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Cell and module design from the LCOE perspectiveArticle PV Production Annual 2014

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Development of PV

In recent years the average annual increase in installed PV capacity has been remarkable. According to an EPIA study [1], the worldwide installed PV capacity was 102GWp at the end of 2012 and was estimated to be 145GWp by the end of 2013. This success is primarily attributable to silicon wafer-based technology, which is also set to be the driving technology in years to come. Currently 52% of the European population (EU-27 countries) can already obtain PV electricity at or below grid parity cost (residential prices) [2]. Nevertheless, the currently installed PV capacity accounts for just 2.6% of the total electricity production in the EU-27 countries. This

presents enormous potential.Photovoltaics is a disruptive energy source, responsible

for the largest increase in electrical energy in 2012 in Europe [1]: it will therefore play an ever more important role in the overall energy mix. Photovoltaics is thus in a close interplay with the existing grids, since the energy produced is either fed into the public grid or consumed (or stored) locally to some extent. New calculation methods for evaluating cost-effectiveness and comparability must be considered. The reduction to costs/Wp is no longer sufficient and can affect the development of PV on the whole.

In the past, various terms and methods were employed to evaluate the use of PV or to compare different PV technologies

Cell and module design from the LCOE perspectiveAlexander Hauser, André Richter & Sylvère Leu, Meyer Burger Technology Ltd, Gwatt (Thun), Switzerland

ABSTRACT As the share of PV in the energy mix increases, it is logical to compare electricity generation by PV and other energy sources. A common method is to calculate the energy price by means of the levelized cost of electricity (LCOE): this allows different technologies to be compared on the basis of a standardized calculation, both within PV and with other sources of energy generation. In this paper the PV-module-related technological criteria that have a positive impact on the LCOE calculation are derived. The sensitivities of these criteria are then examined, and the basis for the choice of wafer, cell and module technologies is established with a view to achieving the lowest LCOE values.

Figure 1. Evolution of the economic key figures in PV. Broadly speaking, this can be divided into six phases, from $/Wp through $/kWh and finally to levelized cost of electricity (LCOE) calculations.

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with one another. In retrospect, the economic evaluation of PV can be broadly divided into six phases (Fig. 1).

In the period up to 1998, the so-called pioneer phase, the module costs dominated; the module prices were compared on the basis of power in $/Wp and under standard test conditions (STC). At that time, production chiefly pertained to standalone systems for the electrification of mountain huts (small island systems). The first grid-connected installations had an output of 1–3kWp (Burgdorf model in Switzerland, 1000-roof programme in Germany, etc.), on account of the lack of larger inverters with which to feed the generated DC electricity into the AC grid.

This was followed by the phase with installation sizes between 3 and 100kWp. During this period, the costs of different PV systems were chiefly determined on the basis of the installed system costs, that is to say system costs per installed unit of capacity. The non-module costs, the so-called balance of system (BOS) costs, were added to the module costs. In this way, a comparative value was obtained, namely the system costs per Wp.

In the next phase, the installation sizes grew into the megawatt range, and a new key performance indicator (KPI) was introduced, namely the performance ratio (PR). The PR enabled a comparison of different PV installations to be made and the kWh/kWp value to be determined. At the same time, the PR key figure permitted the feasibility of planned PV projects to be assessed. The goal was to validate the energy generated in relation to the installed capacity using the variables of global radiation, efficiency and system design. In addition, the concept of ‘European efficiency’ was introduced during this time for the purpose of evaluating the efficiency of solar inverters.

The launch of the feed-in tariff (FiT) in Germany in phase 4 brought about the construction of large-scale power plants in the megawatt peak range which called not only for solutions to the technical challenges, but also for new financing models. For this purpose, the preferred approach was to fall back on the discounted cash flow (DCF) analysis, underpinned by the PR. During this euphoric period, the concept of grid parity was increasingly mentioned, and the ultimate goal of PV was to achieve grid parity at residential prices.

In phase 5, disillusionment set in: with the continuing expansion of PV electricity generation, its efficiency then began to be compared with other energy sources in the energy mix. In place of the PR, grid parity and $/Wp key figures, the levelized cost of electricity (LCOE) method was introduced in the PV industry in around 2010. This method enables different energy sources to be compared with one another in a standardized manner and their cost-effectiveness to be assessed. With increasing penetration, PV finds itself obliged to comply with this method of calculation as well. Of course, this makes the challenges faced by PV tougher from an economic perspective, since LCOE values have to be lower than the grid parity at residential prices.

