第一太陽能 (FSLR) 2012 Q1 法說會逐字稿

Good day, everyone, and welcome to First Solar's first-quarter 2012 earnings call.

This call is being webcast live on the investor session section of First Solar's website at firstsolar.com.

At this time all participants in a listen-only mode.

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 investor section of First Solar's website at firstsolar.com.

In addition we have posted the presentation for this call on our investor relations website.

An audio replay of the call will also be available approximately two hours after its conclusion.

The audio replay will remain available until May 10, 2012 at 11.59 PM 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 are calling from outside the United States.

And entering the replay passcode, 370-3847.

A replay of the webcast will be available on the investor section of the Company's website approximately two hours after the conclusion of the call.

And will remain available for approximately 90 calendar days.

If you're 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 five-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.

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 one hour for today's call.

Most of the financial numbers reported and discussed on today's call are based on US Generally Accepted Accounting Principles.

In the 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, 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 of 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 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 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.

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 five-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 the global energy industry.

And most recently served as CEO of AEI 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 five-year plan.

From a process and timing perspective, I would like to add that the board conducted an exhaustive search for the CEO position and received significant interest from a number of candidates.

We were 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 the fit with Jim, in terms of his market knowledge and experience, leadership skills and culture alignment, was the ideal.

Jim has been an integral part of the development of our strategy and five-year plan that we will 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 is 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 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 of First Solar is unrivaled in terms of talent, depth and experience.

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 would next like to discuss our strategy and five-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 over-investment in 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've 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 the successful execution of our strategy requires that we focus our time and our resources on our new markets.

In the future, subsidized markets may make up a part of our total sales with 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 three things.

First, be prepared to price solar electricity at levels sufficient to make solar-generated electricity a compelling value proposition and trigger the new demand without 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.

And I would like to explain how First Solar is uniquely capable of delivering on each of these three requirements, starting with pricing.

On slide 8, we give some indications of the major components of the solar power products.

And how each can impact LCOE.

The price of solar electricity is determined by the cost of capital, total installed system costs, and project development costs, together with the irradiance level of a specific site.

As you can see from the slide, the evolution of LCOE for any market and specific site is a multivariate and complex relationship.

And LCOE is highly sensitive to project cost of capital.

We believe solar electricity costs in the range of $0.10 to $0.14 a kilowatt hour will be sufficient to trigger new demand in open sustainable markets.

We're planning to achieve these price levels in two ways.

First, as shown on slide 9, successfully executing our system cost reduction road map 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 road map is not free of risk, 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 processing product improvements, albeit with a greater degree of risk.

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.

A 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 are 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 that employ our modules.

Including, since 2008, power plants that we have designed, engineered and constructed.

Since 2009, we have employed our own O&M function to monitor and analyzer our utility-scale power plants in the US, supported by a sophisticated utility grade network operating control center.

Over the course of this experience, we've analyzed the performance of literally millions of solar modules and numerous system designs and sizes, and across many different environmental conditions.

We have used this extensive data and 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 many 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 gigawatt AC of solar power plants that have received debt financing rated investment grade, exceeding $1.5 billion in the aggregate.

And an approximately two-thirds 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 have 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, the 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 gris management costs.

Solar power has several properties that differ from conventional power.

Unlike conventional power it cannot be dispensed at will.

It must be used when available or not at all.

Unlike conventional power it is intermittent.

It is only available when the sun is out.

And finally its 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 that must instantaneously balance supply and demand on the grid and regulate both its fluctuations in order to maintain grid stability.

At the low penetration levels typical of most solar subsidy programs and distributed 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.

Third, 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.

And keep us at the forefront in this key area.

Turning to slide 12, in summary, to the question of how will you win business with your strategy, the answer is, by delivering on the three key requirements to these markets.

A market-clearing solar electricity price, demonstrated reliability, and grid integration capability.

First Solar is well-equipped in all of these areas.

To the question, how will you compete against PV component manufacturers or other system integrators that use cheap silicon-based panels, the answer that 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 a multiple gigawatts and installations.

Our targeted customers are technically adept, risk-averse, and sophisticated.

They have and will continue to appreciate the unique value that we provide.

Turning to the five-year plan, the cornerstone is our existing multi-year project pipeline.

As shown on slide 13, our existing capital 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 2014.

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 capacity with our current factories and some of our spare equipment.

With essentially all of the revenue coming from sustainable markets.

We are now focusing on the new markets although we are still early in the process.

As shown on slide 15, we're screening markets based on a combination of power demand, price level, availability of other power sources, and irradiation levels.

Slide 16 present our financial targets for 2016.

With several important assumptions.

First, we're assuming we're going to be able to sell 2.6 gigawatts to 3 gigawatts DC of power plants in a 100% vertically integrated business model where we do everything from development through sale of the power plant.

