A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

National Renewable Energy Laboratory 

Innovation for Our Energy Future 

Experience Scaling-Up 

Manufacturing of Emerging 

Photovoltaic Technologies 

G. W. Braun 

En-Strat Associates 

Darnestown, Maryland 

D. E. Skinner 

DES Associates 

Warrington, Pennsylvania 

Subcontract Report 

NREL/SR-640-39165 

January 2007 

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 
Experience Scaling-Up 

Manufacturing of Emerging 

Photovoltaic Technologies 

G. W. Braun 

En-Strat Associates 

Darnestown, Maryland 

D. E. Skinner 

DES Associates 

Warrington, Pennsylvania 

NREL Technical Monitor: R. Margolis 

Prepared under Subcontract Nos. KLCX-4-44450-03 and AEK-6-66261-01 

Subcontract Report 

NREL/SR-640-39165 

January 2007 

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
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Table of Contents

Authors’ Preface ................................................................................................................. 1 

Executive Summary............................................................................................................ 2 

Introduction......................................................................................................................... 8 

Case Study: Tandem Amorphous Silicon........................................................................ 10 

Visions and Models....................................................................................................... 11 

Cost Models.................................................................................................................. 12 

Cost Evolution Detailed Analysis................................................................................. 13 

Interpretation................................................................................................................. 25 

Future Cost Reduction .................................................................................................. 28 

Case Study: Cadmium Telluride...................................................................................... 32 

R&D to Production Engineering Phase ........................................................................ 32 

Legacy Manufacturing Plan.......................................................................................... 34 

Stage-Gate and Efficiency Stretch ................................................................................ 39 

Commercialization and Manufacturing ........................................................................ 41 

Thin-Film Costs............................................................................................................ 47 

Thin-Film Technology and Manufacturing Ramp........................................................ 50 

End Notes.......................................................................................................................... 52 

 iii
Authors’ Preface 

We had close visibility to two important generic photovoltaic technologies at particularly 

revealing stages of development, i.e., the stages between R&D and stable commercial 

production and profitable sales. 

After considering and incorporating comments on our original draft, we feel the need to 

be very clear about what this report attempts and what it does not attempt. Based on two 

historical cases, it attempts to shed light on the difference between: 1) costs and 

schedules validated by actual manufacturing and market experience, and 2) estimated 

costs and schedules that rely on technology forecasts and engineering estimates. The 

amorphous Silicon case also identifies some of the costs that are incurred in meeting 

specific market requirements, while the Cadmium Telluride case identifies many of the 

operational challenges involved in transferring R&D results to production. 

We do not claim that the experience reported is typical of what may be expected in other 

cases of thin-film PV commercialization. Nevertheless, it may be illuminating in general 

terms, i.e. costs and timescales involved in replicating favorable R&D results in the much 

more demanding context of commercial production. The problems we encountered may 

not be unique to the cases we discuss; they may be relevant to parallel and future efforts. 

Some in fact are generic concerns, e.g. the problems of scaling from R&D results to 

larger area products in high volume production. Likewise, managing the interplay 

between markets, technology and manufacturing is a challenge every new PV enterprise 

must face, and the challenge is compounded by inherent differences between incumbent 

products and new offerings. Other problems probably were unique, e.g. some specific 

product finishing costs dictated by emerging and innovative market applications. 

We were not tasked to present a management case study. It is impossible to illuminate all 

of the considerations that enter into investment and operational decisions in a competitive 

environment. We caution against inferring that easy choices were missed. We know of 

none. 

The transition between R&D and commercial success takes a great deal of time and 

money for emerging energy conversion technologies in general. The experience we 

report can be instructive to those managing comparable efforts, and to their investors. It 

can also be instructive to R&D managers responsible for positioning such new 

technologies for commercial success via the U.S. Department of Energy Solar 

Technology program. We commend Dr. Robert Margolis’ recognition of the latter 

opportunity, and we appreciate reviewer comments that led to clarifications and 

improvements in our report. 

Gerry Braun and Doug Skinner 

 1
Executive Summary 

At the end of 2002, a first-tier PV module manufacturer, BP Solar, announced its 

decision to abandon two leading thin-film PV manufacturing scale-up and 

commercialization efforts. These intensive efforts spanned a decade and were the 

culmination of private-sector R&D investments totaling a few hundred million dollars 

during the prior decade. Combined capital expenditures approached 100 million (2005) 

dollars and were supported by significant U.S. Department of Energy (DOE) and 

National Renewable Energy Laboratory (NREL) R&D expenditures. In both cases, hard 

challenges were met – and a wealth of experience was gained. 

In late 2004, a study was commissioned to review what was learned specifically about 

cost, i.e. to: 

• Identify real-world cost models that can be used to evaluate comparable emerging 

technologies 

• Identify decisions and cost drivers that may be influential in other cases 

• Understand the reasons actual product costs may have exceeded original estimates 

• Apply related insights to evaluate the potential for future cost reductions using 

comparable technology 

Two cases were considered: 

1) Introduction of large-area tandem amorphous silicon (a-Si) thin-film modules into 

the global PV market, and 

2) Transfer of cadmium telluride (CdTe) thin-film research results to a production 

environment. 

Recognizing that “time is money” in matters of this sort, it is instructive to place cost 

experience in the context of R&D and commercialization phases and their duration. 

Figure EC-1 below provides a program chronology for the two cases. 

 2
The chronology suggests that the average time elapsed between the start of the R&D 

phase and program termination was roughly 20 years for two cases that stopped short of 

full commercial success. While this result may not be representative of an entire class of 

technology, or other on-going cases, it does provide potentially useful benchmarks. 

Tandem amorphous silicon summary 

The tandem amorphous silicon commercialization efforts began with funding and 

construction of a manufacturing plant intended to produce 10MW per year. Product 

efficiency, plant throughput, and yield shortfalls limited actual realized capacity to 

around 6MW per year. 

The commercialization effort was driven by three dramatically different market strategies 

at different stages: 

1) The original strategy (internal sales of frameless and otherwise unfinished glass to 

glass laminates for large privately financed power projects) proved infeasible.1 

2) The second strategy (competition with crystalline products for market share in all 

major market segments) proved feasible, though financially unattractive, under 

the circumstances. It required significant product development and inline process 

work.2 

3) The third strategy (internal sales of a specialized building integrated PV (BIPV) 

product) was temporarily successful and also required significant product 

development and manufacturing process enhancements. 

Factory and support organizations struggled to support the strategy changes. Related 

customer and internal company coordination posed significant challenges. 

Cost models evolved toward greater detail but did not change in basic structure. Cost 

forecasts did change significantly. Some of the significant individual changes were 

independent of product specification; including those driven by the inability to achieve 

originally forecast conversion efficiencies, line yields, staffing levels, depreciation, and 

other fixed costs. Original material cost estimates held up fairly well. 

Other significant changes were driven by the above market strategy changes, as reflected 

in product specifications. The first strategy change resulted in a requirement for a 

product line with nominal voltages and other product features compatible with typical PV 

end uses at the time. These features included: 

• Framing and strengthened glass for robustness, 

• Factory-installed industry standard cables and connectors, and 

• Improved encapsulation and edge insulation as necessary to meet various safety 

and product life qualification and certification processes and standards.3

 

The second strategy change introduced the requirement for “vision glass,” i.e. semitransparent laminates with special edge connectors suitable for use in canopies and, 

ultimately, windows. 

 3
Both market strategy changes involved trade-offs among marketing, technology, 

engineering, and manufacturing. Some trade-offs would have been better and more 

economically manageable prior to production rather than during an extended production 

ramp. For example, the transition to processing strengthened glass was especially slow 

and costly – and never fully executed. In the meantime, both factory and customers dealt 

with the problems of material more susceptible to breakage and crack propagation in 

handling, shipping, and long-term operation than competing products already in the 

market. 

The owners of the commercialization effort and its assets probably considered the cost 

experience analyzed here in deciding to abandon the effort. The original plan called for 

the prototype factory to be replicated extensively while being upgraded with new 

deposition technology. The vision was to achieve hundreds of MW/year of cumulative 

manufacturing capacity over in the decade following successful prototype factory 

operation. Prototype factory performance could not have been regarded as successful 

relative to the original targets; accordingly, the original strategic vision had been 

abandoned well before the prototype factory itself was abandoned. A break-even factory 

operation might still have survived based on yet a third market strategy change, i.e. to 

focus on markets involving single modules vs. larger arrays. 

A recommitment to this original vision for the technology, as some have recently 

proposed, might reasonably target manufacturing costs in the same range as originally 

forecast, i.e. $0.75/W in 1995 dollars for unframed annealed glass laminates lacking 

cables and connectors. Success would require achievement of the originally targeted 

efficiencies as well as the ability to spread fixed costs over multiple, identical new 

factories once the cost target could be validated in a prototype plant. Success in 

achieving these costs would not guarantee market success. One thing experience makes 

clear is that the existing and foreseeable markets want products more robust and 

completely featured – and, therefore, significantly more costly – than the product targeted 

more than10 years ago. 

A different original vision, involving a more appropriate choice of entry markets, might 

have yielded different results. The appropriate entry market for tandem amorphous 

might, for example, have been the remote power market, ironically a market segment in 

which its sponsor had excellent access. Instead, applications in the targeted entry market, 

large-scale power plants, would have not only required near-perfect execution in the 

scale-up phase but also significant subsequent technology and engineering upgrades.4

 

 

Cadmium telluride summary 

The cadmium telluride commercialization effort was launched at a plant originally 

intended to produce 10MW of single-junction amorphous silicon product annually.5 The 

project replaced front-end amorphous silicon deposition equipment with cadmium 

telluride deposition equipment. Unlike the above tandem amorphous silicon effort, the 

effort was not preceded by pilot manufacturing and sale of small area modules using the 

same basic film deposition technology. The market vision was relatively under-

 4
developed at the time scale-up was committed, although the product and manufacturing 

vision were well informed by previous single junction amorphous silicon production 

experience at the same site. The experience, however, did not overcome the cost, 

schedule, and performance challenges associated with unique chemical deposition 

processes and equipment. 

In support of investment decisions, detailed manufacturing cost models were developed. 

In contrast to the tandem amorphous silicon case above, forecasted costs changed in a 

favorable direction during the preproduction phase as significant efficiency 

improvements – higher watts per unit – were achieved during process development 

before full-scale production was attempted. Subsequently, because the endeavor was 

abandoned before routine shipments of commercial product could be achieved, the cost 

model and forecasted costs did not evolve further except to accommodate various module 

engineering changes related to encapsulation, cabling, and connectors; and strengthened 

glass and framing options. Product stewardship costs were a major consideration, based 

on market information suggesting that arrangements would be needed to support “cradleto-grave” or even “cradle-to-cradle” product recovery, disposal, and/or recycling. Again, 

forecasts were made but were not validated by commercial experience. 

The cadmium telluride effort was instructive regarding the time and cost required to 

transfer limited R&D processes into full-scale manufacturing. Examples include 

accommodating the realities of local labor markets, and the losses of continuity and 

technology support when originating R&D staff is not co-located with nor accountable to 

the commercialization project manager. The effort took place under conditions not likely 

to be repeated. The unique circumstances of a corporate merger and related downsizing 

activity had an impact. There was a need to convert an incomplete R&D result to 

complete engineering reality on a compressed schedule that had no margin to 

accommodate technical setbacks or accomplish inevitable process and engineering 

changes. There was also no time to investigate and design around phenomena that had 

not been exposed in the R&D process (e.g., anomalous differences between outdoor and 

indoor performance) nor was there time to adjust product design and process engineering 

in order to pass qualification tests and achieve necessary product certifications. 

Perspective 

The reviews summarized here focused on cost experience. Some cost-related 

observations common to both cases include: 

• First-order thin-film PV cost drivers are module electrical efficiency and process 

throughput6; second order is production yield; third order is economies in materials 

and labor; there may be no single dominant driver7. 

• Both efforts validated the intrinsic ($/Wp) cost advantage of thin-film PV, i.e. unlike 

crystalline, thin-film’s intrinsic material costs are largely (around 80%) associated 

with materials other than the active PV materials. However, this advantage can be 

overwhelmed by other fixed and variable manufacturing costs (capital and labor) 

when thin-film efficiencies fall well short of crystalline efficiencies.8

 5
• Large-scale thin-film manufacturing requires major financial investment over several 

years. Initial capital investment in a factory scaling up from R&D results can be as 

high as $2-3 per watt for a 10MW/year thin-film factory; capitalized operating losses 

on the way to mature full capacity operation can be in the same range, in which case 

the financial breakeven horizon may be pushed out a decade or more beyond its 

original target. 

• The manufacturing cost targets of the two efforts reviewed were quite aggressive yet 

well above $1/Wp (2005 $) for glass-glass laminate modules. The review did not 

suggest ways these goals could have been achieved with the technologies at their 

stage of development when the factories were abandoned. Targeting installed costs 

in the same range for generically similar products from new factories9

 lacks 

grounding either in experience reported here or foreseeable technology 

improvements. 

Low cost per Watt is a necessary, but not sufficient, condition in order for thin-film 

modules to take power array sales away from crystalline modules; the generically lower 

power density of thin-film modules imposes greater balance of system costs which scale 

with the efficiency deficit. The effect varies with application. In some applications thinfilm modules having significantly lower efficiency than crystalline counterparts cannot be 

priced low enough to off-set the balance of system cost penalty without jeopardizing the 

financial viability of the manufacturer. Regardless of efficiency, thin-film products 

lacking a track record in the market may not command the same unit price ($/W) the 

market is willing to pay for familiar and proven products having equivalent 

specifications. Thus, there are significant barriers to market entry facing new PV module 

offerings that are not addressed by the current study. 

Cost experience cannot completely be separated from other observations, which include: 

• Good R&D and pilot production using R&D equipment does not guarantee 

commercial success – both tandem a-Si technology and CdTe technology achieved 

impressive efficiency targets over short time periods, but the knowledge base needed 

for high volume manufacturing at competitive costs was still in development at the 

time of production start-up and even when each effort was concluded. 

• The stage-gate management of a developing technology does serve to emphasize 

critical performance measurements and to focus the management of the project; 

significant resources in time, equipment and staff may still need to be expended 

before a clear path to commercial success or a shutdown decision can be reached; in 

both thin-film cases covered here, the parent enterprise was already producing 

technically competitive products, thus reducing the incentive to persevere in dealing 

with set-backs and limitations. The bar was high for both challenger technologies. 

• Initial product specifications in both cases were consistent with minimizing factory 

value-added features and therefore manufacturing cost, envisioning that mounting 

system and interconnection designs suitable for glass-glass laminate modules would 

be prepared by others. More recent module industry trends are actually maximizing 

factory value-added features in pursuit of plug-and-play functionality to minimize 

installation costs and complexity.10 

 6
• Emerging PV technology should aim to meet the requirements of existing markets, 

unless it offers an extremely inviting competitive advantage in an emerging market. 

Managing both market risk and technology risk is much more difficult than managing 

one or the other independently. 

• PV markets demand results that research per se cannot deliver. This is especially true 

if, as above, the plan is to meet the requirements of existing markets. In this case, 

product development and engineering to meet industry standards (for reliability, 

safety and product life) must precede, not catch up with, factory operations. 

• Manufacturing start-up requires a skilled and dedicated work force; technicians and 

operators generally need to be trained by the enterprise. Depending on local and 

national conditions, recruiting of technical staff can be problematic when local 

applicants with necessary specialized knowledge cannot be identified; location in 

strong industrial economies makes it easier to find second- and third-tier employees. 

• It is encouraging to note that some other glass-metal, thin-film product 

commercialization efforts appear to be progressing well. Partnership with outside 

agencies can make substantive contributions in bringing a new technology on line; in 

terms of the cadmium telluride effort, there were demonstrable gains in technology 

and time as the result of working agreements with NREL and the Institute for Energy 

Conversion. 