The LCOE concept originated from the construction of conventional power stations, which generate and supply energy constantly and without interruption. In the case of renewable energy sources – such as wind or PV – natural energy fluctuations occur: these energies therefore belong to the variable and dynamic renewable energy sources. The fluctuating nature of the electricity generation calls for the availability of reserve capacity or the shutting down of existing conventional power stations. Although this saves primary energy, the predictability and full load operation of these power stations is no longer assured; in the worst-case scenario, electricity generation may become more expensive.

Before PV accounts for more than a 5%, or even a 20% share, of the mains supply (phase 6), the dynamic character of renewable energies must be taken into consideration, and the LCOE calculation needs to be supplemented by a dynamic approach. An approach of this type is, for example, proposed in the variable renewable energy (VRE) method [3] or pursued in the PV parity approach [4]. These approaches are essentially concerned with analysing the integration costs of PV in existing grids and evaluating them from a cost perspective.

Enhancement of the LCOE method

The LCOE method is accordingly complemented by the dynamic integration expression:

The integration costs can be subdivided into different categories:

• Balance cost: short-term capacity adjustments have to take place in the grid because of the variability of the dynamic energy generation.

• Grid costs: the grid may need to be strengthened in order to distribute the variably occurring decentralized energies via different locations.

• Profile costs: used to compensate for the provision of organizable reserve capacities.

• Synergy costs: among other things, renewable energies afford savings in primary energy, reduced CO2 emissions, the production of reactive energy, and overall savings in the external costs of conventional energy sources. Local use of the decentralized energy reduces power losses because it eliminates the need to transport it over long distances.

On the other hand, the integration costs decline as the share of self-consumption increases (demand response

1

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𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿(𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃stat) = � 𝐼𝐼𝐼𝐼𝑡𝑡𝑡𝑡+𝑀𝑀𝑀𝑀𝑡𝑡𝑡𝑡+𝐹𝐹𝐹𝐹𝑡𝑡𝑡𝑡


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(3)

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(3)


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[4]): the decentralized generated energy is stored locally in batteries at the point of generation. This is an elegant way of reducing the above-described integration cost pools. In this case, however, investment in storage capacity will be needed.

As a number of studies show, the magnitude of the integration costs is in turn dependent on the integration level of PV: the integration costs rise in line with the integration level. In all the studies, the local circumstances – such as solar radiation or the sharing of the cost of the electricity by different user groups (e.g. industrial, residential, apartment blocks) – play a decisive role [5]. For example, the integration costs are higher in the north of Europe than in the south [4]. This is related to the fact that in the north, peak power consumption tends to occur on winter evenings and thus PV installations are unable to contribute a great deal. In the south, however, peak consumption occurs around midday in summer. Additionally, a PV system generates more power in sunny locations than it does in northern regions. This is the reason why wind turbines should generally be installed in the north and PV generally in the south.

A comparison of different energy technologies is therefore made on the basis of the enhanced LCOE concept (LCOE(PV)). The formula for the LCOE calculation is:

where I = investment, M = operations and maintenance (O&M) expenditure, F = fuel expenditure, E = electricity generation, t = year, r = discount rate, n = investment period in years, and IC(PV) = integration cost.

Influence of the cell and module design on the LCOE calculation

When comparing different PV technologies, it is sufficient to refer to the LCOE(PVstat), since the influence of different PV technologies on the integration costs is only marginal. What is essential, however, is that the integration costs increase by around one percentage point per percentage point of integration [3,4]. With a PV penetration of ~20%, the integration costs are ~20% of the LCOE(PVstat) costs. It is important to mention that it is not sufficient to achieve grid parity. The decisive key figure, at least for large installations, is the LCOE cost. An investigation into the sensitivity of the LCOE calculation to various module parameters is shown below.

LCOE(PVstat) is simply called LCOE in the following context. It can be seen that on the one hand, the investment It and the maintenance Mt are included in the calculation, and on the other, the system yields Et are included in the denominator. In the case of renewable energies, the Ft costs (fuel expenditure) are of course zero. All costs and investment requirements during the year – inverter replacement, for example – and yields are discounted, and the net present value (NPV) is determined. It is also apparent that the lifetime of an energy system plays a decisive role. Using the commonly accepted lifetime of 20–25 years for PV projects, significantly higher LCOE values are obtained than for a system which can produce energy for 30 or even 40 years.

The annual yield of the installation, that is to say the kWh produced, is dependent on a large number of parameters which can be divided into two classes:

1. Local parameters• Location of the installation (solar radiation, temperature,

wind, precipitation, shading, etc.).• Dirt on the modules.

2. System parametersHere a distinction is made between

• inverter-dependent parameters (such as inverter, voltage level, wiring concept) angle of incidence, rear ventilation, cable cross-sections, etc.; and

• module-dependent parameters.