The second, we assume we would 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 are likely to deviate from the assumptions on slide 16 in a number of ways, as we execute the plan.

For example, we would 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 70% 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 would 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 plant 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 four production lines in Frankfurt-Oder for the month of March.

In addition, we did not run production during the Q1 Malaysia holiday period, as we have historically.

Finally, in support of our efficiency road map, 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 plant improved to 12.9%, which is up from 12.6% last quarter.

We continue to make progress in our technology road map, as the average line conversion efficiency for the second quarter to date is 12.5%, up 0.1 percentage points over the first quarter.

And the current efficiency rate of our models produced on our best line is 13.1%.

Module manufacturing costs per watt for the first quarter was $0.73, which is unchanged quarter over quarter.

The cost includes a $0.03 headwind from plant under-utilization and factory downtime.

As our plants run at full utilization, our module manufacturing costs per watt would have 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 under-utilization.

The restructuring actions we have announced on April 17 will help improve the plant utilization rate going forward and reduce the under-utilization headwind on a 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 module 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 megawatts 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 project in Nevada.

NextEra completed the acquisition of the 40 megawatt AC Sinclair project in Canada.

In April, Exelon received the first funding from the DOE to finance the 230 megawatt AC Antelope Valley project in LA County.

Which eliminates the risk 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.

Last week NRG and MidAmerican celebrated Agua Caliente's first 100 megawatts being delivered to the grid, making in North America's largest PV plant in operation.

Today MidAmerican and First Solar held a groundbreaking celebration at Topaz, marking the 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 onto 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 a 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 for third-party module ASPs to continue to decline 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 to 2009 manufacturing excursion.

Of which $27 million affects cost of goods sold.

$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 on 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 required remediation.

We have now processed all the claims, and based on our completed analysis, we have approved an additional $31 million to remediate those plants.

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 we claimed through remediation.

Regarding the restructuring actions.

Upon completion of these initiatives, we will reduce our ongoing annualized costs by between $100 million to $120 million post 2012.

Split equally 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 margins 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 a 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 of 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 made to enable growth in sustainable markets.

As we exit 2012, we anticipate our operating expense quarter 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 a look of our GAAP EPS to our non-GAAP EPS, which excludes the impact of nonrecurring items from 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 system 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 US Department of Energy.

With the revenue and associated gross margins for these projects, we anticipate that our results sequentially will improve significantly.

Turning to slide 22, I will 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 the increase in unbilled revenue 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 receivables by better aligning our project construction billed to the underlying contact 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 business to support increased project activity.

Both for modules and balance of systems.

And lowered third-party module demand as we did not sell 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 costs increased as we constructed projects we have sold, but for which we cannot recognize revenue yet.

As reminder, when a project sells, the project asset turns either into revenue or deferred project costs, 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, AVSR received the first advance of a loan guarantee by the US 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 German credit facility.

These payments have 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 will have serious financial repercussions.

Ultimately, we feel the restructuring initiatives we have taken in recent months will enhance our balance sheet.

And we have the financial wherewithal to undertake those restructuring initiatives.

We will be constructing the projects 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 bring me to our updated guidance for 2012, starting with the assumptions behind our guidance, as shown on slide 23.

As we mentioned in our April restructuring call, we expect demand to range between 1.5 gigawatts to 1.8 gigawatts.

And our average module manufacturing costs to range from $0.70 to $0.72 per watt.

Our expectation for average module efficiency of 12.7% is 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.

Which 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 initiatives, 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 at $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 plant in Vietnam and Mesa, which we are required to complete.

In addition, we will continue to invest the required CapEx to achieve our module efficiency road map.

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 the 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 received from Desert Sunlight.

And $80 million to $120 million or 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 three 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 to 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)

Stephen Chin, UBS.

This is [Marvis Henri] for Stephen Chin.

A quick question about five-year plan -- your next five-year plan assumes about additional 5 gigawatts a project pipeline.

Can you give us some sense of what investment is required for that?

And what the geography breakdown could broadly look like?

Thank you.

We didn't have a pipeline assumption, really, on the five-year plan.

What we assumed, what we are targeting is -- as a baseline, anyway -- for the full-year 2016, annual installations of 3 gigawatts.

And the way we got to that was simply to try to take our existing production capacity, including the spare tools, and maximize that.

There are a lot of unknowns here.

If things break a more favorable way, it will be larger.

But we had to have a baseline to try to size resources financially and otherwise.

As far as the capital to execute it -- a lot of that is going to depend on the model, the partnership, 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 through these projects.

And we did say -- and as a range of understanding the capital requirements, putting aside the capital that we may need to make in order to create the various relationships and alliances in different markets -- is that the capital expenditures would be the range of $150 million to $300 million on an annual basis.

Which, the way I would look at that is -- on the front of the curve, it's going to be lower.

And then on the back end of the curve, as we get closer to 2016, you'll see it ramp up a little bit.