 7
Introduction 

As part of reviewing the U.S. DOE Solar Program’s technical and economic targets for 

PV technology, it is important to place future projections in the context of real-world 

experience. While current PV production is dominated by crystalline silicon technology, 

there are a number of emerging PV technologies that could gain significant market share 

in the future, if they can successfully compete with crystalline technology on price, 

performance, and overall functionality and aesthetics. Estimating the potential for these 

emerging technologies to realize projected cost reductions is more of an art than a 

science. Thus, examining the available experience with scaling-up PV module 

manufacturing for a number of emerging PV technologies can help to build a sound 

foundation for evaluating the potential for these emerging PV technologies to meet the 

Solar Program’s technical and economic targets. 

In late 2002, two leading thin-film PV manufacturing scale-up and commercialization 

efforts were abandoned by a first-tier PV module manufacturer (BP Solar). This report 

will refer to them variously by location, technology, and brand as follows: 

1. A tandem amorphous silicon (a-Si) PV module factory, dubbed by its owner as 

TF1, was built at Toano, Virginia, (near Williamsburg) based on several years of 

pilot manufacturing of smaller single-junction aSi modules at a combined 

research and production facility in Newtown, Pennsylvania. The tandem a-Si 

modules shipped from Toano were branded generally as Millennia. 

2. A factory was assembled at Fairfield, California, by converting a factory 

originally designed to produce single-junction amorphous silicon modules to 

instead produce cadmium telluride (CdTe) PV modules using a technology known 

internally at BP Solar as Apollo. 

These two efforts afford a unique opportunity to examine such scale-up and 

commercialization experience without hazard to ongoing private-sector initiatives. 

Efforts over a 5- to 10-year scale-up period were reviewed in order to: 

 

• Trace the evolution of production cost models; 

• Develop a chronology of decisions made that influenced manufacturing cost; 

• Examine the factors that drove changes in projected cost estimates; 

• Evaluate the differences between realized cost and expected cost in order to 

gain insights into the reasons for divergence between these costs. 

• Identify key factors that influenced realized cost and expected cost (such as 

changing market requirements, warranties, qualification processes, the degree of 

factory vertical integration, etc.); and 

• Draw experience-based insights in order to estimate the potential for future cost 

reductions in these technologies over the next 10-15 years. 

The available experience must be understood as incomplete. The Apollo CdTe factory 

operated in an extended start-up mode only; the Millennia tandem a-Si factory was 

 8
ramped up over a period of years to operate at full staffing and a capacity of several MW 

per year – though not at its design capacity of 10MW per year. Nevertheless, valuable 

and still relevant cost experience and practical lessons were learned at both locations and 

are presented separately in subsequent sections.11 

 9
Case Study: Tandem Amorphous Silicon 

A factory (to be referred to hereafter as TF1) was funded, constructed, staffed, and 

operated for a few years; and its initial commercial products (to be referred to hereafter 

by their brand name, Millennia) were shipped to customers worldwide. However, (see 

Figure 1) TF1 never operated close to its intended capacity, nor were product 

specifications and product mix consistent from year to year. As a result, available cost 

data reflects the status of a work in progress, not by any means the statistics of a mature 

manufacturing operation. Trends are discernible – some cost elements stabilized nicely – 

and some favorable cost trends emerged. Some specific quantitative results are 

generically representative, but all reflect a variety of interactive circumstances and design 

and operational choices, the composite of which is unlikely to be precisely replicated. 

Figure 1. TF1 Planned vs. Actual 

Shipments

0

5

10

15

1997

1998

1999

2000

2001

2002

Year

MW 

Actual

Plan - 7/97

Some words of perspective are necessary before turning to the analysis. 

First, deposition of amorphous silicon can be accomplished my multiple methods on 

multiple substrates using deposition recipe and device structure designs that are nearly 

unlimited. The basic design used for Millennia involved deposition on a tin oxide coated 

glass surface using an in-line process, with encapsulation of the film accomplished by 

laminating the film between two glass sheets bonded together with a layer of ethyl vinyl 

acetate encapsulant. The relative advantages and disadvantages of this approach vs. 

others under development at the time are significant and beyond the scope of the work 

reported here. The advantages were demonstrated in commercial practice. The 

 10
disadvantages may be inferred from sections of the report describing market strategy, 

process and module engineering changes required during the commercialization process. 

Second, the TF1 experience brought together unique and powerful capabilities and 

resources under qualified management. In the areas where the organizations involved fell 

short, the lack was not in the organization, its experience or its leadership. The attempt 

was as well-positioned for success as possible at the time, drawing on extremely strong 

and patient corporate ownership, a foundational 15-year $200 million R&D investment 

resulting in world-leading organizational experience and competency, and the technical 

and business infrastructure support of the largest U.S.-owned PV manufacturer. 

However, the challenge was much greater than anticipated by investing and supporting 

organizations.12

Third, U.S. PV R&D programs have usefully turned their attention to cost, especially 

“system-driven” cost. In parallel, there has been an equally useful exploration of 

economic value by leading PV analysts. The TF1 story features the interplay of cost and 

value and is particularly instructive in that regard. In setting initial targets, nearly every 

parameter related to customer value was adjusted to minimize manufacturing cost, at 

considerable sacrifice to product attributes of standard crystalline modules. As a result of 

cost minimization on the module side and extremely aggressive assumptions on the 

system side, extremely aggressive installed costs were forecast by the project’s sponsors. 

When it became necessary to adjust the factory’s products to compete for a share of less 

ideal, but already established – or at least emerging – markets, manufacturing costs 

increased incrementally for a number of market- and system-driven reasons. Unframed 

laminate costs were already higher than targeted because of substantially lower than 

targeted efficiencies. When later it became necessary to exploit unique features of the 

technology to capture large special orders, further significant costs were added. The 

“system driven” added costs in both cases are sometimes overlooked in analyses that 

focus on process- and efficiency-driven core product unit ($/W) costs. The result can be 

“apples and oranges” comparisons between functionally non-equivalent products. 

Visions and Models 

Business visions and models changed as experience accumulated. 

First Business Vision – Solar Farm Deployment and “Super-Large-Scale” 

Manufacturing: The initial view of TF1 was that it was to be the sole source of module 

supply to a new business unit chartered to develop, design, and finance central solar 

power plants and other grid-tied PV applications. At the time, the initial vision was 

revolutionary and hinged on unprecedented manufacturing scale-up in support of large 

projects that were to create the necessary demand. The related business model 

anticipated forward integration from module production through the sale of electricity. It 

hinged on a pre-negotiated transfer price (set at $0.75/Wp), according to the terms of the 

joint venture that funded the factory and the specification for the product to be delivered 

(to the project development business unit) at this transfer price. 

 

 11
Validation of this business model failed. No solar farm projects achieved financial 

closing, and thin-film modules meeting the intended specification would not have been 

available to them if they had.13

Second Business Vision – Supplant Crystalline in Emerging High Growth Markets: 

Accordingly, TF1 was re-cast in the role of supplying and enhancing an ongoing 

crystalline PV module manufacturing business (Solarex1) by introducing a new product 

that promised lower production costs and, therefore, enhanced the profitability and 

growth potential of the original business. It was accepted that this would lead to capping 

Solarex crystalline capacity, while thin-film capacity expanded to meet market growth. 

The vision was founded on internal Solarex manufacturing scale-up forecasts completed 

in 1994 showing that thin-film manufacturing costs would level out well below costs of 

polycrystalline modules, thus providing a new technology platform for the already 

established module manufacturing business. The related business model anticipated 

forward integration from module production to the sale of systems, with internal module 

sales supplemented by sales through distribution. The model evolved pragmatically – 

product variations were added opportunistically with a goal to fill the factory, as well as 

profitably satisfy the requirements of existing distribution customers and emerging ongrid markets. 

 

Third Business Vision – “The Future is BIPV”: The third and final business vision 

tacitly conceded that the path to decisive cost advantage vs. crystalline would, at best, be 

longer and less certain than expected. Exploiting the ability to alter the visual and optical 

specification of Millennia modules, it incorporated aspects of both preceding visions, i.e. 

sales of a single special-design product to a sister business unit, i.e. BP Retail, along with 

sales of this new product (and the existing product line) to external customers in 

emerging BIPV market segment. The related business model was a hybrid between the 

two prior models, differing from the original in emphasizing a revolutionary premium 

product for captive customers vs. a cost-engineered economy product unsuited to the 

existing external market. 

These models influenced key related corporate functions – including sales and marketing 

and R&D. They did not directly affect intrinsic costs of the basic product platform, but 

they did significantly affect finished product costs in each case. 

Cost Models 

The core cost model supporting all three business visions and models was simple and 

traditional. Consistent with the PV market at the time, its primary metric was the cost of 

a finished module divided by product nameplate rating in peak direct current Watts. 

Starting with a single product intended for a single customer, product variations 

expanded to the point that the TF1 product line essentially mirrored the Solarex 

crystalline product line in meeting a range of segment-specific market requirements. 

 

1

 Solarex was founded independently in 1973, purchased by Amoco in 1983, and became a business unit of 

Amoco/Enron Solar, a joint venture between Amoco and Enron formed at the end of 1994. 

 12
This created the need for a more detailed (but not fundamentally different) cost model 

able to account for differences among products having different electrical characteristics, 

mechanical specifications, and framing and electrical termination designs (see Table 1). 

Subsequent expansion of the product line to include and emphasize “vision glass” 

modules (to be referred to hereafter by their brand name, PowerView) required only 

incremental changes to the cost model initially, because the initial PowerView products 

were sized and rated in the same range as existing products. Had such premium products 

succeeded in the broader building products market, a manufacturing cost model 

facilitating trade-offs between power output and optical specifications eventually would 

have been needed. 

$/Wp (1) $/module

Varible Costs 

Direct Labor (2) 

Materials (3)

Labor Overhead (4)

Total Variable

Fixed Costs (3) 

Utilities/Rent/Interest 

Indirect Labor

Depreciation (6) 

Total Fixed 

Total Cost (FOB factory)

Notes:

1. Wp = nameplate power, i.e. instantaneous module power under standard test conditions

2. Yielded hours per unit times DL rate per hour divided by Wp

3. Yielded unit cost divided by Wp

4. Yielded hours per unit times O/H rate per hour divided by Wp

5. Allocation in $/Wp reflecting corporate accounting model, actual costs and cost allocations

$/Wp (1)

Table 1. Cost Model

6. Depreciation life of manufacturing equipment taken as 15 years. 

Cost Evolution Detailed Analysis 

Major Product and Cost Model Changes 

The cost model in Table 1 can be used to analyze the nature and impact of specific 

manufacturing and product-line changes that were implemented over the course of 

commercialization efforts. The model did not change structurally, but its imbedded 

assumptions did evolve. Table 2 expands the model to evaluate the impact of 

manufacturing process changes and experience, as well as product-line changes. 

Representative costs are included – they are experience-based estimates, not actual 

 13
recorded costs. Unit costs are presented in $/Wp, and total costs are also presented in 

$/m2. The following narrative briefly outlines each evolutionary change and its rationale. 

$/m2 

Year Reason for Change Watts Total Chg. Total

Direct 

Labor Matl

Labor 

O/H

Plug 

and 

Play Frame

Semitranspa

rent

Strong 

Glass Power Yield Power

1994 Base annealed HV lam 62 0.04 0.37 0.17 0.25 0.83 64.2

1995 Project re-design/re-est. (1) 56 0.04 0.49 0.19 0.35 1.07 0.24 74.8

1995 Depreciation correct. 56 0.04 0.49 0.19 0.65 1.37 0.30 95.7

1995 Staffing re-est. 56 0.15 0.49 0.19 0.65 1.48 0.11 103.4

1999 Material re-est. 56 0.15 0.51 0.19 0.65 1.50 0.02 104.8

0.0

0.0

1996 Switch to MV 56 0.15 0.54 0.19 0.65 1.53 0.03 106.9

0.0

1999 P&P lam product 56 0.15 0.54 0.19 0.65 0.06 1.59 0.06 111.1

2001 HS lam product 56 0.15 0.54 0.19 0.65 0.06 0.15 1.74 0.15 121.6

2001 Actual module power (3) 43 0.15 0.54 0.19 0.65 0.10 0.15 0.34 0.20 2.32 0.58 124.5

2002 Actual total yield 43 0.15 0.54 0.19 0.65 0.10 0.15 0.34 0.15 0.20 2.47 0.15 132.4

0.54 0.0

1998 P&P framed product 56 0.15 0.54 0.19 0.65 0.06 0.21 1.80 0.27 125.8

2001 HS P&P framed product 56 0.15 0.54 0.19 0.65 0.06 0.21 0.15 1.95 0.15 136.3

2001 Actual module power (3) 43 0.15 0.54 0.19 0.65 0.10 0.21 0.15 0.34 0.20 2.53 0.58 135.8

2002 Actual total yield 43 0.15 0.54 0.19 0.65 0.10 0.21 0.15 0.34 0.15 0.20 2.68 0.15 143.7

0.54 0.0

0.0

2000 BIPV lam product 53 0.15 0.54 0.19 0.65 0.06 0.32 0.05 0.04 2.00 0.47 132.6

2001 Cosmetic BIPV lam 53 0.15 0.54 0.19 0.65 0.10 0.32 0.05 0.04 2.05 0.04 135.3

2001 HS BIPV lam 53 0.15 0.54 0.19 0.65 0.10 0.32 0.15 0.06 0.04 2.20 0.16 145.6

2001 Actual module power 40 0.15 0.54 0.19 0.65 0.10 0.21 0.32 0.15 0.44 0.20 2.95 0.74 147.1

2002 Actual total yield 40 0.15 0.54 0.19 0.65 0.10 0.21 0.32 0.15 0.44 0.15 0.20 3.09 0.15 154.5

Notes:

1. Module power reflects efficiency loss due to CTO outsourcing (-10%).

2. LV and "cut" products were introduced in 98, having higher manufacturing costs and also higher customer value - cost estimates are not included.

3. Actual avg module power was 43W, not 56W, reflecting soda lime vs. low iron glass (-10%), MV vs. HV (-2%), and process transfer loss (-18%). 

4. Throughput and line availability (key fixed cost drivers) limited annual factory financial performance, but are assumed, for estimation purposes 

to have been on target at 25 starts per hour and 7000 hours per year.

5. All costs are consultant estimates based on interpretation of actual experience - no comparable tabulation exists in company files. 

$/W internalized and fully built up (5)

Table 2. Estimated TF1 Manufacturing Costs

Vision Glass

Solar Farm Vision

Supplant Crystalline Vision

Future is BIPV Vision

Plug and Play

Framing

Fixed 

Base

Factory Development 

Commercial Production (2)

Variable Base Variable Delta Fixed Delta (4)

 

Initial Product Functional Specification 

The initial product specification called for a module having a total area of 0.8 square 

meters, stabilized efficiency under standard test conditions of 8% (based on aperture 

area), resulting in a nameplate rating of 61.7 Watts, and a cell width resulting in nominal 

operating voltages above 100V, consistent with the product’s intended use in large “solar 

farm” arrays. 

Target Costs 

In the early stage of joint venture negotiations (May 1994), the first manufacturing plant 

was envisioned as a full-scale prototype of future plants to be rated at 120MW/year. 

Later target production costs for TF1 were remarkably consistent with the initial 

scenarios, even to the extent of assuming identical direct-labor costs. Target fixed and 

variable costs for TF1 were $0.25/W and $0.58/W respectively, consistent with a 

negotiated transfer price between the joint venture’s manufacturing unit and power 

project development unit of $0.75/W (1995$) 

 14
Project Redesign and Re-estimation 

Emphasis in the second half of 1994 was on validating the 8% efficiency target, and also 

on establishing a capital budget. It was not until the joint venture closed at the end of 

1994 that efforts were initiated to develop a project plan, select a site, or select 

engineering and construction contractors. By August 1995, having accomplished these 

tasks, it was possible to re-estimate the project cost based on site-specific information, 

results of process validation, preliminary equipment specification/design/selection, 

further process development, and initial plant layouts. The resulting project capital cost 

estimate exceeded the target budget by about 50%, primarily because the number of 

silicon deposition chambers had apparently been underestimated by 36%.14

Design efforts also failed to validate the readiness of the process and equipment used to 

deposit conductive tin oxide in pilot production, and it was determined that an additional 

tin oxide-deposition furnace would be required. As a result, a decision was made to outsource tin oxide-coated glass and eliminate the coating equipment from the front of the 

line. This decision had major implications for product efficiency and therefore cost (i.e. 