The module-dependent parameters are individually listed below.

If the local parameters and the inverter-dependent parameters are frozen by specifying a power station’s location and inverter design, and different module types based on the module-dependent parameters are examined for this location, the yields of different PV technologies can be accurately compared and evaluated. The following module-dependent parameters were taken into consideration with regard to their effects on the yield and thus on the LCOE calculation:

• Module efficiency (Eta): this essentially determines the area-dependent BOS costs and thus the investment involved in the installation.

• Module costs (Cm): here it is vital to use the unit costs and not to make the common mistake of using the costs per Wp. Costs per Wp, whether installation costs per Wp or module costs per Wp, distort calculations that depend on the efficiency and lead to incorrect conclusions.

• Fixed BOS costs per area (not per Wp).

• Variable, capacity and area-dependent BOS costs.

1




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• Temperature coefficient (Tk) in %/K.

• Long-term degradation, expressed as annual degradation (Ad) in % of module power at STC.

• Potential-induced degradation (PID) and light-induced degradation (LID) for the first year in % of module power at STC.

• Lifetime (Lt) of the modules: this essentially determines the lifetime of the entire power station and thus the duration of the project.

• Bifacial module design (Bf ): bifacial modules result in a significant increase in the energy yield of an installation.

Energy yield can be increased by as much as 10–30% [6] compared with a monofacial module.

• Discount rate in %, which corresponds to the weighted average costs of capital (WACC) in the LCOE calculation.

• Annual maintenance costs in % of the total investment.

The yield Et for a specific location – measured in kWh – is a function of Eta, Tk, PID, LID, Ad, Bf and Lt. In the LCOE calculation, the project duration corresponds to the lifetime of the installation, which is essentially determined by the module lifetime. Unlike the liquidity-oriented discounted cash flow calculations, the LCOE calculation makes no allowance for an amortization term. The cash flow calculations and their

Region Example Annual irradiation [kWh/m2] Average cell temperature [°C]

1 Europe, part of USA 1200 40

2 Southern Europe, Asia, South America 2000 60

3 Arabia, Central Africa 2500 70

Standard mc-Si Standard mono Heterojunction

Module efficiency 15.6% 17.2% 19.2%

Temperature coefficient –0.46%/K –0.43%/K –0.2%/K

Cell cost per piece $1.67 $2.19 $2.19

Module manufacturing costs $45/m2 $45/m2 $45/m2

60-cell module price $172 $203 $203

Module lifetime in years 25 25 40

Area-related BOS costs $62/m2 $62/m2 $62/m2

Power-related BOS costs $260/kW $260/kW $260/kW

PID+LID 1st year 3% 3% 0%

Long-term degradation 0.35%/yr 0.35%/yr 0.1%

O&M costs per year 2% of CAPEX 2% of CAPEX 2% of CAPEX

PR (excluding temp. effect) 0.9 0.9 0.9

Discount rate (WACC) 4% 4% 4%

Additional assumptions for cash flow calculations

Interest rate 4% 4% 4%

Inflation rate 2% 2% 2%

Energy value (discounted to year 0) $0.15/kWh $0.15/kWh $0.15/kWh

Table 1. Reference assumptions for the three regions examined for the LCOE calculations.

Table 2. Reference assumptions for the LCOE calculations (price indications from PVinsights [7]). The mono case is used for the sensitivity analysis.


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sensitivities will be addressed next.The sensitivity of the LCOE calculation to the above

module-dependent parameters will be examined next, for which a reference base is needed. The assumptions detailed in Tables 1 and 2 will be adopted as the reference base, and the sensitivities for three different regions will be determined. Based on the reference assumptions in these tables, the influences of the module-dependent parameters on the LCOE can now be derived.

The module costs are separated into cell costs per unit and module manufacturing costs per unit. The BOS costs are broken down into a variable part and a fixed part; the variable part in turn is assumed to consist of an area-dependent portion and a capacity-dependent portion. For the sake of simplicity, the fixed BOS costs are transferred to the two variable cost portions. This breakdown provides a sufficiently accurate approach for comparing different PV technologies with one another.

The WACC of 4% chosen here lies in between the 2.8% chosen by ISE Fraunhofer [8], and the 4.5% chosen by Prognos institute [9]. For a 1MWp solar farm using monocrystalline modules with a module efficiency of 17.2%, the LCOE costs for this reference point for the regions 1, 2 and 3 are US¢12.1/

kWh, US¢8/kWh and US¢6.7/kWh respectively. The influences of the parameters Eta, Tk, PID, LID, Ad, Bf and Lc, as well as of the costs, on the LCOE can now be calculated simply by changing one parameter of the reference case.