Sanjay Shrestha, Lazard Capital Markets

Two-part question for me.

First, are you in active discussion right now, Mike, when you talk about the JV partnership as a way to 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 is the status of that?

Thank you.

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 markets in which 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 are 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 have boots on the ground and are in advanced discussions with a number of parties.

As it relates to the LTM claims, as I indicated, we have now processed all of the claims.

We determined which ones would require remediation, and we have provided for those claims.

We believe that the evaluation that we have done, that we have completed, has been very thorough.

And we do not believe that a meaningful amount, if any, of those unremediated claims would then determine to be later have to require remediation.

Amir Rozwadowski, Barclays Capital.

Good afternoon, Michael, David.

And certainly, congratulations on your new role, James.

If we talk a bit more about 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, can you give us a sense as to how we should think about the progression of the 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 how we should think about that longer-term.

I think what you'll see as we progress through the five years is, in the near term, there is some remaining activity to be conducted in the US.

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 is 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 will be able to, over time, as we get a deeper understanding, be able to give some visibility as to what the pipeline opportunities look like in these new markets.

So it will be a gradual transition over the five-year period.

Brian Lee, Goldman Sachs.

On the 3 gigawatts by 2016 -- what market share would that imply you capturing of the utility-scale market?

And how does that compare to your positioning in the US 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 feel the competitive differentiation for you in building systems is, over the longer run?

Thanks.

The estimates of the total market size in 2016 are a bit all over the map, depending on which source you look at.

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 is less than a 10% total market share.

If you look at our participation in the US market, 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 fields versus distributed, it would require a greater market share in the free field segment.

But that is 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 is significant potential to increase that demand from currently projected levels.

But we are 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 is 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 a power plant; 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 will have a competitive advantage.

However, that does not mean that we think we're going to have a cost disadvantage.

As we execute our cost road map, 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 a quality characteristic associated with it that give us the opportunity to win.

Timothy Arcuri, Citi.

I have a question on these partnerships that you were actually talking about.

For the 2016 guidance you're giving us, you're saying 2.6 to 3 gigawatts.

But it sounds like that is based on basically covering your module production.

But then you were 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 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 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?

Thanks.

I'll take the easy one first.

The warranty provision is associated with our forward-looking projection of modules that are installed.

At that point in time reserves are provided for the anticipated return rate for those modules that have been shipped and are installed, and are actively being used by 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 will happen going forward.

Again, that was done as a forward-looking view.

We do not provide for warranty as we incur it.

We provide for warranty as we anticipated the return rate associated with product that had been shipped.

In terms of partnering relationships in these markets, the current focus in 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 into demand in these markets, we could see broader partnering arrangements that included manufacturing, but that is not something we have visibility to at this point.

Hari Chandra, Auriga.

This is regarding your five-year plan.

It presumes 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.

What would prevent that into leaking into downstream, as you go into fully, as you transition fully into nonsubsidized markets by 2016?

So would you not be still muddling around with the same dynamics as you go forward?

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 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.

And that will reserve an element of the market, if you have these irrational market participants, for the quality provider.

So 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 on the demand side -- I think the question was around dependency around policies and subsidies.

Again, our strategy is to go in and to enable and create markets without that dependency.

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 will be able to do that.

Vishal Shah, Deutsche Bank

This is actually Susie Min calling on behalf of Vishal.

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?

Thank you.

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

Kelly Dougherty, 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 can 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 and 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.

Mehdi Hosseini, Susquehanna International

Yes -- as a follow-up to the previous question, I am 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 being finalized with connection -- they're starting $0.15; are in the high single digits.

So does that mean that you are making a top-down assessment that the market outside the US are going to be much bigger and much higher than the PPA rates?

Or is there something I am missing here?

Just the LCOE on slide 16 and what is going on in US don't add up.

Yes, Mehdi -- I think the PPA pricing you're seeing today, at least if it is the same data set we are looking at, is a function of RPS program, for example, in California, with an ITC, and 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.

If you 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 kind of a market setting, based on the work we have 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.

Josh Baribeau, Canaccord.

Can you remind us what the provisions for a 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?

I don't want to get into to much detail around the specifics of that.

But you have to remember that tax holiday was originally generated when we began our initial production in KLM, which was initially, I believe, four lines when we started production.

So I think if you look at it from that perspective, we've got 20 lines up and operational.

We've given a plan that we will generate somewhere between 2.6 and 3 gigawatts of demand, which we stated we are going to need KLM essentially at capacity for the foreseeable future.

Chris Kovacs, Robert W. Baird.

In the past you guys have talked about some demonstration projects you are doing in China.

And obviously you have Ordos going on there.

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 stuff that's still in early development work?

But just 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.

There 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 are 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 will be able to provide that type of information.

But I just think we are 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.

We want to thank you all for your participation.

You may now disconnect.