10% reduction and 11% increase respectively), and also major implications for variable 

material cost (i.e. 22% increase), though the eventual effect was thought to be less at the 

time.15 

In addition, revised estimates of Germane2 costs and use resulted in another 11% variable 

materials cost increase. Finally, labor overhead costs were revised upward by 12%. 

The project capital re-estimate would have increased the depreciation component of fixed 

costs by about 40% from $0.15/W to $0.25/W; however, around the same time, the 

original allocation for depreciation – was increased to around $0.55/W, for an overall 

267% increase.16 The latter allocation for depreciation appears consistent with a 15 year 

depreciation period, depreciation schedules consistent with generally accepted accounting 

standards, and plant capital costs in the $30-35 million range, combined with capitalized 

pre-commercial operating costs in the $5-10 million range. 

The target direct-labor estimate, $0.04/W, would have been consistent with plant staffing 

in the 25-30 range, whereas later staffing estimates based on start-up operations and 

initial production put the requirement in the 80-100 range, consistent with a philosophy 

of relying on manual intervention in critical line transitions before moving to full 

automation. Direct-labor estimates ranged somewhat higher but eventually stabilized in 

the range of $0.15/W, a 275% increase from the original target, suggesting that the 

original target may have carried forward without examination from early estimates for 

conceptual plants rated at >100MW/year. 

Re-estimated variable material costs (for full area laminates, i.e. the original target 

product) proved more reliable and were only adjusted upward by a small percentage over 

subsequent years. 

 

2

 Germane is a gas containing Germanium 

 15
Overall, correction of errors ($0.41/W), experience-based re-estimates of various cost 

elements ($0.15/W), and targeting 9% lower product efficiency initially ($0.11/W) 

resulted in a $0.67/W (or roughly 81% increase) in the base cost of the original target 

product, without accounting for the effects of actual vs. targeted line yield and actual vs. 

targeted product efficiency.17 These latter effects, to be considered below, resulted in 

combined incremental additional increases in base cost of $0.70 to $0.80/W, depending 

on the specification of the finished product. Thus, in 1995, the base cost of the product, 

assuming originally targeted line yield and efficiency, increased by nearly $0.70/W. 

Factoring in the effect of actual vs. targeted yield and efficiency results in an additional 

$0.70/W to $0.80/W increase. 

In summary, the reasons for higher than forecast base product cost were: 

1. Underestimates, including direct labor, plant equipment, depreciation and 

material costs 

2. Inability to achieve target product efficiencies and line yields18

Product Specification Changes 

“Medium” Voltage (MV) 

While TF1 was being built, a separate business unit was working to develop large gridtied projects to absorb its output. Meanwhile, efforts were underway among U.S. utilities 

and government allies to promote other PV applications in the United States, including 

smaller grid-tied applications. Though the TF1 product, as specified, was a questionable 

fit with these applications (due to its efficiency disadvantage), emerging grid rooftop 

markets offered an opportunity to deploy relatively large numbers of modules from the 

new factory without “cannibalizing” the existing crystalline module sales. Accordingly, 

proposals were developed that would tap government programs to allow the new thinfilm modules to be offered at a discount and packaged conveniently for use in grid 

rooftop projects. Projects resulting from these proposals ultimately facilitated nearly 

2MW of thin-film module sales19. 

The “high-voltage” thin-film module targeted by the new thin-film joint venture, though 

conceptually optimum for large arrays, was poorly suited to grid rooftop and other nearterm, grid-tied markets. Suppliers of inverters for grid-tied applications in the United 

States were few, and their products were designed to accommodate the electrical 

specifications of typical commercial PV modules.3 Accordingly, a decision was reached 

to introduce a module with cell interconnects running parallel to the long side of the 

module instead of parallel to the short side, as in the high-voltage module. This allowed 

 

3

 Most crystalline PV modules at the time had nominal voltages that were multiples of 12V (i.e. 12V for 

battery charging applications and 24V larger area modules for both battery charging and grid-tied arrays). 

One crystalline manufacturer had introduced a 48V module that was popular in the US for grid-tied arrays, 

and Solarex had a similar design not yet in production. 

 16
for a nominal voltage of 48 volts (vs. the original 110V) without unduly compromising 

module efficiency. Some compromise was necessary due to the change in cell width and 

additional length of current collection paths, which also increased the use of “frit,” the 

silver-based paste used to create low-resistance internal current paths within the module. 

The effect of the additional frit use is estimated at $0.03/W, increasing overall materials 

cost by about 6%. 

Plug and Play 

The target module specification for solar farms was ideal from a manufacturing 

perspective, i.e. not only, as discussed, in calling for a single product for a single 

customer, but also in calling for a product with no value-added features at all. Such a 

product is a convenient basis for comparison with other “ideal,” i.e. “no value-added,” 

products4. However, such comparisons need to be undertaken with care for the following 

reasons: 

• Some value-added features are demanded by the market, 

• These features account for significant percentages of overall product cost, that 

vary with module footprint and efficiency 

• The percentages vary significantly depending on the product platform, 

For example, products sold at the time into the general market had factory-installed 

“junction boxes,” which typically added a few cents per watt to crystalline module 

manufacturing cost. At the time, plug-type connectors were an emerging, not fully 

proven, solution – though leading system integrators quickly began to demand factory 

installation of specific plug-type connectors. For on-grid applications – the nowdominant market segment – factory-installed connector cables terminated in plug-type 

connectors are now standard, adding, in the case of Millennia, $4 to $9 to product unit 

cost. The estimated cost impact of plug-and-play finishing is $0.22/W and $0.15/W for 

laminate and framed products respectively. BIPV products involving light transmission 

have a cosmetic requirement to move the electrical termination to the module’s edge, at 

an additional cost estimated in the $0.05/W to $0.10/W range. A variety of “edge 

connector” designs were evaluated. Initial generic vision glass and service station 

canopy products did not include them, but later versions did.20 

Strengthened (toughened) Glass 

Early visions for large thin-film factories recognized the fact that, in markets where 

modules would substitute for other glass-based products, they would have to include the 

same type of glass. Glass that is “framed,” as in smaller residential windows, does not 

need to be particularly strong, because the frame protects it from bending stresses and 

crack initiators such as edge chips and handling impacts. Other glass applications, i.e. 

 

4

 The target TF1 product was essentially stripped down for low cost. The real products that were actually 

sold included many value added aspects and were more costly. 

 17
any in which glass is both an optical and structural element (or any where impacts could 

result in breakage and flying shards) require toughening the glass both to prevent 

breakage and to minimize the related hazards by minimizing the size of broken 

fragments. 

Toughening is basically accomplished by heat treatment that results in compressive 

stresses in the surface layers of the glass, which tend to cancel the tensile stresses that are 

induced in one surface layer when the glass is twisted or bent (glass is weak in tension.) 

The toughening process adds significantly to the cost of the glass. Further, because 

toughened glass tends to shatter rather than crack, it does not lend itself to products that 

require final sizing after other value-added steps. There are no commercially useful 

processes for cutting toughened glass. 

Crystalline modules use a single layer of tempered (high-strength) glass to provide 

structural stability and environmental protection for thin, fragile PV cells. Framed 

crystalline modules are remarkably resistant to impact and the rigors of shipping and 

normal handling. If the targeted initial use of TF1 product had been the general market, it 

is almost certain that at least one of the two glass elements would have had to be strong, 

preferably both. If pilot manufacturing had been attempted on strong glass, the factory 

and deposition equipment design would have accommodated the requirement to preserve 

the dimensional stability of the front glass during the deposition process. Unfortunately, 

the factory was built in anticipation of depositing the films on “annealed,” i.e. standard, 

non-strengthened glass. Being free of pre-stressed areas, such glass does not tend to warp 

significantly when its surface layers are subjected to convective or radiant heating, as in 

some steps in the piloted TF1 film-deposition process. 

There was cursory consideration of using strengthened glass in the early stages of project 

planning and implementation. The decision against strengthened glass might have been 

compelled by the likely cost impact and related technical jeopardy to implementing the 

factory project; but it also might have been rationalized on the (then baseline) assumption 

that the product would primarily be used in large arrays where annealed glass solutions 

had already proven suitable.5

As it turned out, the decision had major implications for product cost and other important 

market considerations. Glass breakage and cracking was a thread that ran through the 

commercialization effort like a painful nerve. Its symptoms, chronologically, can be 

briefly traced as follows: 

1996 – Customer Samples. Modules from half-area (4ft2) pilot production were offered 

to the initial customer base and used in demonstration arrays. Many broke or cracked in 

transit or in use, resulting in a requirement for more careful handling and more robust 

packaging. 

 

5

 The 400kW single junction aSi array at PVUSA incorporated frameless double annealed glass laminates. 

 18
1997 – Prototype Multi-module Panels. Demonstration arrays and installations 

involved mounting of glass laminates to metal racks or in preassembled, multi-module 

panels using two-sided tape as the attachment vehicle. Accidental twisting of the multimodule panels resulted in cracks and breakage that compromised array performance, 

though methods were developed to make module removal and replacement more 

convenient. 

1998 – The “Pillow Effect.” The initial lamination process used in production resulted 

in squeezing encapsulant preferentially out of module edge areas, resulting in what was 

referred to as a “pillow effect” with the glass layers ending up closer together at the edges 

than in the middle surface layers and the glass edge areas pre-stressed in tension after the 

glass cooled and the encapsulant cured. This made the modules more vulnerable to 

cracks initiating and propagating from their edges due to thermal stresses and thermal 

shocks in normal operation. The two initial customers most enthusiastic about 

Millennia’s performance and cost advantages in their applications, i.e. PowerLight 

Corporation (a U.S. system integrator) and Polyene (a company developing the solar 

water pumping market in India), were the first to raise concerns about excessive module 

cracking and the premature module failures that could be expected as a result. Both 

companies invoked the product warranty and were partially compensated for their 

losses.6 The lamination process defect that caused the vulnerability to cracking was 

corrected as soon as it was identified. However, by then some product made with the 

defective process had been shipped and installed. 

1999 – Market-Driven Business Plan. At year-end, a cross-functional7 planning team 

was chartered to: 

• Provide a new vision for the TF business unit, and 

• Identify key actions leading to profitability by year-end 2000, shipments of 100% 

of production by year-end 2001, and sustainable business growth thereafter. 

The team concluded that acceptance of the then-current product (43W, annealed glass, 

glass-to-glass encapsulation) would be limited to a few sub-segments of the overall PV 

market; and that this would result in insufficient demand to support profitability or 

business growth. Their plan called for converting the factory to flexible production of a 

range of products generally accepted in current markets and significantly advantaged in 

emerging on-grid markets. They recommended shifting production to deposit films in 

multiple electrical configurations, resulting in lighter-framed 12V modules with ratings 

of 5, 10, 20 and 43W for remote markets, to deposit films on heat strengthened or 

tempered glass, resulting in lighter and more robust framed and unframed, full-size 

modules for on-grid markets (site assembled and packaged system solutions), and finally 

 

6

 Polyene’s business success hinged on the success of its initial installations using Solarex thin-film 

products; the company eventually failed after lengthy negotiations to resolve its claim that the modules 

found to be cracked were defective as shipped and that consequential costs should be covered . 

7

 Manufacturing, marketing, technology, business development, sales, finance, and product development 

 19
to add the capability to laser ablate the film, resulting in light-transmitting “vision glass” 

and special feature (logo patterned) modules for BIPV. 

2000 – Deposition on Strengthened Glass. By year-end 1999, the implications of the 

planned switch to heat-strengthened products were better understood, and plans were in 

place to introduce such products starting in the first quarter of 2000. Heat-strengthened 

glass/Tedlar laminate costs were expected to be $0.2/W higher than comparable doubleannealed glass laminate costs. Attempts during 2000 to process heat-strengthened glass 

using existing equipment and processes were unsuccessful – and also costly to factory 

operations – because of the need to use the manufacturing line for numerous engineering 

test runs over many months.21 Eventually, process and equipment modifications were 

identified and implemented that enabled limited numbers of heat-strengthened laminates 

(about 25kW) to be made for vision glass and other products in the first half of 2001. It 

is assumed that heat-strengthened product production increased over the following year 

until BP Solar announced termination of TF1 operations. 

2001 – “Arc Risk." Because of delays in switching to at least partial production of heatstrengthened product during 2000, PowerView modules shipped for initial BP service 

station canopy applications were double-annealed glass laminates. By the end of 2000, 

several hundred kW of this product had been shipped. In early 2001, eight modules in 

five installations in Indianapolis were damaged by electrical arcing. All eight modules 

exhibited cracks of the front glass and resulting corrosion of film material. Subsequent 

investigation determined that Millennia modules in grounded arrays operating at >100V 

relative to ground and experiencing glass breakage during or after installation were, or 

would be, at risk of arcing along the silver frit bus bars, and that heat generated by the arc 

could soften or melt the adjacent glass and/or pose hazards due to fire or falling objects 

under certain conditions. Primary risk factors related to breakage risk and operating 

voltage. Breakage risk, in turn, was determined by whether the glass was annealed or 

heat-strengthened; whether the glass was supported at its edges by a frame; and, if 

unframed, whether the glass laminate was properly mounted.8 

Cost Impact of Heat Strengthened Glass 

The cost impact of using stronger glass depends on the encapsulation approach. For 

double-glass laminates, the total cost impact of two heat-strengthened glass layers is 

 

8

 The consequences of this determination were serious. First, heat strengthened modules were not yet in 

production, and most existing Millennia installations, including those involving greatest safety risk (service 

station canopies) used power conversion equipment requiring array operation well over 100V. Affected 

service station installations were tagged out pending inverter replacement, extensive testing was done in 

support of failure analysis and preparation of installation guidelines and risk assessment, and a 

communications plan was prepared. In the end, such information remained closely held, and a 

comprehensive effort was made to evaluate risks, and where necessary, inspect and identify the condition 

of every existing Millennia installation, to the extent possible. Considering the volume of product shipped 

by 2001, and assuming an average system size of 15kW, the numbers of installations covered by the 

investigation would have run into the hundreds. System reconfigurations were required in some cases. 

Detailed statistics are not available. 

 20
estimated at $0.20/W, though lack of production experience suggests putting the cost 

impact in a range between $0.15/W and $0.30/W. The total cost impact of switching 

framed modules from a double-annealed glass laminate to a heat-strengthened 

glass/EVA/tedlar laminate is estimated, again without benefit of production experience, 

at $0.15/W. This estimate may be optimistic; production validation may or may not have 

occurred.22 

Frames 

Recognizing the below-target efficiency of the initial thin-film products and the 

problematic experience with preassembled multi-laminate panels, an effort was 

undertaken in support of the PV-VALUE9 program, targeting mounting solutions for 

double-glass laminate modules that would minimize area-related balance of system and 

installation costs, particularly for applications on residential roofs. The innovation that 

resulted, the Integra framing and mounting system, was greeted with enthusiasm by some 

initial grid market customers, whose focus was retrofit applications on residential roofs, 

the application for which the solution was intended. 

Innovative solutions for installation on commercial roofs, i.e. PowerLight Corporation’s 

system using insulated roof pavers, were compatible with the original medium voltage 

(MV) laminate product. However, grid-tied customers in non-U.S. markets, where the 

Integra product was not safety-certified, were demanding modules having standard 

frames. Breakage experience (noted above) with annealed glass laminates also 

encouraged introduction of a broader range of framed modules.10

The total cost impact of framing of a nominal 43W Millennia modules is estimated at 

$0.21/W. 

“PowerView” 

Until 1999, the emerging market for building-integrated PV (BIPV), i.e. the substitution 

of PV modules for other building-envelope materials, had been a low priority, because of 

inherent conflicts with the company’s role as a leading high-volume, low-cost 

manufacturer of standard products. (BIPV applications typically involved special 

products specified for use in “one-off” projects.) However, during 1999, new company 

 

9

 A program established to develop and deploy packaged residential rooftop systems incorporating 

Millennia, with the assistance of a $2/Wac buy-down made possible by DOE cost sharing. 