A high efficiency drastically cuts the LCOE costsFig. 2 shows that the efficiency has a considerable influence on the LCOE costs. A 10% increase in efficiency from 17.2% reduces the LCOE costs by 7.5%. The efficiency variator is accordingly 77% for this case.

Reduction in cell priceLow cell prices also affect the LCOE calculation (Fig. 3). Even when the cell costs are assumed to be zero, the LCOE costs are limited by BOS and module manufacturing costs. If it were desired to reduce the LCOE costs by 50% in order to become competitive with other energy sources, it would therefore not be possible to achieve this goal solely by reducing the cell costs. This is because the fixed module costs – such as glass, backsheet, junction boxes and BOS – remain unchanged. Pursuing a cost-cutting strategy [10] with a view to becoming the cost leader is therefore neither sustainable nor expedient from the LCOE perspective.

Figure 2. LCOE sensitivity to module efficiency. The module efficiency has a significant influence on the LCOE calculation irrespective of the WACC.

Figure 3. Influence of the cell costs (wafer costs and cell manufacturing costs) on the LCOE calculation. Figure 5. Influence of the project duration on the LCOE calculation.

Figure 4. Influence of the temperature coefficient on the LCOE calculation.

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Temperature coefficientFig. 4 shows that simply reducing the temperature coefficient has a significant effect on the LCOE values. A reduction in the present-day temperature coefficient of –0.45%/K (PV today) to –0.2%/K (heterojunction technology – HJT) reduces the LCOE costs by 9.4% in region 2. In region 3, the LCOE values are reduced by as much as 10%. It therefore makes little sense to simply make solar cells cheaper: they need to become more efficient in terms of power and performance ratio. In other words, a low temperature coefficient also boosts the competitiveness of PV compared with traditional energy sources.

Project durationThe project duration, which is essentially limited by the module lifetime, has a decisive influence on the LCOE (Fig. 5). However, the curve levels off for longer periods, because on the one hand, yields are discounted by 4% on the NPV (see reference assumptions in Table 2), and on the other hand, a normal performance degradation of 0.35% per annum is assumed. Nevertheless, 50% more kWh will be generated over the course of a project duration of 40 years, compared with a project duration of 25 years. Lifetimes of 40 years can be achieved using glass–glass modules.

Performance degradation as a result of PID and LID effectsBecause PID and LID effects occur in the first year of operation and no subsequent performance degradation results from PID and LID effects, the influence of both effects on the LCOE is linear. A LID effect of 3% in the first year, for example, diminishes the LCOE values by 3%. If no LID effects occur, the LCOE values remain unchanged.

Annual degradationDifferent degradation effects occur, depending on the module design and type of connection technology, as well as on the type of encapsulation. Annual degradation values between 0.2 and 0.5% per year for LCOE calculations have been reported in the literature; a value somewhere in between, of 0.35% per year, has been chosen for the calculations here. It is clear, however, that this value is determined by the design of the modules in combination with the materials and cells that are used. By choosing cells without micro-cracks and replacing the backsheet with glass, the annual degradation can be reduced substantially.

Bifacial vs. monofacialBifacial modules provide more energy because these types of cell are able to convert sunlight into electrical energy on both the front and the back sides; this effect is greater with glass–glass modules than with glass–Tedlar modules. The effect of bifacial construction on glass–glass modules has been measured in the Swiss Alps [6]: on average this effect accounts for a 15% higher yield per year per installed watt,

but with a white or snow-covered background, the additional yield was as much as 30%. Bifacial construction is almost completely incorporated in the LCOE calculation: the variator in respect of bifacial construction is 86% and this parameter exhibits the greatest influence on LCOE of all module-dependent parameters. An additional yield of 15% thanks to bifacial construction results in an LCOE reduction of 13%.

Cost savings due to thin wafer materialWhen investigating wafer thickness, kerf loss needs to be taken into account as well. Kerf loss can be further reduced with diamond wire (DW), as shown in Table 3. For physical reasons, there is no scope for any further significant reduction in current kerf loss (typically 147µm) with slurry processes. With DW, kerf loss can be reduced to 100µm, with a simultaneous decrease in wafer thickness to 120µm.

Cell and module technologies in which performance is not limited by thinner wafers have a cost savings potential of $0.32 per cell.

Goal of PV technology developmentBased on the above elaborations, it will now be possible to determine precisely which cell and module concepts are sustainable and must be implemented in order to reduce the LCOE values. It has been demonstrated, however, that individual measures are insufficient on their own: rather, it will be necessary to implement the entire package of measures, encompassing cell efficiency, module costs, temperature coefficient, PID- and LID-free modules, lifetime, wafer thickness and bifaciality, while avoiding additional costs and additional production steps as much as possible. Intelligent cell and module concepts of this type will ensure the competitiveness of PV in the context of the global energy mix.

