote that and we're not to a level of probability where I think we feel comfortable with that. As we move forward and get more advanced in these markets, I think we'll be able to provide that type of information. But I think we're not comfortable doing that at this point.

Ladies and gentlemen, this does conclude the question-and-answer session, as well as today's conference call. You want to thank you, all, for your participation. You may now disconnect.