10 Module frames, while adding significantly to module manufacturing cost, off-set some balance of system 

costs (the module frame becomes part of the overall mounting structure) and require no re-engineering of 

mounting solutions used with crystalline modules, nor any special new mounting hardware. More 

importantly, frames provide the structural support necessary to package and ship individual modules rather 

than crates of modules, a strong consideration for distribution customers selling modules in smaller 

quantities. It is of course essential that the active area of the laminate be properly insulated electrically and 

properly protected from water ingress; otherwise the frame provides a current path to ground accelerating 

module failure and resulting in ground faults. 

 21
leaders,11 most of whom had plate-glass manufacturing industry experience, established a 

direction for the thin-film business unit that envisioned high-volume production of 

standard BIPV products. Their imagination had been captured by the technical ability to 

create architecturally and aesthetically unique modules using a laser-ablation process that 

created microscopic holes in the film. The demonstrated potential to make a lighttransmitting, thin-film laminate was quickly married to an initiative of the company’s 

new owner, BP, aiming to include PV arrays in the canopies of all new BP service 

stations in selected markets, including the United States. The cost impact of 

“PowerView” processing is estimated at about $0.41/W, including the impact of power 

loss slightly greater than the level of film removal, i.e. 5% for initial products. 

Module Power 

Module power shortfalls had a major effect on cost, adding about $0.20/W to nominal 

fixed costs and more than $0.40/W to variable cost. A factory sized to produce a certain 

number of units at the target rating will have an actual output proportional to module 

efficiency and costs inversely proportional to module efficiency. 

Specifically, a technology envisioned to rapidly achieve stablized 8% module efficiencies 

in production and improve significantly from there (see Figure 2), struggled at first to 

achieve 5.5%; and then stubbornly refused over a period of a few years to reach a point 

where significant numbers of higher-rated modules could be made, in spite of ongoing 

forecasts by company technologists that promised results consistent with the original 

vision. 

How could this happen? No published explanation exists; a few observations can be 

offered to provide perspective: 

• There was significant efficiency variation in various process “recipes” evaluated 

during 1995 after the demonstration of 7.8% stabilized efficiency on half-size 

plates in 1994. There were also differences among the various recipes in terms of 

deposition time, process readiness, and equipment and material cost. It would 

have been natural to sacrifice efficiency in order to make conservative choices in 

other aspects (e.g., the decision to outsource tin oxide-coated glass at a penalty of 

about half a point in stabilized efficiency), hoping to recover lost efficiency via 

future process optimization and improvement. 

• Whether, in fact, any recipe demonstrated in experimental chambers operated by 

research staff could be effectively replicated in full-size, inline deposition 

chambers operated by factory floor staff is questionable. Variations even among 

experimental chambers were significant. 

• Other decisions along the way – e.g., the switch from “high” to “medium” voltage 

discussed earlier. 

 

11 In 1998, a new CEO and new technology and manufacturing executives were hired. 

 22
The catch-all explanation is simply “process transfer loss.” A process that ostensibly 

delivered close to 8% efficiency using experimental chambers in pilot production of halfarea plates somehow lost 18% of projected module power when transferred to 

production, and this loss was never recovered. 

Yield 

Cost is likewise inversely related to overall process yield. Relative to the original 92% 

target, actual total line yields for core products leveled off in the 70% to 80% range.23 

The estimated effect is to increase fixed costs by $0.15/W. The assumptions behind the 

original yield assumption are unknown. 

Efficiency Penalty 

The numbers of relatively large systems using Millennia modules provided an 

opportunity to assess the effect on overall system cost of low efficiency and other 

inherent electrical and mechanical features. Relative to the highest-performing modules 

available at the time, it was estimated that the impact on system cost of using Millennia 

instead of a higher-efficiency product was in the range of $0.16/efficiency point/W, or 

roughly $1/W vs. crystalline modules in commercial production at the time. This impact 

was confirmed by an NREL-funded analysis by a major U.S. system integrator24 and 

was a major deterrent to the use of Millennia modules (even by BP Solar’s system sales 

teams) in large projects where high-volume crystalline pricing typically did not exceed 

high-volume Millennia pricing by enough to offset the penalty. Obviously, the penalty 

would likely be greater now, based on crystalline module efficiency improvements over 

the intervening years. 

“Off-budget” or “Below the Line” Costs 

Transfer of a PV module technology from R&D to commercial production can incur 

major costs that are not counted in models like the one applied here. Specifically, a 

factory has operating and fixed costs whether it is operating productively or not. 

Likewise, before, during, and after commissioning, there can be value in pilot production 

of prototype or precursor products. Pilot lines and experimental equipment can allow for 

validation of processes and designs without tying up part or all of the main manufacturing 

line. Continuing R&D aiming at future improvements in manufacturing processes or 

equipment may also be required if the factory is itself a prototype, and some technologies 

that may enhance future plants are not ready for commercial use at the time it is built and 

commissioned. 

Pre-commercial Operations 

In the case of TF1, the plan called for essentially full production within two years of 

project initiation. Figure 1 shows the gap between planned and actual production. Some 

cost savings can be captured by regulating staffing according to the ramp rate that 

technical progress permits while avoiding extremely low-yield operation; but fixed costs 

remain, as do R&D costs and variable costs that exceed product revenues. For the TF1 

 23
start-up and production ramp, these costs ran to several millions of dollars annually. 

Some financial relief was available by “capitalizing” operating costs in the years prior to 

round-the-clock commercial production. This resulted in an apparent capital cost much 

higher than the original plant budget and much higher than would have been justified by 

the plant’s originally projected economics. 

Pilot Lines 

Pilot operation continued only a year and some months beyond factory project initiation 

and so had minimal cost impact. A question arises as to whether continued pilot 

operations would have supported process experimentation that ultimately was done in the 

main production line. If so, economies of terminating off-line pilot operations prior to 

factory start-up may have been false. 

R&D 

TF1 was founded on the strength of a significant ongoing combined R&D and 

manufacturing operation in Newtown, Pennsylvania, employing approximately 70 to 80 

people. Manufacturing operations in Pennsylvania produced a few hundred kW annually 

of 5W single-junction modules for customers who manufactured specialty products like 

livestock fence and recreational vehicle battery chargers. Arguably, resulting revenue 

covered the manufacturing unit’s share of facility and labor costs, but the need to colocate R&D staff with the new factory and the assumption that OEM customers could be 

“converted” to purchase comparable polycrystalline product led to a decision to close the 

Pennsylvania plant and terminate all employees not needed to staff the new factory or the 

scaled-down R&D group at the new factory. R&D costs in the range of $2M to $3M per 

year continued, along with the one-time cost of relocating relevant personnel and 

equipment. These costs were not counted against factory revenues but were partially offset in early years through cost-sharing participation in DOE/NREL programs. 

Downstream Costs 

PV modules account for a major share of installed PV system costs. Their efficiency and 

value-added features have a major effect on remaining “downstream” costs. Along with 

module price per watt, two such costs were influential in market acceptance of the 

product line, i.e. the cost of shipping modules to the point of use and the cost of 

incorporating them in a properly functioning system. 

Shipping and Packaging 

Shipping costs are typically paid by the PV customer and would be considered in 

evaluating product and supplier offerings. For Millennia, they varied from an estimated 

$0.02/W for container shipments of laminate products destined for warehousing in 

Rotterdam to an estimated $0.13/W for container shipments of framed products destined 

for India. Additional shipping costs from distribution warehouse to end use would have 

been incurred in all cases. It is fair to say that Millennia shipping costs, simply due to 

low power density and low numbers of watts per container, significantly disadvantaged 

Millennia relative to competing higher efficiency products. It is also noteworthy that 

modules shipped to end customers are often shipped in small quantities, necessitating 

 24
individual packaging at some point. For Millennia, the incremental cost of single-module 

packaging was several cents per watt more than crate packaging. 

Interpretation 

Decision Chronology Summary 

To summarize, the decisions that influenced manufacturing cost were fundamentally 

market vision and business model choices, not independent manufacturing decisions. 

The first decision that influenced manufacturing cost was the decision to target central 

station power applications. It meant that product features demanded by the existing 

market such as frames, strong glass, and convenient electrical terminations could be 

avoided. 

The second decision that influenced manufacturing cost was the decision to offer the 

product in markets where standard crystalline modules were also an option for potential 

customers. This led to the need to engineer a product having competitive warranties and 

even superior plug-and-play functionality (to offset a portion of the base technology’s 

inherent efficiency penalty). It also led to the need to offer product options not discussed 

above, including products having a nominal voltage of 12V rather than 48V, products 

having lower ratings typical of competing thin-film and crystalline modules used in 

village solar home systems and other off-grid applications. It led to the need to engineer 

a product certified for operation in European on-grid applications that had wider strips of 

film removed at the edges to provide proper electrical isolation for modules tested and 

certified for operation in systems designed for up to 1000V (vs. the U.S. National Electric 

Code limit of 600V). The cost of these products varied – the essential decision in each 

case was to accept the incremental manufacturing (and, in some cases, front- and backend process and product development, qualification, and certification) costs in order to 

offer a product having the same or greater value than crystalline and competing thin-film 

offerings. 

The third decision that influenced manufacturing cost was, like the second, a decision to 

increase cost as necessary to offer unique value, i.e. the combination of power generation 

and light transmission. 

BP Solar’s decision to shut down the factory in late 2002 and its related decision to 

abandon further effort on the technology are also of interest. These decisions did not 

hinge exclusively on manufacturing costs; rather cost experience was undoubtedly a 

significant factor. 

First, there was a decision to abandon the factory, TF1. For cost reasons, it could not be 

profitably “filled”, i.e. operated at full capacity in response to customer orders, without 

implementing yet another new market vision. Such a vision probably existed, but it 

probably also would have involved a niche market where small thin-film modules rated at 

5W to 50W could be sold at high enough prices to generate good margins, a market 

 25
already validated by previous Solarex thin-film manufacturing efforts and by others; and 

a market to which crystalline technology is poorly adapted to compete on cost. Relative 

to the company’s need at the time to focus on the profitability of its crystalline business 

in the face of strong global competition, this option was probably not considered. 

Second, there was a decision to abandon the technology. This was no doubt also 

influenced by cost, i.e. failure to validate production costs and product efficiencies that 

would support profitable sales in major market segments. This failure, which flowed 

from technical limitations of first generation manufacturing equipment and related 

deposition processes, left in its wake no high confidence path to sufficient manufacturing 

scale where attendant off-budget and scale-up costs would be recovered and attractive 

returns on investment could be anticipated. Clearly, the original strategy of proving and 

then replicating, many times over, a manufacturing line capable of reasonable efficiency 

could no longer be plausibly advocated, even if the owners had not been facing hard 

capital allocation and investment choices. 

Cost Change Drivers 

How did cost projections change, and what drove the changes? 

Material Cost Drivers 

Figure 2 summarizes unit material cost projections. 

Figure 2. Unit Material Cost

 (laminate w/pigtails)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

$/unit

1994

1995

1997

1999

Differences in the two preproduction material cost projections (1994 and 1995) were 

discussed earlier. Increases from 1994 to 1995 were driven by costs of tin oxide-coated 

glass and increases in Germane gas cost and use. Differences between pre- and postproduction projections were also driven primarily by more realistic assumptions 

regarding yield, and costs of back layer (glass or tedlar), frit, and encapsulant (EVA). 

Germane cost increases were offset by Silane cost decreases. Further reductions in 

overall specialty gas cost drove the differences between projections made in 1997 and 

1999 for production years 1998 and 2000. 

 26
Labor and Other Unit Cost Drivers 

Table 3 summarizes the increases in various unit cost projections from mid-1995 to late 

1999. Labor and fixed cost increases, like material cost increases, apparently were driven 

by more realistic yield assumptions as well as lesser influences more difficult to identify 

than material cost drivers. The factory was not in full stable production during the 

period, so comparison of detailed labor hour and process step yield statistics would not be 

conclusive. 

1995 1999 Change

12.88 15.39 19%

25.2 30.62 22%

36.26 47.30 30%

Total 74.34 93.31 26%

Notes:

1. Includes direct labor and labor overhead

Labor Total (1)

Direct Material

Fixed Cost 

Unframed laminate w/pigtails ($/unit)

Table 3. Original vs. Experience-Based Cost Estimates 

Efficiency 

The most persistent, and apparently unalterable, difference between realized cost and 

expected cost was actual efficiency vs. projected efficiency. From 1994 onward (see 

Figure 3) efficiency improvement forecasts were updated multiple times, and the 

scenarios for improvement were consistent from forecast to forecast; yet actually 

realized average efficiency did not change significantly during the roughly 5 years of 

commercial product shipments. 

Figure 3. Efficiency Forecasts 

0

2

4

6

8

10

12

1997

1998

1999

2000

2001

2002

2003

Year

Stabilized Efficiency - 

%

6/5/1995

5/23/1997

7/29/1997

3/31/1999

Actual 

 27
Cost Experience Summary 

Unit laminate costs (driven by materials and labor) were substantially underestimated 

initially; efficiency shortfalls drove laminate $/Wp costs up further; in parallel, the need 

to meet market requirements by shipping thin-film products technically equivalent to 

accepted and proven crystalline products drove $/Wp costs even higher; finally, valueadded features were incorporated at significant incremental cost. 

Cost/Value Trade-off 

The above discussion of cost drivers risks reinforcement of a common but overly 

simplistic understanding that all module sales go to the low bidder, based on $/Wp price 

comparison. It suffices to say that, with PV modules (as with virtually every other 

manufactured product); manufacturing costs can be reduced by sacrificing functionality, 

convenience, quality, durability, operating life, etc. For example, it is technically very 

challenging to engineer and produce a thin-film module whose actual demonstrated 

lifetime under simulated long-term environmental assault is actually 20 years. Such a 

product is almost certain to cost more to manufacture than a module that achieves a lesser 

level of qualification. As is obvious from the above discussion, the evolution of TF1 

product costs was equally and inextricably an evolution in TF1 product value. 

Future Cost Reduction 

A good place to start in assessing the potential for future cost reduction is cost 

comparisons that were drawn between the two major Solarex module manufacturing 

technologies, i.e. a-Si and polycrystalline. Figure 4 reflects what would have to be 

regarded as the best-informed view of this comparison at the time (in mid-1997). It was 

based on world-leading manufacturing experience and hundreds of millions of dollars 

and decades of investment in both technologies; and it was essentially the bottom-line 

rationale for strategic plans, which forecast the eventual eclipse of the company’s 

crystalline manufacturing capacity by its thin-film capacity. 

 28
Figure 4. TF and Poly Laminate Costs

0

0.5

1

1.5

2

2.5

1997 1998 1999 2000 2001 2002

Year

$/Wp TF lam

Xtal lam

The favorable scenario hinged on thin-film production scale-up to levels comparable or 

even exceeding polycrystalline. As presented, the preference appeared decisive, but its 

absolute magnitude was in the range of $0.3/Wp in 2002. The preceding analysis 

suggests that several factors, or a combination thereof, could negate or reverse this 

advantage. 

Could such a comparison like the above still come true? Perhaps, but much has changed 

on both sides of the comparison. In particular, crystalline technology and production 

scale have continued to progress in the intervening years while the Solarex a-Si 

technology suffered a devastating setback at the end of 2002, losing both physical assets 

with which to move the technology forward but also losing the organizational capability 

to use them. 

Putting aside comparisons, can a-Si manufacturing costs be reduced from the levels 

achieved by Solarex and BP Solar over the next 10-15 years? Technically yes – it is 

evident from the preceding analysis that original targets were not achieved. Laminate 

costs exceeded original long-term targets by almost a factor of 2 at the end, but only part 

of the explanation was unrealistic cost targets imbedded in early cost models. The other 

part of the explanation – failure to achieve more realistic cost targets – can in principle be 

overcome with the expenditure of significant resources. 

Recent proposals to undertake such expenditures are by no means revolutionary, but they 

actually mirror the visions and strategies underlying the decade-long effort analyzed 

above. In early strategic plans, TF1 was viewed as a prototype and precursor of a 

“factory of factories” that would assemble, tune, and qualify “cookie-cutter” lines from 

an ever-improving template, switching to more efficient films as they came out of the 

R&D pipeline, driving capital costs down, and adding automation and a complete process 

to deliver and staff turn-key factories anywhere in the world. The deployment scale 

 29
envisioned at the time was comparable to the deployment scale envisioned in more recent 

proposals. See Figure 5 for the results of this aggressive scenario. 