What is the optimum PV technology with regard to the LCOE?

The requirements are clear. The above parameters are to be changed in order to achieve the lowest LCOE values without

Technology Wafer Kerf Pitch Module savings Cell costs [µm] [µm] [µm] [US$/pcs] [US$/pcs]

Slurry 180 147 327 0.0 2.19

DW 180 150 330 4.4 2.12

DW 160 140 300 8.4 2.05

DW 140 125 265 13.2 1.98

DW 120 100 220 19.2 1.87

Table 3. Module cost savings as a result of reducing wafer thickness and kerf, allowing for pulling costs. (Cell costs according to PVinsights [7].)


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introducing additional process steps or incurring additional costs. Heterojunction technology (HJT) with SmartWire Connection Technology (SWCT) is one solution. These modules are LID- and PID-free without causing additional costs in the cell process; moreover, bifacial construction is already available free of charge as a physical by-product with HJT cells. The only requirement is to swap process steps: no additional process steps need to be introduced. The band gap potential results in best-cell efficiencies of over 24%. The temperature coefficient is only –0.2%/K in the module, which is lower than for thin-film modules. Thin wafers can be employed with HJT for four reasons. First, HJT exhibits no loss of efficiency when using thin wafers. Second, at no point in the process chain is a maximum process temperature of 250°C exceeded, resulting in low energy-related process costs. Third, undesirable wafer bowing is reduced because of the lower process temperatures. Fourth, cells produced in this way have few micro-cracks – a prerequisite for a long lifetime.

With SWCT the silver requirement is reduced by 80%, and the module lifetime (and in turn the project duration) is increased. SWCT results in an increase in module efficiency of ~3% in comparison to, for example, three-busbar cells.

In conclusion, HJT in combination with SWCT is virtually predestined to bring about a permanent reduction in LCOE values. This intelligent cell and module concept is the answer to the forthcoming competitive challenges related to the global energy mix and is unrivalled in its positive impact in terms of reducing LCOE values.

Fig. 6 depicts the transition from a monofacial module to a HJT module according to the assumed reference by itemizing the

criteria described above which have a considerable influence on the reduction of LCOE costs. The chart refers to region 2.

It is clear that HJT offers considerable inherent potential for LCOE cost reduction. It can also be seen that only the complete package of measures results in LCOE values that are competitive in the context of the energy mix specific to the region. Improvements with regard to the criteria of efficiency, temperature coefficient, bifacial construction and lifetime lead to these significant savings. It is important to stress that these improvements involve neither higher module costs nor additional process steps, which is without doubt the strength of HJT.

There is obviously scope for refinement of HJT, with the prospect of achieving further reductions in LCOE values: future optimizations and savings will result in a possible additional 25% reduction in LCOE values. This will be achieved through savings all along the value chain and also as the result of future economies of scale [11]. An LCOE value of just above US¢4/kWh will then be within reach in region 2. The LCOE values for region 3, with a solar radiation of 2500kWh/m2, could fall to US¢3.6/kWh in the medium term.

Combination of HJT, diamond wire and SWCT

Meyer Burger Technology has systematically advanced its technology with the goal of guaranteeing the lowest LCOE values. Both the cell concept and the module concept are oriented to the essential criteria described above that lead to a sustainable reduction in LCOE values. This may be the only way to make PV competitive with other energy sources and

8 7.97 0.670.63 0.2

0.16 0.995.32 0.69

0.320.21 0.04 4.06

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mc (15.6%)

mono (17.2%)

19.2%

TC= ‐0.2%

no PID/LID

degradation = 0.1%/yr

25 ‐ 40 y

HJT today

bifacial (+15%) 21

%

slurry (180um) ‐ DW (120um)

AG savings

HJT optimum

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Figure 6. The properties of heterojunction technology and the effects on the LCOE for the climatic conditions in region 2. The individual LCOE-sensitive measures shown for the reduction of LCOE values are based on the assumed reference of a monofacial monocrystalline module. (The efficiencies shown are module efficiencies.)



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become part of the energy mix. In particular:1. HJT can be industrially applied on a large scale and with

significant cost-effectiveness for the first time using new PECVD (plasma-enhanced chemical vapour deposition) and PVD (physical vapour deposition) tools.