Figure 5. Factory of Factories Scenario

0

100

200

300

400

500

600

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Year

Cumulative Capacity 

(MW/year)

If current proposals are basically reincarnations of old proposals that were partially 

implemented, what guidance can be gleaned from the implementation experience? 

First, target market validation is essential. The initial market hypothesis will drive both 

product and factory design; and, if wrong, it will have a crippling effect on subsequent 

efforts. It will result in a requirement to integrate and coordinate moving targets in too 

many fundamental aspects, i.e. emerging markets, product line reengineering, and factory 

process changes. Changes in one aspect alone are daunting enough and can be addressed 

relatively quickly, as long as complications and delays in one aspect do not cascade and 

aggravate complications in other aspects. As noted, TF1 and supporting product 

engineering had to adapt to not just one but two major changes in fundamental market 

requirements (i.e. from a requirement for a single high-voltage, essentially unfinished, 

and relatively fragile laminate product for a single customer) to a requirement for a broad 

line of products functionally equivalent to established product offerings in several diverse 

market segments, back to a single product for a single customer – but one with significant 

value-added features as yet undemonstrated in production or use. These basic 

redirections set in motion other changes that proliferated and were beyond the capacity of 

even an experienced parent organization to support or smoothly coordinate. 

Second, early product introduction and sales can be valuable in smoking out problems, 

but it can also result in damaging and distracting customer and market reactions. 

Technology validation using experimental equipment and pilot lines can only be partial – 

it eliminates a negative theoretical possibility but does not prove a positive operational 

forecast. Operating a full-scale line without benefit of related revenues involves net costs 

 30
well beyond the cost of the factory itself. These costs can only be justified by 

hypothetical revenues from multiple future plants, but they must be accounted for in 

realistic budgets. 

Third, because thin-film PV technology challenges are so serious, it is tempting to 

assume that related product engineering, qualification, and certification challenges are not 

of the same importance and can be addressed once a factory is being built. For example, 

photovoltaic films are especially vulnerable to destruction by moisture ingress; and 

encapsulation strategies consistent with competitive warranties should be developed and 

validated in parallel with film-deposition processes. The cost of dealing with unresolved 

engineering issues can be significant, i.e. several hundreds of thousands of dollars per 

year, or a few percent of full capacity revenues of a 10MW/year factory. More 

important, lack of timely resolution can delay production and compromise pricing, with 

far greater negative financial consequences. 

Fourth, there are no top-down management fixes when thin-film PV net income forecasts 

turn out to be optimistic. In the case of TF1, the challenges of unforeseen and 

unavoidable technology, product engineering, factory operations, and marketing changes 

outlined above were compounded by exhaustive consultant and management reviews and 

reorganizations. 

Finally, patient capital and significant corporate parental support are truly necessary if 

thin-film commercialization initiatives are to proceed on an aggressive schedule. Amoco, 

BP, and their crystalline PV business units provided these indispensable ingredients, e.g., 

in the product engineering and legal disciplines, finance, marketing, sales, customer 

service, procurement, logistics, and health and safety. Capital and corporate 

infrastructure support are necessary but, of course, not sufficient. Execution of the plan 

is the sufficient condition. Even so, the importance of the diverse and essential 

organizational and financial resources Amoco and BP made available to TF1 and its 

planning and operations cannot be overstated.25 

 31
Case Study: Cadmium Telluride 

Apollo Technology – R&D to Production Engineering Phase: 1986 – 1998 

1986 to 1996: Acquisition of Apollo Technology and R&D Effort 

The Apollo photovoltaic technology project started in 1986 when BP Solar acquired 

patents for CdTe photovoltaic devices from Monosolar Inc. (Santa Monica, California). 

The Monosolar patents described the electrochemical deposition of two semiconductor 

films – cadmium sulfide (CdS) and cadmium telluride (CdTe) – onto a conducting tin 

oxide-coated glass substrate. 

BP Solar organized an R&D project at Sunbury (U.K.) named Apollo. The R&D team 

objective was to increase semiconductor efficiency and the size of the photovoltaic 

device using the Monosolar electrochemical process as a starting point. Monosolar 

inventors produced CdTe photovoltaic devices on substrates of a few square inches. 

During the 1987-1996 period, the UK Apollo team developed a computer-controlled 

plating process that deposited CdTe on a 1ft2

 (.09m2) substrate, in conjunction with a 

back contact process that relied on conformal coating techniques. The CdS film was 

produced via a thermal-chemical batch reactor process, where elapsed time and rinsing 

controlled the film thickness. The R&D effort eventually culminated in a 1-square-foot 

module with 10% aperture area efficiency (approximately 8 watts). 

By the end of the 10-year R&D period, the Apollo technology fundamentals – chemical 

deposition of CdS and CdTe on tin oxide float glass substrate, application of back contact 

coatings, laser ablation of cells, and metallization – were identified and documented for a 

1ft2 substrate using laboratory bench-type equipment. The encapsulation process relied on 

lamination and lead attachment techniques similar to that used by crystalline photovoltaic 

(PV) manufacturers. The R&D processes – and, by implication, the laboratory equipment 

– were documented as the core Apollo technology by 1996 and handed off to the 

Fairfield engineering team. 

1994 to 1996: Acquisition of Fairfield Plant and Equipment 

The Fairfield (Calif.) plant and equipment were designed by APS Inc. to produce 31” x 

61” (78cm x 155cm) amorphous silicon PV modules using a batch process developed by 

its predecessor company.26 However, APS infringed a Solarex patent in their deposition 

process and, as a result, ceased operation in 1995.27 Subsequently, APS filed for 

bankruptcy, and the Fairfield assets were put up for sale. After a technical audit by BP 

Solar in 1996, it was determined that the Apollo technology could utilize about 50% of 

the APS equipment, primarily in the post-deposition processes. The Fairfield purchase 

was consummated in October 1996. The Fairfield a-Si plant was designed around a highvacuum, plasma-deposition batch process. The only “wet material” in use at Fairfield was 

water for incoming glass washing, vacuum pump oil and various solvents used in the 

encapsulation process. 

 

 32
1997 to 1998: Technology Transfer, Process Specification, Equipment Procurement, 

and Staffing 

Technology Transfer 

In January 1997, a three-person team began the process of transferring the Apollo 

technology from the UK R&D group to Fairfield. During the initial stage of the 

technology transfer process, the team focused on engineering specifications for the 

Apollo process, so that equipment bid specifications could be prepared. 

Review of the R&D laboratory process was used to define the cycle time and type – batch 

or continuous – for each manufacturing process step, including load/unload time. The 

manufacturing process was charted for a 14-by-61-inch substrate while taking into 

account existing equipment locations at Fairfield. The 14-inch width was dictated by the 

R&D team findings linked to voltage drop across the substrate during CdTe deposition. 

The 61-inch length for Apollo stemmed from the APS module footprint (31-by-61 inch) 

for existing equipment at Fairfield. 

The processing of 0.55m2 (14-by-61 inch) substrates at Fairfield was considered an 

intermediate product from the outset, one that posed little risk for the R&D CdTe 

deposition process. The 0.55m2 module had a nominal 25W rating, which could be used 

for battery charging or in small arrays, but was not viewed as a power module. The 

rationale for producing the 25W module at all was to allow the plant to start operating in 

the shortest time possible, while the Fairfield technology team developed a CdTe 

deposition process for 24-by-61 inch (0.94m2) substrate. The 24-inch product size 

emerged for several reasons. First, one person could manually handle a 0.94m2 size 

substrate; and a module could be handled by a two-person team, from a weight 

perspective. Second, off-the-shelf coating equipment to process 24-inch wide materials 

was judged to be widely available. Third, the R&D and Fairfield team had reason to 

believe the CdTe deposition technology could be pressed to accommodate 24-inch 

substrate, but larger widths presented significant technical risks; and, further, the plating 

tank size necessary to process 5-across 14-inch substrates could dimensionally 

accommodate 3-up 24-inch substrates. Finally, the deposition equipment would “fit” onto 

the Fairfield plant floor along with a second CdTe deposition train at a later time. From 

the outset, therefore, the technology transfer team considered the ramification of a larger 

substrate in preparing the specification for new equipment. 

Process Specification

The translation of the R&D process for 0.09m2

 substrates posed substantial challenges. 

The intermediate 0.55m2

 substrate presented engineering challenges for even relatively 

simple heat-treat steps. Time-temperature profiles for manufacturing-size convection 

ovens had to be developed from the R&D bench-type ovens. Questions arose about ramp 

rates, soak time, cool-down, and surface temperature uniformity across single substrates 

of a “load” comprised of about 20 substrates in a batch, laminar flow oven. Such 

parameters had not been explicitly considered on the R&D level, presumably because the 

small 0.09m2 plate load did not elicit any fundamental technology questions. 

 33
Scale and edge effects were encountered in other processes as well. The CdS deposition 

process in R&D, for example, was based on “manual stirring” by a technician as two 

aqueous solutions were poured into a deep bench tank, followed by manual insertion of a 

small rack of CTO glass. At Fairfield the two solutions (cadmium-base and chelating) 

would be pumped into a reaction chamber many times larger, air would “stir” the 

solutions, followed by immersion of the substrate load weighing hundreds of pounds 

from a hoist. The batch reaction process requirements were carefully calculated, and then 

converted into equipment specifications for high-volume manufacturing. Similar scale 

issues were addressed across many other processes. 

Equipment

When the engineering specifications were judged as complete, equipment procurement 

was initiated, which took place during the 1997-1998 period.28 The approach taken was 

to obtain a modified version of “off-the-shelf” equipment from original equipment 

manufacturers (OEM) in order to minimize equipment design and delivery time. The 

main exception to this approach was the procurement of the CdS and CdTe reactors, each 

of which were one-off or engineer-to-order (ETO) pieces of equipment. The design and 

construction of the requisite Apollo deposition equipment by the selected OEM required 

considerable input from Fairfield’s technology/engineering team. A prototype CdTe 

reactor was made prior to delivery of the main system to test the internal components. 

This unit had one eighth of the capacity of the main CdTe train and was operated in a 

semi-manual mode. However, the internal components and structure were identical in 

design to the production line. By July 1998, all equipment was in place, including the 

single CdTe prototype tank, so that process qualification trials could take place. 

Recruitment of Technical Staff

As the Apollo project got underway at Fairfield in 1997, there was great demand for 

scientists, engineers and other skilled personnel throughout the “Bay” area in northern 

California. Initially, recruitment of technical staff was limited to the local region. It was 

quickly determined that personnel availability in northern California was inadequate for 

the proposed compensation levels; and sometimes qualified candidates simply could not 

be identified almost regardless of salary. 

Apollo Technology – Legacy Manufacturing Plan: Circa 1997 – 1999 

1997 Manufacturing Vision – Apollo Modules @ η ~ 5.5 – 6.5%:29 Initially, Apollo 

manufacturing volume was planned under the assumption that only supply constrained its 

consumption in the market. That is, if the Fairfield plant was capable of producing stable 

25Wp modules over the 1998 to 1999 period, they would all be sold. Following on in 

2000, if Fairfield produced stable 50Wp modules, they too would all be sold as well. The 

Apollo technology/engineering start-up team was convinced that the various equipment 

and process challenges were manageable, and that the endeavor would constitute a major 

breakthrough in thin-film module manufacturing. The Apollo team benefited from 

abundant offers of corporate support at the outset, which was usually forthcoming in 

disciplines such as financial, legal, purchasing and community relations. 

 34
Based on the outdoor experience of the R&D findings, the Fairfield team expected about 

6% light-soak degradation by the Apollo module. The initial efficiency target in 

manufacturing was 5.9% for the 0.55m2

 unit and 6.6% for the 0.94m2 unit, resulting in 

stabilized efficiency on order of 5.5% and 6.2%, respectively. The module features were 

straightforward – annealed glass to glass lamination using EVA, U-channel brackets, Jbox connector, and 16AWG red/black wire harness suitable for interconnection in an 

array. These module features were those employed by APS for the a-Si 500kW array 

built for the PVUSA project. These encapsulation processes and equipment were carried 

over at Fairfield. 

The manufacturing plan for the period 1998-2000 identified a number of risks that could 

impede the rapid start-up of Apollo production. These risks included the following: 

1. Engineering Staff – timely recruitment within salary guidelines for essential 

engineering and other technical personnel needed for line start-up; 

2. New Process Equipment – procured in reference to the cost estimates originally 

developed by the R&D team; this applied to both modified “off-the-shelf” 

equipment as well as the one-off, special-purpose deposition reactors and 

associated fixtures; 

3. Facility Overhaul – modifications to accommodate multiple wet chemical 

manufacturing processes and supporting infrastructure; 

4. Hazardous Waste and Environmental Control Equipment – retention of chemical 

solutions under normal and catastrophic conditions, spent solution capture and onsite/off-site treatment of hazardous chemicals, volatile organic compounds 

(VOC), and other materials (direct and indirect); securing necessary permits and 

approvals from local, regional, and state agencies; 

5. Fairfield Equipment – modified or reconditioned to handle Apollo substrates and 

modules; legacy equipment of interest included glass washers, automated 

load/unload laser stations, metal sputtering unit, and encapsulation equipment 

such as EVA applicator, buss foil applicator, laminators, bracket applicator, 

laminate/bracket curing ovens, and conveyors; 

6. Operator and Technician – timely recruitment from local labor pool and specific 

training, including skilled maintenance and process technicians; 

7. Product and Process Reliability – reliance on earlier R&D studies, especially 

outdoor test array data, to forecast long term module electrical and environmental 

performance. 

Start-up Challenges, Risk Management, and Revised Vision: 1997 – 1999: As it 

turned out, some of the aforementioned risks were significant drivers of project 

performance, either with respect to resource consumption, creation of major delays in the 

project timeline, or both. There was no expectation that new significant technology 

enhancements would be required for success. 

 35
Technical Staff 

Recruitment of engineering and technology staff was extremely challenging. The speedy 

recruitment of senior technology and engineering personnel in the local region was not 

successful. The overall project plan called for all new engineering staff, plus three 

“transfer” members from other units, to be onboard by April 1997; installation of all 

essential process equipment by the end of 1997; and start of qualification trials in early 

1998. 

The reality turned out differently. The first engineer was hired in May 1997, and the last 

came onboard in September 1997. Once assembled, however, the team charged ahead 

with the technical challenges. Higher than budget relocation costs and higher-thanplanned salaries aside, the greater impact was a delay in acquiring, installing and 

qualifying process equipment; and in managing the extensive facility renovations. The 

start-up expenditure was set at about $200,000 per month. Hence, the delay in starting up 

the Apollo manufacturing line beyond the planned period (early 1998) was very costly. 

Deposition Equipment

The Apollo CdS and CdTe deposition reactors were unique. In terms of scale, the batch 

reactors were quite large. In terms of equipment construction, the CdTe electro-chemical 

reactor required significant alignment precision, which is not normally associated with 

large and heavy substrates in a chemical bath. Alignment of the mass transport 

mechanism with the substrates and transport racks proved to be very difficult in terms of 

material selection and fabrication. Further, both types of reactors involved large thermal 

loads and the need to closely control the temperature profile. 

In 1997, there were very few original equipment manufacturers (OEMs) with the 

requisite engineering and fabrication expertise needed for designing and constructing the 

sort of very large deposition reactors necessary for the Apollo process. The Apollo team 

identified a handful of firms in the USA. One was eliminated because all construction 

was done in the Far East, which would lead to excessive project and engineering 

oversight costs. A second company disqualified itself because they were located on the 

East Coast. The remaining three OEMs were in the Los Angeles area. 

Three bids were solicited, but only two firms responded. The first bidder had marginal 

experience in manufacturing large-scale, automated chemical batch reactors at the time, 

and their bid was judged inadequate. The second OEM submitted a quote that 

demonstrated reasonably good technical understanding, and the proposed cost was close 

to that originally estimated by the R&D team. The third company, when pressed to 

submit a bid, said they would only consider a time and materials (T&M) design project 

for one year to come up with a design of what was needed, and the charges for the 

engineering effort would be equal to the second firm’s bid for finished reactors. 

The second OEM was awarded the contract for the CdS and CdTe deposition units in 

June 1997. The CdS deposition unit was delivered in December 1997 per the contract. 

The CdTe deposition system proved much more difficult. After many months, a special 

project manager and a mechanical engineer were assigned full-time to work on-site at the 

 36
OEM’s place of business. In the end, the CdTe unit was delivered in August 1998 at a 

cost about double the original bid, and only prototype fixtures for one of the eight tank 

trains were provided. To fit out the other 7 tank fixtures, additional cost on order of 

another 50% was required.30 

Facility Overhaul

The modifications needed to convert the “dry” Fairfield facility to accept the wet 

chemical processes for Apollo were challenging in several respects. Channels and 

conduits had to be cut into a solid concrete floor, along with discharge pipes to 

“catchment” tanks where pumps were needed to convey the spent solutions to a treatment 

facility especially designed to handle cadmium wastewater. Concurrently, various gas 

byproducts from processes involving hazardous gases and solvents had to be captured by 

flow hoods and conveyed to scrubber systems. Chemical holding tanks, containment 

dikes and seismic tie-downs were needed where yet-to-be-acquired process equipment 

was to be installed. Due to the large thermal load of the Apollo process, a new multistage 

boiler had to be fitted, along with significant upgrades for DI water service, compressed 

air, electrical drops, and air handling systems. Coordination of the various trades was 

daunting, as up to a dozen subcontractors were on-site along with crews numbering 

several dozen at times. Original estimates to put these new services in place were 

exceeded by wide margins as existing services had to be removed, in most cases, in order 

to install the new services. Moreover, the extremely short project timeline required 

reliance on design-to-build (DTB) contracts, as opposed to specification and firm fixprice quotations. DTB contracts can save time, but are generally more expensive and 

difficult to manage. An outside construction management firm was employed. Overall, 

the facility upgrades exceeded “stand-alone” construction estimates by about 100%.31

Hazardous Waste and Environmental Control Equipment 

The project effort to identify, characterize, quantify and treat the hazardous waste byproducts of the Apollo process was handled in an expeditious and cost-effective manner. 

There were a number of antecedents leading up to this outcome. First, the R&D team had 

carefully noted and documented the hazardous wastes produced in their UK laboratory, in 

response to strict corporate health, safety and environmental (HS) guidelines. Second, the 

UK member of the technology transfer team was well informed regarding the hazards 

associated with the Apollo process since he was the site HSE officer. Third, the Fairfield 

team was able to engage a BP pre-qualified environmental engineering firm in the Bay 

area. The environmental firm’s study of hazardous-waste treatment was funded, in part, 

under a subcontract with NREL. Fourth, the first engineer hired at Fairfield was a qualitycontrol specialist for a major chemical manufacturer and, as such, was very 

knowledgeable as to chemical hazards, waste treatment suppliers, and applicable 

regulations. In short, the requisite expertise, staff resources, and funding quickly fell into 

place. 

The authority to construct (ACT) permit for air emission abatement equipment was 

issued in July 1997 by the Bay Area Air Quality Management District (BAAQMD). 

Following discussions with the local sewer district, the wastewater stream treatment prior 

to discharge was identified and established. All necessary environmental control 

 37
equipment was ordered, installed, and qualified by mid-year 1998. There were no cost 

upsets, and permits to operate were eventually secured for start-up. 

Fairfield Equipment

Renovation of existing APS equipment was scheduled on an “as-needed” basis over the 

years 1997-2000. The most significant upgrades, in terms of cost, involved the laserablation stations. By 2000, the existing Fairfield laser technology had insufficient power 

and other optical properties to reliably scribe Apollo substrates. The semiconductor and 

back contact material were considerably thicker in Apollo than that used by APS to 

produce a-Si material. Further, the use of tempered CTO substrates introduced flatness 

variations that necessitated beam optics with larger depth of field. The cost to upgrade all 

the laser stations and respective controllers was approximately $250,000 in 2001. Other 

“legacy” Fairfield equipment, such as glass washers and laminators, necessitated 

overhaul to replace aged parts, which was accomplished at modest cost within routine 

maintenance budgets. The buss foil applicator for a-Si APS modules was not usable for 

Apollo despite best efforts, eventually leading to the adoption of foil-tape prior to 1999, 

and then conversion to frit buss bars derivative of the parallel a-Si factory (Toano, 

Virginia). Other general-purpose conveyors and worktables were used as is. The edgedeletion equipment received a major overhaul to significantly enhance capture of ablated 

material, so as to trap cadmium particles. The metal sputtering system was used as is, 

although the metal target materials were modified over time to enhance performance of 

Apollo modules. 

Operator and Technician Recruitment; & Product and Process Reliability

As it turned out, the first phase of the Apollo project from 1997-1998Q3 was mainly 

concerned with proving that the Apollo CdS-CdTe deposition equipment was capable of 

depositing a semiconductor film on large substrates. By the end of 1998Q2 the Apollo 

team was satisfied with the back contact process based upon studies using CdTe coated 

substrates from another company. Corporate leadership change in late 1997 did lead to 

inquiries regarding the financial and market underpinnings for the Apollo project. The 

earlier “supply constrained” premise did not survive close scrutiny by new marketing 

staff at Fairfield. There were new questions as to the technical feasibility of the Apollo 

CdTe deposition train. Responses to such questions were difficult in early 1998, as the 

equipment had not been delivered, much less installed and qualified. The financial 

viability of the Apollo enterprise was thoroughly analyzed with respect to alternative 

scenarios and their inherent risks. While the top-down management review was taking 

place, the Fairfield technical team continued efforts to improve the process, albeit with 

only a single prototype CdTe reactor. 

The recruitment of a full complement of operators and technicians was set aside for the 

moment. Product reliability and environmental studies were also limited since Apollo 

CdTe deposition equipment was not yet installed at Fairfield. Both recruitment and 

product evaluation tasks became more consequential in the third phase of the Apollo 

project, following after the 1999 efficiency stretch and the Apollo commercialization 

stage-gate in June 2000. 

 38
Beginning in 1998Q2 the fabrication and assembly of the 8-tank CdTe deposition system 

was assigned to a special engineering team comprised of a senior project manager from 

BP, senior chemistry technologists from UK and Fairfield, and a Fairfield mechanical 

engineer. All members of this team were expected to work on site at the company 

building the CdTe deposition system. 

The balance of the Apollo engineering and technology team continued efforts to refine 

and qualify the post-deposition processes. Progress in the development of the lamination 

and encapsulation process was limited as the appropriate engineering positions were not 

on board as yet. The installation of the equipment to control hazardous waste materials 

was continued. 

Apollo Technology – Stage-Gate and Efficiency Stretch: 1998Q3 – 2000Q2 

Stage-Gate #1: Equipment Capabilities – CdTe Prototype Reactor (Oct, 1998) 

The first stage-gate demonstration was undertaken in October 1998. While awaiting the 

completion and delivery of the eight-pack CdTe deposition system, it was important to 

determine whether the prototype reactor unit was capable of depositing a CdTe film over 

the CTO-CdS substrate. As mentioned above, the OEM supplied a prototype reactor 

chamber that was expected to be the same as the 8 chambers in the production unit when 

delivered. There was a certain level of concern associated with the CdTe system, ranging 

from the mundane – did it leak cadmium solution – to the sophisticated – was a 

stoichiometric CdTe film deposited in the reactor – and the momentous – did the CdTe 

film exhibit semiconductor properties. The principal scientists responsible for the design 

of the CdTe reactor system carried out the demonstration. After several weeks, the 

prototype reactor performed as expected, albeit with much “hands-on” input by the 

scientists. 

Stage-Gate #2: Process Capabilities – CdTe Prototype Reactor (Jan. 1999) 

The second stage-gate demonstration was completed in January 1999. Shortly after the 

October stage-gate was completed, the full eight-pack CdTe deposition train was 

delivered and services connected. At this juncture, however, the individual reactor 

chambers were not completely fitted out. The decision was made to accept the equipment 

as is, because the OEM had been struggling with the build for some months. Before funds 

were released to completely fit out the eight-pack, it was important to demonstrate that 

the CdTe electrochemical process in the fitted-out prototype reactor was capable of 

producing viable product. The second stage-gate targets for a 200-plate lot included 

efficiency (average η ≥ 6% & std dev ≤ 0.7%), overall yield (≥ 80%) and related results.. 

This stage-gate was successfully completed.32

Stage-Gate #3: Process Capabilities – CdTe 8-Pack Reactor (April 1999)

The third stage-gate demonstration dealt with the eight-pack CdTe reactor and its process 

capability. The stage-gate #3 pass criteria were identical to those of stage-gate 2. Stagegate #3 was successfully completed in April 1999. 

 39
Up to this point, the Fairfield team was working toward the start-up of the 0.55m2

 Apollo 

line in 1999. With the merger of BP Solar with Solarex, new questions were raised, 

namely, “which thin-film process had the best hopes for commercial success – the Apollo 

cadmium telluride at Fairfield, California, or the Millennia amorphous silicon at Toano, 

Virginia?” After technical discussions and exchanges of cost and performance data, it 

was concluded that neither thin-film technology had a clear cost advantage or a 

performance advantage as both produced modules with aperture efficiencies on the order 

of 6%. However, as the Toano plant was further along in terms of its production rollout, 

the Fairfield process became the “challenger” technology. The Apollo technology had to 

demonstrate a clear advantage in terms of product performance or cost in order to 

survive. 

The Fairfield team was given a mandate to undertake an “efficiency stretch” project for 

the 0.94m2 Apollo module, with the goal to significantly boost module power at a cost 

that demonstrated a clear and convincing comparative advantage. The Fairfield team 

sought the advice and assistance of the NREL thin-film staff as well as the scientists at 

the Institute of Energy Conversion at the University of Delaware. Both organizations 

provided excellent technical advice and supporting analyses that were extremely useful in 

progressing the Apollo CdTe technology at Fairfield. 

Stage-Gate #4: High Efficiency > 6% Process Capabilities – CdTe 8-Pack Reactor 

(Sept. 1999)

The fourth stage-gate demonstration looked at the production of 0.94m2 substrates with 

efficiencies in excess of 6% (~ 50Wp). At this stage, only the eight-pack reactor 

equipment was utilized. Based on supporting studies by NREL and IEC research 

scientists, the Apollo process team began looking at ways to improve the performance of 

the CdTe absorber layer. A post-deposition process was developed to facilitate grain 

growth, which resulted in overall module efficiency going from 6% to about 7% or 

~60Wp with the 0.94m2 size module.33 The stage-gate 4 pass criteria were similar to 

those for stage-gate 3, and were successfully completed in September 1999. 

Stage-Gate #5: High Efficiency > 7% Capabilities – CdTe 8-Pack Reactor (Dec. 

1999)

The fifth stage-gate demonstration looked exclusively at the production of 0.94m2

substrates with efficiencies in excess of 8% (~70Wp). This stage-gate addressed the 

stability of the Apollo module over 500 hours of light soak under load at controlled 

temperature (50°C ± 5°C) and irradiance (800w/m2

 ± 5%).34 Stage-gate 5 was attained in 

December 1999. 

Stage-Gate #6: Very High Efficiency ~10% Capabilities – CdTe 8-Pack Reactor 

(April 2000) 

The sixth stage-gate demonstration looked at the production of 0.94m2 substrates with 

efficiencies in excess of 8% (~70Wp). The technical challenge was to reduce the losses in 

the window or CdS layer. This was achieved by reducing the thickness of the CdS layer 

without compromising the electrical properties of the semiconductor. A process was 

developed whereby a high-resistance layer was placed over the CTO prior to CdS 

 40
deposition. The CdS layer thickness was reduced by about half, which allowed more blue 

light to pass through to the CdTe layer and increased the quantum efficiency of the 

Apollo device. Module efficiency on order of 10% (~85Wp) was achieved for a 

significant number of units. This stage-gate was achieved in April 2000. 

Stage-Gate #7: Commercialization of VHE Apollo Modules (June 2000) 

This stage- gate was anticipated with eagerness by the Apollo technology team. The 

meeting was organized in June 2000 and involved marketing and corporate staff for the 

first time in many months. A number of issues were discussed, including the status of the 

technology, manufacturing capability, staff needs, product qualification and production 

ramp plan. 

The outcome of the meeting was a directive to develop an overall business plan including 

product specification and qualification, manufacturing costs, staffing, capital expenditure, 

manufacturing ramp plan, sales forecast, and product stewardship plan. The next section 

will discuss the cost and schedule consequences that emanated from the 

commercialization strategy discussions. 

Commercialization and Manufacturing: 2000 – 2002 

Manufacturing Process Changes for 10% Modules:

The Apollo process and technology had evolved during the previous two and a half years 

as the result of the efficiency stretch improvements. The manufacturing process to 

produce modules with 10% efficiency (or 80 watts) had grown in complexity, however, 

through the introduction of new materials, new handling steps, and new equipment. 

Figure 6 presents a simplified schematic for the “10% efficiency” Apollo process, which 

was expected to yield “80Wp modules” on average, as well as improved reliability. The 

efficiency gains involved process steps #02, #03, #05 and #07 in the schematic. 

Reliability gains came from change to heat strengthened glass (#01) and use of vapor 

barrier (#14). The schematic is simplified in that only 16 macro-processes are broken out. 

Underlying each of the 16 macro-processes is a bundle of discrete processes, numbering 

in excess of 42 to produce a glass-to-glass laminate. These 42 processes, in turn, do not 

reflect other offline procedures such as preparing solutions, process control 

measurements, operation of environmental control equipment, equipment setup and 

teardown, and similar procedures. Moreover, the 42 discrete procedures do not include 

the steps required to build the other module types (e.g., frame) desired by product 

managers. 

As displayed in Figure 6, there were three major process subsets at Fairfield, namely 

Deposition Process (#01 - #08), Back Contact Process (#09 - #13) and Module Process 

(#14 - #16). A fourth major process subset – Environmental Control – is not depicted, but 

was just as critical to the successful operation of the Apollo manufacturing line. 

 41
Specific engineers and technicians were assigned principal areas of responsibility, but 

everyone was expected to participate in daily and weekly meetings to troubleshoot yield, 

quality or performance shortfalls. Root cause and corrective action initiatives were daily 

occurrences as the manufacturing line began to ramp in 2001. As discussed later, line 

yield and environmental stress reliability matters consumed significant engineering, 

technology and production staff resources. 

The process changes to improve aperture efficiency came at a cost in almost every 

circumstance, either in terms of material, direct labor or handling, cycle times, or new 

equipment. The type and approximate impact of the major changes are summarized 

below. 

Process #02 Sputter HR Buffer Layer – this new process added nominal material costs for 

sputtered metal and masking tape. The more significant cost was higher direct labor costs 

and a bottleneck at the sputtering system station. The bottleneck eventually would 

impinge on capacity. The direct cost of the HR buffer layer at low volumes was roughly 

$0.02 – 0.03 per W or $2/m2

, and a scheduling workaround challenge. 

Process #03 CdS Deposition – thinner window (CdS) layer was accomplished by using a 

shorter cycle time; which, in theory, lowered direct labor – but the resulting labor 

efficiency gain was minimal. 

#01 #02 #03 #04

Glass Wash & Inspect Thermal Clean CdS Deposition CdS Heat Treat

Sputter HR Layer

#08 #07 #06 #05

Surface Etch & CdTe Grain Growth CdTe Heat Treat CdTe Deposition

Cu Doping & Heat Treat

#09 #10 #11 #12

Laser 1 Cell Isolation Insulation/ Laser 2 Isolation Sputter

Back Contact Film Metal Interconnect

#16 #15 #14 #13

Final Inspection Encapsulation Edge Delete/ Laser 3 Isolation

Vapor Barrier

Major Process Upgrade

Deposition Process

Back Contact

Module Process

Figure 6. APOLLO SIMPLIFIED PROCESS FLOW - 10% EFFICIENCY [80Wp]

Color Key

 42
Process #05 CdTe Deposition – the efficiency stretch program concluded that a thicker 

CdTe layer improved device performance, which required a longer deposition cycle, and 

reduced plant capacity in units by approximately 25%. While the unit reduction was 

offset by higher electrical yields, it was concluded that fixed cost per unit or watt was 

adversely affected, and ways to shorten the CdTe cycle time were under consideration. 