2. HJT has already demonstrated 24.7% efficiency with large wafer formats.

3. HJT cells have a symmetrical structure and are bifacial without the need for additional process steps.

4. The cells do not lose efficiency when the wafer thickness (as-cut thickness) is reduced. A reduction from today’s 180–200µm to 145µm (or even to ~100–120µm) does not affect the cell efficiency. Meyer Burger Technology has developed highly cost-effective and environmentally-friendly water-based diamond-wire slicing (DW wafering) for minimum kerf loss and maximum productivity, even for thin wafers.

5. Thin cells lend themselves extremely well to formation into modules with the new SWCT. A high light utilization also increases the module output, and the modules can be adapted to local light conditions (Central Europe = fewer wires, Sun Belt = more wires). SWCT technology increases the module lifetime and boosts the yield, because it tolerates micro-cracks without power loss. Eliminating the need for busbars and reducing the finger width results in immediate reduction in silver use by as much as 80% compared with a normal cell. HJT cells have already been successfully produced in the Meyer Burger Technology laboratory using 20mg of silver paste.

6. HJT cells achieve high levels of efficiency with n-type silicon and are not subject to LID or PID degradation. A summary of n-type solar cell concepts is provided in Kopecek & Libal [12]. The advantages of n-type wafers in the manufacture of solar cells are well known: this is evidenced by the ITRPV industry forecast [13] that the 5% share of n-type wafers will double by 2015, and quadruple to more than 20% by 2017. In the same study, the efficiency potential of n-type cells is rated the highest by a wide margin. With regard to the price situation, it should be noted that there is no reason why n-type should be more expensive than p-type material. Moreover, the entire cylindrical part of an ingot can be utilized, and the material yield is usable for cell production without waste, except for ~5cm at the top and tail.

7. HJT cells have a remarkably low temperature coefficient of less than 50% of that of current modules. Even the best thin-film technologies barely reach this value, and HJT still has the potential to improve it even more in the future. The energy yield, in terms of Wp and m2, is higher with HJT than with other technologies.

8. With SWCT, a very fine grid is drawn over the fingers. Although low temperature pastes have a lower conductance than high temperature pastes, this does not play an important role, especially since the silver content can be reduced by 80%. In addition, with HJT cells the TCO (transparent conductive oxide) layer is conductive and forms direct connections to the SWCT wire mesh. HJT/SWCT modules have already been examined in the laboratory by eightfold IEC 61215 testing (damp heat) and fourfold thermal cycle testing, without any significant drop in performance or delamination. These tests provide evidence of extended durability, and the assumption of a 40-year lifetime appears realistic.

A cross section of a HJT cell is shown in Fig. 7.

Considerations involving the cash flow calculation

A liquidity-oriented evaluation of PV installations can be carried out using the cash flow method. In this calculation, future monetary earnings are discounted back to the present time. In the first few years, the earnings are used to repay debt – this term is known as the payback period.

In the cash flow calculation, the earnings are discounted back to a predefined energy price. This is in contrast to the LCOE calculation, in which the kWh are discounted back over a predetermined project duration, irrespective of a payback period. Both calculations discount back to the NPV.

Different investment strategiesAn interesting consideration within the cash flow calculation is to take into account the investment strategy. Here, a

Figure 7. Cross section of a HJT cell.


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distinction is made between three different cases, with a comparison of their respective impacts on standard technology and HJT technology (Fig. 8).

Case 1: Utility or large installation operator These PV installations are technically restricted through the absolute maximum output, dictated by the grid connection. The investor will therefore compare systems of the same kWp size. The cash flow curves show the standard (STD) PV installation in red and a HJT PV installation in blue (see Table 2 for the conditions). The capital expenditure for the HJT installation is lower than that for the STD installation, on account of the fact that HJT systems incur fewer BOS costs. The ‘minor’ difference means that the payback period for HJT is cut almost in half. After 25 and 40 years, the surplus revenues of the PV installations of US$1226 and US$1744 respectively can be seen for region 3.

Case 2: The investment budget is fixedInvestors wish to lay out a specific amount of capital and are looking for an installation with maximum return and minimum risk. The HJT system is now enlarged compared with case 1, making the capital expenditure for both installations identical. The more powerful system – here the HJT system – generates more electrical energy on account

of the size and the lower degradation or higher revenues because of the better temperature coefficient. The cash flow curve shows higher revenues as well as a shorter payback time, thus minimizing risk.

Case 3: Identical amounts of annual energy Home owners either have a specific roof area available or would like to generate their annual energy consumption themselves. The second case is addressed in the cash flow curve of case 3. Both types of PV installation feed in the same predetermined amount of energy in the first year. Because of the different degradations of the installations, the HJT installation will feed in this value virtually unchanged and the STD installation will exhibit a slightly higher degradation. The home owner’s investment strategy can therefore be achieved with a lower investment for the same benefits. This calculation can be further optimized with self-consumption if the consumer electricity price is higher than the FiT.