Process #07 CdTe Grain Growth – this process change had nominal material costs, but 

did require the addition of equipment costing about $300,000 and required more energy. 

The depreciation cost per watt was minimal at the targeted eight megawatt (8 MW) run 

rate. 

Other Cost Impacts

There was a major unplanned cost upset during the 2000-01 period. It appeared as an 

extraordinary rise in the price of electricity in California. Due to a breakdown in the 

power delivery system in California, early forecasts indicated that utility costs on order of 

$0.07-0.10 per watt ($5 - $8 per m 2) would be incurred at full-run rate. Investigations of 

how best to offset higher utility costs were set in motion, including installation of a large 

grid-connected Apollo array at the Fairfield site. 

Product Plan and Impact

Following onto the commercialization stage-gate in June 2000, the Apollo venture came 

under the auspices of corporate gatekeepers for product design. 

Heat-Strengthened Glass

One product design requirement was the use of heat-strengthened glass in the Apollo 

product. The Fairfield engineering team ran small lots through the deposition and 

encapsulation line. Fully tempered 0.55m2 (14” x 61”) CTO glass lost about 50% of its 

surface compression, thereby falling into the heat-strengthen (HS) range (≤ 10k psi) after 

going through the Apollo process. Module electrical performance was acceptable. Other 

tests with HS rear glass (14-by-61 inches) indicated lower adhesion and some bubbles 

after lamination. Other process issues with heat-strengthened glass did eventually 

emerge. 

With the above HS test results in hand, it was judged that CTO substrates could be 

tempered concurrent with “firing the frit buss” with modest additional costs based upon 

discussions with TF1 staff and their supplier. One alternative for the frit-buss – metal foil 

with two-sided tape -- was unreliable under environmental stress conditions. The product 

management team requested a cost comparison for annealed CTO and rear cover glass, 

tempered CTO and annealed rear cover glass, and tempered CTO and HS rear cover 

glass.35 The approximate and initial cost differences are presented in Figure 7. The cost 

estimates for the HS-CTO and HS-Rear glass were guesstimates from the glass fabricator 

who would process truckloads with racks of annealed tin-oxide coated (CTO or TEC) and 

annealed clear (CLR) glass as shipped from the LOF float glass foundry. 

 43
Figure 7. ANNEALED vs. HEAT-STRENGTHEN CTO & REAR 

GLASS

$0.25

$0.36

$0.48

$21

$31

$40

$0

$10

$20

$30

$40

$50

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

Annealed: Annealed HS CTO: Rear Anneal HS CTO:HS Rear

$/Wp

$/m2

$/Wp $/m2

The base case – Annealed CTO and Annealed Rear – glass costs in the chart ($21/m2) 

were gathered from local and internal sources. Subsequently, base case costs for 

annealed/annealed units were underestimated by 30% or so, while the HS/HS 

configuration costs were about 5% lower overall. All-inclusive quotes from the glass 

fabricator for scribing the CTO glass to size, edge seaming, washing, drying and racking 

for shipment to Fairfield was about $2.50/m2

. The “low ohm” CTO glass used at Fairfield 

was priced by LOF at about $15/m2

 for modest truckload quantities. For CLR glass, the 

raw glass with seamed edges was about $9/m2 (vs. $3/m2 as originally thought using inhouse seaming process). 

With the HS-CTO product, in addition to the cutting and seaming operations, the 

fabricator had to dispense conductive frit ($6/m2

) and cure the frit ($4/m2) while 

tempering the CTO. Tempering the CTO glass, with one clear side and the other being 

tin-oxide coated, while holding flatness and compression specifications across the 

0.945m2

 surface turned out to be a technology challenge for the fabricator and eventually 

a cost upset. Gaining agreement on how to measure surface compression using nondestructive means was difficult using available instrumentation. The HS process with 

CLR glass was more straightforward. A significant cost variable was the yield loss at the 

fabricator level. Over time it was anticipated that higher volume and more robust process 

control by the fabricator would secure lower unit costs, on order of 5 – 10% perhaps. 

 44
Despite the large “guesstimated” cost differences, it was decided to proceed with the HSCTO and HS-Rear glass for Apollo because it was thought the final product would have 

greater acceptance and field reliability.36

Product Stewardship

Another issue considered by the Apollo Commercialization team was the question of 

product stewardship. At the Fairfield plant, substantial technical and financial resources 

were devoted to the abatement of environmental risks. The Fairfield plant had gained 

environmental (ISO 14001) certification. All employees were instructed regarding the 

proper methods and personal safety gear required by each operation where there was 

some risk of exposure to cadmium feedstock, as well as other safety and environmental 

hazards. The feedstock was present as cadmium solutions inside equipment hoods with 

separate air handling gear, which went a long way toward reducing workforce exposure. 

Early engineering studies concluded that finished modules and post-lamination line scrap 

easily passed the Toxic Characteristic Leach Procedure tests established by the U.S. 

Environmental Protection Agency (EPA), which meant such scrap could go into ordinary 

municipal landfills except in California. All Fairfield line scrap was disposed of as 

hazardous waste. 

The issue of handling Apollo modules was addressed once again in anticipation of highvolume Fairfield manufacturing, and the shipping of large quantities of Apollo modules 

around the country and, in time, throughout the world. In general, the marketing plan for 

Apollo was to seek out partners who were large grid-connected installers. Preferably, 

these commercial arrangements would take place for projects of 50kW or greater. By 

limiting the distribution channels, it was thought the handling and return of scrap Apollo 

modules to the Fairfield plant could be achieved in an economic manner. Once reaching 

the Fairfield plant, any scrapped modules would be properly disposed. 

Environmental standards were evolving and it was concluded that a “cradle-to-grave” 

(vs.” cradle-to-cradle” advocated by some) stewardship program would be initiated.37 On 

the basis of very preliminary cost estimates to ship modules from, say, India to 

California, warehousing and transit costs to a smelter operation where the scrap modules 

would be used as flux, an accrual charge of $0.05 - 0.15/Wp ($4 - $12/m2) may be 

necessary as a stewardship cost. A project was organized to scope the handling of local 

Apollo scrap and future material returns. Discussions were initiated with a smelter 

operator in the northwest. 

Manufacturing Ramp Plan

The Apollo manufacturing line incorporated some major upgrades in terms of existing 

equipment, as well as the purchase and installation of new material handling and process 

equipment to improve operational efficiencies. Also, the eight-pack CdTe system had to 

be completely fitted out as only one tank had been upgraded for the efficiency stretch 

quest. 

As the new equipment was brought onboard, the limitations of certain facility services 

also came into play. Upgrades to services such as boiler water distribution, pneumatic 

 45
distribution, DI water and electrical services were initiated. The environmental abatement 

equipment also was upgraded in certain areas. Additional quality-control equipment for 

assessing deposition solutions, as well as wastewater streams became critical. The 

encapsulation line also required an influx of new (e.g., inline IV tester) equipment and 

the refurbishment of other equipment. 

The encapsulation process and equipment capabilities were particularly significant as 

product qualification tests were undertaken. The glass-to-glass Apollo module, using HS 

substrate and rear glass, failed the 1,000-hour damp heat (1000hr DH) test. The newly 

hired encapsulation engineers had to identify a new edge and wire hole vapor barrier 

process to protect the Apollo thin-film, which was predisposed to moisture induced 

corrosion. Annealed glass off a float line is typically very flat. The HS process for glass 

introduces stresses that can introduce curvature onto the surface of the glass. A glassglass laminate configuration will typically result in “gaps” between the CTO side and the 

Rear side. These edge gaps permitted ingression of water vapor that attacked the thin-film 

material and eventually lead to performance degradation in the module. Working closely 

with a specialty adhesives and sealants company, an extruded butyl sealant material was 

developed that, and once applied along the edge of the glass-glass laminate, acted to 

prevent DH failures through the edges. Another material was developed for the wire-hole 

pottant where leads were soldered to the conductive frit. The challenge here was to 

identify a material(s) that was impervious to water vapor, firmly encapsulate the wire 

solder interconnect and yet be flexible enough to not break the solder connection at the 

frit surface during thermal cycles. The vapor barrier process was a critical path item 

before a general product introduction was possible. 

While the moisture barrier effort was underway, corporate product engineering 

simultaneously wanted to qualify various framed module configurations for Apollo. The 

framed module effort added greatly to the workload of Apollo encapsulation engineering 

staff. In addition to the major tasks associated with overcoming DH failures, Apollo 

technology staff was also instructed to consider new EVA material. A 1,000-hour damp 

heat test cycle lasted 6 weeks. Consequently, the conduct of dozens of test samples in 

various test cycles in test chambers at Fairfield, at Frederick MD site, and local 

environmental test houses kept several engineers and quality staff on their toes. 

The fitting out of the eight-pack tank fixtures (e.g., mass transport comb) was also a 

considerable task. To accelerate final installation, an outside contractor was hired to 

organize a rigging and fitting crew. This process took several months to complete. Final 

installation of the tank fixtures had to take place inside the CdTe deposition reactor. 

Special safeguards were implemented to protect the installation team, as regular 

processing of test substrates was ongoing. Once a tank was fitted out, a process to plate 

out impurities was scheduled, which sometimes took a week or more. This was followed 

with qualification lots before the tanks were placed in service. The tank startup timeline 

extended over several months. 

In addition to the hiring of several engineers and technicians in the last half of 2000, full 

production meant the hiring and training of 50-60 production employees. Attracting 

 46
prospective process operators and technicians was woefully inadequate during the first 

quarter of 2001. Based on the advice of outside agencies, the starting rate for production 

employees was raised by about 10% across the board. This had an impact on labor costs; 

but, spread across all cost centers, it was not a major hit at the time. The generic answer 

to avoid higher unit costs was generally to ramp the planned volume and, hopefully, 

observe a corresponding change in units going to stores. 

The Fairfield line began commercial operation in August 2001. Almost immediately, the 

line began to encounter difficulties with respect to yields. Some shakedown is always 

anticipated with start-up, but the yield losses increased right along with efforts to bring 

more CdTe tanks on line. The largest yield loss was at the CdTe deposition process either 

immediately as a visual defect (e.g., incomplete deposition) or later at IV test following 

the back contact process. Additional losses occurred in the encapsulation line due to 

electrical or visual failures, including excessive bubbles entrapped in the laminate, 

misalignment of top/bottom covers, appearance, and the like. 

By the end of 2001, the cumulative line yield was only one-half of plan (65%), which 

was initially judged as being a reasonable target. The overall cost impact of the excessive 

yield loss is unknown, but a reasonable guesstimate would be about $0.35/Wp or about 

$30/m2. This is a shocking cost increase, of course, and the entire technology and 

engineering team spent countless hours battling to regain control of line yield. 

Interestingly, studies of process variations did not suggest that the equipment was not 

working or was set-up incorrectly. Rather, the largest defect was visual at CdTe 

deposition, followed by electrical losses. The process finally achieved target yield at the 

end of January 2002, and operated until November 2002, when the line was shut-in. 

Thin-Film Costs 

The cost to manufacture thin-film PV product has several major components as outlined 

above for the TF1 experience. Estimating the cost of manufacturing thin-film modules 

across a number of different companies during the past decade or so, there seems to be a 

striking similarity for the direct materials used in each instance, as well as direct-labor, 

manufacturing overhead and so-called fixed costs, such as plant management, 

engineering, facility costs, and assigned central support (HR, accounting, administration). 

Based on several production cost benchmark exercises for TF1 and Fairfield, the Apollo 

cost model developed for financial planning and forecasting purposes was similar to that 

for Millennia (TF1), not withstanding large differences in the fundamental technologies 

and how the thin-film device was produced. 

One key driver to reducing unit costs, thereby moving closer to positive gross margin, 

was always higher module efficiency or peak watts (Wp) – the higher the Wp, the greater 

the divisor in any financial projection and the lower the unit cost. A second key driver for 

financial planning was greater volume of production, and the sooner the better, in order to 

spread sizable fixed plant, equipment and manufacturing support costs on per unit basis. 

A third cost driver is line yield usually followed by line efficiency and lower material 

costs. The planning analyst objective was usually focused on the “hockey stick” 

 47
production ramp, thus achieving the more “straightforward” and less “technical” cost 

reduction. The volume-is-easy perception is often misplaced as greater volume during 

start-up oft times can dissipate the engineering focus and efficacy by introducing too 

many realities into the mix and may be less likely to achieve the “straightforward” gains. 

Allocation of technical resources during the start-up of a new technology is a challenge. 

Figure 8 presents a pie chart of the typical material costs to manufacture a glass-to-glass 

thin-film (TF) module with dual-lead interconnects, U-channel brackets for system 

mounting, and packaging for shipment. Costs to produce units with extruded aluminum 

frames as used to manufacture crystalline-type products are greater than the simple Ubracket, on order of two times greater than the mounting bracket for the glass-to-glass 

configuration.38

Figure 8. Typical TF Direct Material Profile

Bracket+ 

EdgeSeal

Wire Asm

Box (Bulk)

HS-Rear 

CTO+TF+BC/Mtl Gls/EVA

HS-Front Gls/Frit

Total material costs for an 80-watt module are estimated at $0.85 per watt ($68/m2). The 

material composition of a finished TF module is displayed in Figure 8 by rank from 

highest to lowest percentage of cost. The direct material item, percentage and cost per m2

are as follows: 

1. ~31% -- Heat Strengthen (HS) Front Glass (edge finish) and Frit buss ($21/m2

), 

which is the substrate upon which the thin-film device is deposited; 

2. ~25% -- CTO plus TF material ($17/m2

) that includes all thin-film materials from 

CTO layer to semiconductor to back contact and metal; 

3. ~21% -- HS-Rear Glass/EVA at ($14/m2

) with edge seaming; 

4. ~8% -- Box (bulk packaging) & labeling at ($6/m2); 

5. ~7% -- Wire Assembly ($5/m2), comprised of J-box, pottant, wire leads with 

male/female connectors; 

6. ~7% -- Bracket/ Sealant ($5/m2), for mounting the module and sealing edges from 

moisture. 

 48
The requirement for HS-CTO and HS-Rear glass for Apollo imposed a cost on order of 

$4 - $5 per square meter (~$0.05/Wp). Both HS processes were additive to direct material 

costs for Apollo. The Frit/Temper process applied to CTO glass accounts for 75% of the 

total HS cost in Apollo, but was an essential process for “firing” the conductive frit buss 

collector in any event. If the frit buss system is eliminated, the HS costs could arguably 

be reduced. Other CdTe processes may achieve in situ heat strengthening of the TF 

product. 

The Apollo CTO, CdTe semiconductor material, back contact and metallization cost is 

about one-fourth of total material cost in the above configuration. Adding the HS-Front 

Glass substrate, the percentage is about 56%39. The remaining cost elements, which 

comprise 44% of the total material cost, are also requisite in the production of crystalline 

modules in many instances. The ability to achieve greater material cost savings by 

reducing only the thin-film semiconductor material costs is limited. 

Another way of looking at thin-film module costs is to recognize that their use in large 

power arrays imposes additional balance of systems (BOS) costs because the power 

density (Wp) per square meter is lower. In the case of the Apollo module, the power 

density is about 80W/m2

 given the overall 24”x61” footprint. By contrast the size of a BP 

multi-crystalline 80W module is only 0.65m2, which is equivalent to approximately 

123W/m2. Hence, the multi-crystalline 80W module’s power density is about 50% 

greater than the Apollo module put into production at Fairfield. Since BOS costs are 

approximately linear with overall array footprint, the Apollo module cost would have to 

be reduced on order of 50% to offset greater BOS material and installation costs. There is 

little prospect to achieve such large cost reduction for thin-film modules generally. The 

answer still comes down to power rating and power density. Prototype Apollo array 

calculations concluded that a sizeable total cost/performance shortfall would persist 

relative to higher power density crystalline Si units. The lower power density of the 

Apollo module, even if its module costs were significantly lower, still must confront the 

area-related balance of system costs for an array. 