In all nine cases illustrated in Fig. 8, the same STD installation is used as a point of reference and the HJT installation adapted to the investment strategy. Both FiTs and lease contracts generally have a predetermined duration: with PV installations a figure of 20 to 25 years is used for this reason. In the early years of PV, a great deal was learned about

Figure 8. Cash flow calculations for three cases and regions. 1kWp STD system (red), HJT system (blue). ROC = Return on Capital Employed.



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the importance of good materials and the right interplay. Subject to the absence of external factors, a PV system with good modules is perfectly capable of achieving a lifetime of 40 years. The cash flow consideration allows the total return to be ascertained for any desired operating time. It becomes clear that investments in PV installations are medium term because the payback time has to be reached.

Different regionsThe cash flow curves have been calculated for the three example regions (graphs displayed vertically in Fig. 8). Although PV efficiency with standard technology declines significantly at high temperatures, virtually no disadvantages are encountered with the new heterojunction technology, especially in very sunny, typically very warm regions; the economic advantage over standard technology is therefore considerable.

Fig. 8 also highlights the difference between the LCOE and cash flow considerations: the further the earnings lie in the future, the more strongly the LCOE discounts all effects. Effects such as increased lifetime or reduced degradation are more lightly weighted in the LCOE consideration than in the cash flow calculation. The curves in the cash flow calculation are substantially flattened by the rate of inflation.

The economic advantages of new HJT-based installations over good current PV technologies are easy to see: the real return on investment after 25 years is 230% for HJT installations and 141% for STD installations.

If the cash flow consideration is extended to other energy generation systems, such as coal or gas-fired power stations, it will be necessary to factor in the future fuel cost trend. With PV investments, the entire investment is made at the beginning and virtually no further running costs are incurred. The result of this in the cash flow consideration is that after a certain period of time, PV can achieve higher cash flow returns than, for example, gas-fired combined cycle power plants (see Fig. 10). Depending on the assumption made for fuel price inflation (here 7% per annum), HJT-based PV installations are even more cost-effective than gas-fired combined cycle power plants after 33 years.

This is where the difference between the LCOE and cash flow calculations is apparent. In the LCOE calculation, a gas-fired combined cycle power plant appears to be cheaper than a PV installation. In the cash flow consideration (Fig. 10) it can be seen that the PV installation is more cost-effective than a gas-fired combined cycle power plant. This is chiefly dependent on the lifetime and fuel costs.

Findings from the PV learning curve

The ‘standard’ cells on mc or cz wafers have the largest market share and are the most technically mature. However, these technologies are almost at the limit of their efficiency, and they offer few criteria for long-term reductions in LCOE costs,

with the result that the only opportunities for improvement lie in production cost reduction.

To achieve higher efficiencies, various upgrades have been introduced, but some – such as selective emitters or MWT (metallization wrap-through) – have almost reached the end of their product life cycles. The use of selective emitters lasted approximately four years and became obsolete when appropriate pastes were made available. MWT technology lost its advantage of a reduction in silver usage on the front when smart wire technology was introduced. Another upgrade – the co-diffusion cell – is costly to produce and expensive in use, with limited cell efficiency, and it offers less potential in terms of temperature coefficient. The remaining upgrade for existing systems is the conversion to PERC (passivated emitter and rear cell), which will allow existing systems to continue operating for a number of years. This

Figure 9. Case 2, region 2, showing the cash flow earnings after 25 and 40 years. If the lifetime is limited to 25 years for STD installations and 40 years for HJT installations, the difference in earnings is greater by a factor of 3.2. The LCOE, however, only yields an advantage of 15% (see Fig. 6).

Figure 10. Cash flow calculation comparing HJT and gas-fired combined cycle power technology for region three. The cash flow calculation shows that new PV technologies are highly competitive.


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is associated with a strategy that is based purely on cost, because in the mainstream area it is crucial to remain the cost leader. For this reason, new investments are being directed at new technologies which meet the requirements outlined by the LCOE calculation. Cell concepts of this type are based on HJT cell technology: one such example is heterojunction with intrinsic thin layer (HIT), developed by Sanyo. HJT modules began line production in 1997 and have since repeatedly broken the world efficiency record for modules. The economy of scale potential for HJT is not yet exhausted, because it is at the beginning of its product life cycle. Upscaling from 500MWp to 2GWp, for example, would bring cost benefits of 20% [11], and HJT can also benefit from this potential. The upper level, however, has not been included in the present consideration of LCOE. According to the learning curve, the hundreds of GW of production have to be produced at the same price level as today, which does not allow a reasonable profit margin with today’s mature technology. In contrast, today’s manufacturing costs for HJT modules are lower than market module prices, and profits are realistic.

Innovation cycles

Fig. 12 depicts the innovation cycles. The dashed black line represents the innovation curve for standard cell technology, which today has almost exhausted its potential. The grey curve represents the next technology, HJT. Point marks the business decision point for switching to the new

technology, because at this point, the costs and performance of both technologies are identical. By investing resources – indicated by – the new technology can attain a much higher potential, represented by . The future potential of the new technology is indicated by .

From the business perspective, switching to the new wave of technology makes good sense. First, the LCOE calculations carried out lead to this decision; second, the cash flow calculations also indicate that the new technologies have advantages; and third, it can be deduced from the learning curve that following the mainstream leads to a strategy that is based purely on cost, which leaves little scope for innovation.

Conclusion

LCOE calculations are a useful tool for comparing different energy generation systems. To calculate the true costs of PV electricity, factors such as profile and balance costs have to be added to the ‘bare’ LCOE cost to cover the fluctuation of PV generation. Module properties have a major impact on the LCOE costs. A sensitivity analysis reveals that module lifetime, efficiency, temperature coefficient and bifaciality have the biggest impact on LCOE. The authors are convinced that the best combination of these properties can be achieved using HJT technology together with SmartWire Connection Technology. Compared with other advanced cell concepts, this strategy can be realized at the same wafer and cell manufacturing costs as current

Figure 11. 80% PV learning curve. Doubling the cumulative production quantities reduces the manufacturing costs by 20% [14]. The current price level is well below the learning curve.

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standard PV technology. In combination with water-based diamond-wire sawing of thin wafers, the costs can be decreased much further, and HJT cells maintain the same high efficiency at reduced wafer thicknesses. For a sunny location, the LCOE can be reduced from 8US¢/kWh using current technology to US¢5.3/kWh; if bifaciality and future cost savings processes are implemented, this can be reduced even further to US¢4/kWh.

HJT technology combined with SWCT offers the best potential for reducing LCOE costs without additional production steps or increased manufacturing costs. Additional cost reduction potential is still available, because economies of scale have not yet been reached.

References

[1] Masson, G. et al. 2013, “Global market outlook for photovoltaics 2013–2017”, European Photovoltaic Industry Association (EPIA), European Commission (May) [http://www.epia.org/news/publications/global-market-outlook-for-photovoltaics-2013-2017/].

[2] Ossenbrink, H et al. 2013, “Photovoltaic electricity cost map”, JRC Scientific and Policy Report 83366, European Union.

[3] Ueckerdt, F. et al 2013, “System LCOE: What are the costs of variable renewables?”, Energy, Vol. 63, pp. 61–75.

[4] Pudjianto, D. et al. 2013, “Grid integration cost of photovoltaic power generation – Direct costs analysis related to grid impact of photovoltaics”, PVParity Report

(September).[5] Spertino, F. et al. 2013, “New concept for PV parity in

typical case studies: Hidden cost included”, Proc. 28th EU PVSEC, Paris, France.

[6] Nordmann, T., Vontobel, T. & Lingel, R. 2013, “Exploiting high solar irradiation in Alpine regions using bifacial PV modules”, Proc. 28th EU PVSEC, Paris, France, pp. 4797–4799.

[7] PVinsights 2014 (January 14th), PV prices and reports [http://pvinsights.com].

[8] Kost, C. et al. 2013, “Levelized cost of electricity renewable energy technologies”, Fraunhofer ISE Study (November).

[9] Peter, F. et al. 2013, “Entwicklung von Stromproduktionskosten”, Prognos Study for BELECTRIC [www.prognos.com].

[10] Porter, M.E. 1980, Competitive Strategy: Techniques for Analyzing Industries and Competitors. New York: Free Press.

[11] Goodrich, A.C. et al. 2013, “Assessing the drivers of regional trends in solar photovoltaic manufacturing”, Energy & Env. Sci., DOI: 10.1039/c3ee40701b.

[12] Kopecek, R. & Libal, J. 2013, “The status and future of industrial n-type silicon solar cells”, Photovoltaics International, 21st edn, pp. 52–59.

[13] SEMI PV Group Europe 2013, “International technology roadmap for photovoltaic (ITRVP): Results 2012”, 4th edn (March) [available online at http://www.itrpv.net/Reports/Downloads/].

[14] BSW-Solar and PSE AG 2013, Data.

Figure 12. Innovation cycles.


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