The discussion thus far only addresses thin-film direct material costs, which are typically 

much lower than crystalline Si direct materials due mainly to unit wafer/cell costs. 

Looking at post-lamination crystalline module assembly labor costs, there isn’t a great 

difference with thin-film module assembly efforts. Both types typically involve soldering 

wire leads to the interconnect buss, mounting a J-box, IV testing, installing an optional 

mounting system (e.g., frame), cleaning, labeling, and packing. The crystalline tabbing, 

lay-up, and lamination process were very labor intensive in comparison to thin-film laser, 

metallization, edge-deletion, and lamination steps. Several companies have come forward 

with automation for the processing of crystalline modules in these areas. There may still 

be significant cost advantages for thin-film deposition, as opposed to wafer sawing and 

coating, but needs to be proved out, as some operations of this type appear to be 

narrowing the labor cost gap. 

Generally speaking, the engineering, maintenance, and plant management costs would be 

quite similar for thin-film as for crystalline PV module manufacturing. Overall thin-film 

 49
modules can cost less than x-Si on a direct material basis. However, to the extent thinfilm units are to put into field arrays, the greater area required per system output target 

imposes substantial cost increases in BOS materials and possibly field installation labor 

as well. The Apollo module may have gained sufficient power density in time, but the 

possibility of commercial success was problematic pending success in the field. Full 

qualification of the Apollo product and manufacturing process was certainly years away. 

Thin-Film Technology and Manufacturing Ramp 

Manufacturing technology is different from R&D technology in one very important 

sense. While a handful of “superior” thin-film devices (or even a few hundred devices) 

may be produced in the laboratory, they are produced under very different circumstances. 

First, the equipment and materials used can be top grade, as cost savings on the order of 

pennies is not critical for a R&D demonstration. In any event, the quantities consumed in 

making the breakthrough devices will be modest. Second, the R&D laboratory staff will 

typically include highly trained and motivated individuals. Thirdly, the R&D timeline is 

such that compared to profitable factory operations, the rate at which the advanced 

devices are made is, in a word, “glacial.” 

The Apollo R&D team spent about 10 years developing the CdTe electrochemical 

process. The Fairfield engineering team was allotted 24 months in which to bring up a 

manufacturing line on a scale that was two orders of magnitude greater than the R&D 

device production rate. This relationship of R&D experimental time to targeted 

manufacturing start-up time has been observed in other companies as well. 

The quantity of material to be consumed in manufacturing takes on a whole new 

dimension. In Fairfield, chemical solutions were delivered in totes that could only be 

handled with a forklift. CTO glass came in truckloads and was fabricated on a float line 

flowing at rate of 20 to 30 feet per minute, or about 20 tons of glass per hour. 

Manufacturing processes had to be controlled on a 24/7 basis and, more importantly, a 

means of monitoring the thin-film process so as to detect out-of-control situations before 

a ton of material (about 120 substrates) had to be scrapped. Equipment maintenance and 

calibration needed to be “95/95” capable of uptime and in six-sigma control. The large 

quantities of direct materials and the law of large numbers will undoubtedly produce out 

of specification values never seen or considered by the R&D team. Manufacturing 

engineers also have to develop a repertoire of “trouble-shooting” techniques to correct for 

unusual circumstances created by variations in materials, equipment, operators, and plant 

services. 

Perhaps a better way of drawing the distinction between R&D levels of expertise and that 

in manufacturing is to consider the cycle time per module. A 10-megawatt thin-film line, 

producing an 80-watt unit over a 50-week period, has to produce a finished, quality 

module every 4 minutes working on a 24/7 basis. This does not take yield into 

consideration, so the 10MW cycle time is typically much more compressed. And, by the 

way, cost and product mix targets must be met while accommodating engineering trials to 

test better methods or to develop new products. 

 50
High-volume manufacturing of a commodity (for Apollo watts installed in an electrical 

grid) is a very tough game. It took a long time to assemble the first-rate engineering 

Apollo team at Fairfield. Eventually, the team would have successfully brought Apollo 

manufacturing up to an acceptable level. However, business plans for thin-film 

technology often exhibit negative cash flow for many years. Once major spending begins, 

it is difficult to convince investors to patiently wait for a return.40

 51
End Notes 

 

1

 Original strategy proved infeasible because it assumed product attributes (manufacturing cost and 

efficiency) that were not achieved and also assumed power sales/financing terms and government 

concessions that were not successfully negotiated 

2

 It was feasible to sell TF modules into markets where crystalline modules were the standard offering, but 

in traditional markets, TF prices had to be substantially below crystalline prices, and TF manufacturing 

costs were higher than originally targeted, resulting in negative cash flow. 

3

 The initial strategy envisioned sales to a sister business unit developing, financing and operating central 

station PV power plants. In this case, certain market requirements did not apply, including UL certification 

and 20 year module performance warranties. This should not be taken to imply that the product would not 

have been safe in a large array context nor have lifetimes appropriate to the solar farm application, but 

rather that, for example, meeting standards appropriate to a 10 year warranty would have been acceptable. 4

 The report deliberately does not address the relative advantages and disadvantages of the TF1 

manufacturing process in relation to a-Si manufacturing processes being developed or used by other 

companies. Analysis necessary to do so professionally and credibly was not within the scope of work 

authorized by NREL. 

5

 The Chronar Corporation originally developed a batch plasma deposition process for making amorphous 

silicon substrates. After Chronar filed bankruptcy in 1990, the principal investor formed Advanced 

Photovoltaic Systems, Inc. (APS) and continued development of the a-Si deposition process at a Trenton 

NJ pilot plant. APS eventually transferred the technology and equipment to a special purpose plant in 

Fairfield, CA in 1992 – 93 and operated it in limited production until bankruptcy again intervened. Factory 

assets were eventually purchased by BP Solar. 

6

 Process throughput is a measure of how many units are processed per unit of time. It a major factor in 

determining actual plant capacity, which in turn affects fixed costs per unit. 

7

 First of a kind factories experiencing start-up and production ramp delays can incur significant additional 

capital expenditures. 

8

 Module cost per Watt allows a first order comparison. Installed system costs depend on module 

efficiency as well as unit cost. The effect varies according to mounting structure, wiring and costs that 

scale with area, weight, etc. 

9

 For example, see M.S. Keshner and R. Arya, “Study of Potential Cost Reductions Resulting from SuperLarge-Scale Manufacturing of PV Modules, NREL Sub-contract Report NREL/SR-520-36846, October 

2004. 

10 There is, as yet, little federal support of longer-term, higher risk plug-and-play product innovation and 

enabling technology. 

11 It is reasonable to ask and important to answer whether the cost experience reported and discussed 

applies directly to thin-film generally or other factories specifically. Of course it does not. The reader may 

choose to assume the Millennia and Apollo experience was an artifact of idiosyncrasies of the specific 

manufacturing processes and business contexts and has no other applicability. Or the reader may choose to 

infer general or specific lessons that apply in other cases based on his/her direct knowledge of the other 

cases. 

12 The initial commercialization strategy selected by the venture sponsors was very aggressive, resulting in 

considerable competitive advantage if successful, but also significant additional risk. 

13 See note i 

14 Initial plant cost estimates were based on aggressive assumptions regarding product efficiency, process 

speed, and total yield and were based on conceptual, not detailed engineering estimates. These various 

factors were not completely independent. Trade-offs became better understood based on pilot runs and ongoing process development. The final choice, driven by the need to achieve targeted plant capacity, 

dictated additional chambers. 

15 At the time, manufacturers of coated glass did not aggressively respond to the nascent a-Si PV 

manufacturing industry (the validity of a large future market was not demonstrated) and may have priced 

their offerings accordingly. 

 52
 

16 The basis of the initial depreciation estimate is not available to the authors. The re-estimate did not, to 

the authors' knowledge, reflect an assumption of extended start-up at low production as actually occurred. 

17 Intial cost estimates were completed by an R&D organization based on conceptual rather than 

preliminary or detailed engineering. In a project context, considering the risks and unknowns, 

contingencies well in excess of those typical at this stage of project development for lower risk projects 

would have been appropriate, e.g. >50%. The choice between budgeting for the unknown and risking 

budget overruns is faced routinely in private and public sector undertakings: overruns and missed cost 

targets are by no means uncommon when pre-commercial technologies are involved. 

18 Project cost estimation theory and practice in other fields relies on the use of project and line item 

contingencies to account for the impact of changes needed to achieve a project's specification. Those who 

seek funding for scale up steps in PV development and manufacturing are faced with the dilemma of 

including contingencies in their estimates and thus jeopardizing their prospects for funding, or not 

including them and thus jeopardizing the ability to achieve projected costs. 

19 The problem of high area related costs incurred in using Millennia in rooftop applications was addressed 

in two ways. First, government commercialization grants were applied specifically to offer the modules at 

a discount that more than off-set the area related cost penalty. Second, an innovative module framing, 

interconnect and mounting system was developed that resulted reduced area related and installation costs to 

a bare minimum. This patented approach reduces crystalline residential rooftop system installed costs by 

10 to 15% and is an important spin-off of the Millennia effort. 

20 Edge connector development was conducted under serious time pressure from the customer and also as a 

relatively new R&D target that had not been addressed previously. This context is not conducive to 

exploration of optimal solutions that involve significant technical risk. Parenthetically, it is the authors’ 

view that government programs could effectively provide the context for exploration of higher risk and 

longer development cycle plug and play innovations, including radical innovations that would extend 

system modularity to the level of the DC module. 

21Even the initial limited quantities of "pillow effect" product experienced minimal breakage when installed 

and in subsequent service. However, any reliability problems exceeding customer expectations (based on 

their experience with crystalline products) was considered excessive. Framed Millennia met this standard, 

and so continued sale into these applications was judged to be prudent and acceptable. However, BIPV 

applications of interest to numbers of potential customers, as well as other frameless laminate applications 

preferred by a number of existing customers, were restricted pending introduction of heat strengthened 

laminates. 

22 Estimates assumed tens of thousands of 0.8 m2 units per year. Heat strengthening costs would be 

sensitive to production volume and glass area. 

23 Line yields for silicon solar cells in high volume production currently range from less than 90% to 95% 

according to presentations at the First International Symposium on Photovoltaic Mass Production. See 

http://www.epia.org/08Events/SEMICON2005/SE05_PRES1_07.pdf 

24 D. Shugar, “Strategies for Mainstreaming Grid-Connected PV This Decade”, March 26, 2003, chart #11, 

http://www.nrel.gov/ncpv_prm/pdfs/33586100.pdf 

25 In retrospect, the factory is better viewed as the culmination of an RD&D process than as a self-justified 

commercial project. It could be inferred that “good money was thrown after bad” in pressing forward with 

incremental innovation to solve problems and improve overall results. The same could be said of much 

R&D conducted by US companies and laboratories. 

26 The Chronar Corporation originally developed a batch plasma deposition process for making amorphous 

silicon substrates. After Chronar filed bankruptcy in 1990, the principal investor formed Advanced 

Photovoltaic Systems, Inc. (APS) and continued development of the a-Si deposition process at a Trenton 

NJ pilot plant. APS eventually transferred the technology and equipment to a special purpose plant in 

Fairfield, CA in 1992 - 93. 

27 There were several “Solarex patents” related to the product (recipe) and process used to produce a-Si 

photovoltaic modules. Solarex developed an inline process for producing a-Si photovoltaic modules, and 

eventually scaled up the process at the Toano VA plant. When BP acquired Amoco in 1998, BP Solar also 

acquired Solarex and the Amoco share of a joint venture with Enron in the Toano enterprise. The Enron 

interest was eventually sold to BP Solar as well. 

 53
 

28 The specification of special purpose equipment for the first time is always subject to implicit risks. The 

Apollo technology team addressed the “known risks” in various ways such as requiring versatility where 

possible; but “unknown risks” are difficult since they may reveal themselves only after a large number of 

trials. Tests to correctly identify and remediate the defect become more difficult as the volume of product is 

increased. Unfortunately, the Apollo technology yielded a number of experiential challenges after start-up. 29 Whenever module efficiency (η) is used, it references aperture area efficiency. 30 Final design and delivery of the seven deposition tank fixtures was postponed until midway through 

2000, following successful completion of the Apollo “efficiency stretch” and the “commercialization” stage 

gates over the April 1999 through June 2000 period. 

31 Some of the over budget costs of renovation are one time effects for the home plant. New plant 

construction would be bid with the Apollo requirements upfront and facility costs likely would be less for a 

mature technology. New technology startups, however, seldom have the luxury of securing a special 

purpose building from the ground up, so over budget modifications can be anticipated. 

32 This level of performance for Apollo was about the same as that of the a-Si product produced by Solarex 

at Toano VA on the TF1 line. 

33 In order to successfully process 24-by 61-inch substrates, the Apollo team worked in collaboration with 

LOF, the glass manufacturer, in order to obtain low resistance CTO lites at a reasonable cost. The low ohm 

CTO reduced voltage drop and allows for more uniform electrochemical deposition across the 24” width of 

the substrate. The low ohm TEC glass was priced at about $15/m2 for quantities of 1 – 2 truckloads per 

month. For volumes double this rate, unit costs would be about 5% lower 

34 Source NREL/SR-520-32883 report 

35 The glass-to-glass thin-film module is constructed such that the front glass, with the CTO and CdTe film, 

is attached to the rear glass, with EVA in between. 

36 The CTO was delivered in temper condition, but the Apollo process resulted in a relaxing of the surface 

compression to a HS condition. 

37 Some advocated a “cradle to cradle” stewardship where the cadmium material in scrap would be 

processed and used in manufacturing new material for making Apollo solar modules. Such an arrangement 

was considered, but only as a long-term goal. 

38 The frame configuration cost was approximately 2.5x greater than the bracket configuration due to more 

metal extrusion, more costly wire assembly and 50% reduction in units per bulk package. 

39 The cost values are presented with no yield losses. Generally the yield losses are typically greater for the 

front-end processes, which often take the form of low power, mechanical and visual losses. The front-end 

yield loss would apply to the HS Front Glass/CTO-TF Device, which represents about 56% of total 

material. The yield for lamination and encapsulation is typically higher, but any yield losses at final IV are 

still costly since it involves the next largest material category – HS Rear Glass/EVA. 

 54
F1146-E(12/2004) 

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1. REPORT DATE (DD-MM-YYYY)

January 2007 

2. REPORT TYPE

Subcontractor Report 

3. DATES COVERED (From - To)

 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Experience Scaling-Up Manufacturing of Emerging Photovoltaic 

Technologies 

5c. PROGRAM ELEMENT NUMBER

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NREL/SR-640-39165 

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PVB7.6301 

6. AUTHOR(S)

G.W. Braun and D.E Skinner 

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En-Strat Associates DES Associates 

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Darnestown, MD 20878 Warrington, PA 18976 

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KLCX-4-44450-03 and 

AEK-6-66261-01 

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NREL 

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13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Robert Margolis 

14. ABSTRACT (Maximum 200 Words)

This report examines two important generic photovoltaic technologies at particularly revealing stages of development, 

i.e., the stages between R&D and stable commercial production and profitable sales. Based on two historical cases, 

it attempts to shed light on the difference between: 1) costs and schedules validated by actual manufacturing and 

market experience, and 2) estimated costs and schedules that rely on technology forecasts and engineering 

estimates. The amorphous Silicon case also identifies some of the costs that are incurred in meeting specific market 

requirements, while the Cadmium Telluride case identifies many of the operational challenges involved in transferring 

R&D results to production. The transition between R&D and commercial success takes a great deal of time and 

money for emerging energy conversion technologies in general. The experience reported here can be instructive to 

those managing comparable efforts, and to their investors. It can also be instructive to R&D managers responsible for 

positioning such new technologies for commercial success. 

15. SUBJECT TERMS

NREL; Robert Margolis; solar technology; photovoltaics; cadmium telluride; tandem amorphous silicon; thin-film 

technology; BP Solar; large-scale manufacturing; Apollo technology; Gerald Braun; Douglas Skinner 

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