Webinar Q&A: Calculating large-scale PV costs


Over the past 18 months, power purchase agreements (PPAs) being signed for vast solar power projects in many parts of the world have been hitting record lows. In India in 2017, the sector witnessed a PPA of just US$37/MWh for the 500 MW Bhadla Solar Park in the state of Rajasthan.

This record-low price for India was surpassed in other maturing solar markets, namely the UAE, Saudi Arabia and Chile, which saw PPAs of $24.2/MWh, $23.6/MWh and $21.48/MWh, respectively.

The winning developers on each of these large-scale, record-low cost solar projects were established project developers and EPCs, including the likes of Saudi state-backed ACWA, Italian utility, Enel, and a leviathan joint venture (JV) between Chinese tier-1 vertically integrated solar manufacturer, JinkoSolar and Japanese conglomerate, Marubeni.

The correlation between bankable player and record-low bid is certainly noteworthy, but does not alone account for this new low-cost landscape. The reasons for such prices are multivariate, and it was these reasons that were explored in the recent pv magazine webinar by Vikas Bansal, head of business development international markets at Indian EPC Sterling and Wilson, and Rainer Gegenwart, the CTO of Dubai-based project developer, Phanes Group.

Both participants explained in detail during the webinar the how and why it is possible for certain prices and projections to be made for certain regions, taking into account a range of factors including cost of capital, political stability – or lack thereof – existing infrastructure, technology selected, and market maturation.

Such a broad and relevant topic elicited a great response from the audience, who weighed in with a great many insightful questions. Here is a selection of the most interesting ones, complete with answers from the webinar experts.

What impact does political instability have on costs and revenues in solar markets in Africa and Asia?
Rainer Gegenwart (RG): The most obvious impacts are higher PRI (Political Risk Insurance) and higher interest rates (higher swap/margin).  As a result of these rates, the entire project cost goes up.
Vikas Bansal (VB): In countries that are politically unstable, investors can be shy in putting their money into the market. This means that insurances and security costs rise, yes. There will also be additional costs built into the project by every stakeholder as contingency against probable and/or perceived future risks. The gestation period can also be longer, and hence more costly, if project are finally commissioned from stage of concept.

Could you give examples of insurance costs in different regions please?
VB: Insurance costs vary from region to region. There are many insurances that are specifically designed for certain regions to cover things like kidnapping, theft, political upheaval – essentially threats that are not universally applicable but may be heightened in some regions. There are also countries that mandate the purchase of locally secured insurances, while others are more open on this requirement. It means that the quantum of insurance costs cannot be generalized.

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Given such low rates seen across industry, is the business still profitable from your perspective? Can EPCs still survive on these prices?
RG: It is certainly more difficult for pure EPCs due to such tight margins and risk. A number of cost-efficient EPCs will survive.
VB: The definition of profit varies company to company. EPCs are used to working on very thin margins. It will be difficult, however, even for good EPCs to survive for longer periods if the solar industry continues to deliver such a brutal competitive business environment. This may also lead to a negative impact on the health of PV projects.

If such recent bids have been substantially below cost in recent cases, what do developers hope to achieve by building such plants?
RG: These developers bid on falling costs and the lowest available financing. Some may lose out of course, and a number of projects will not be built, as has been witnessed in Brazil, for example.
VB: The motives behind such low tariffs vary from bidder to bidder. Some developers, investors and IPPs are just in race to build out their experience and portfolios, given that they are relatively new to the technology. While others are under pressure to utilize their available funds and earn some larger returns and profits.

In time, after market consolidation has progressed significantly, do you think tariffs will begin to increase?
RG: No, we see further decreases in African countries, where Phanes Group is active.
VB: Not so soon, no. It may take between six months to one year for tariffs to stabilize and maybe then increase.

Given that long-term schedules translate into ‘gambles' from bidders, and that many of the tender results are not transparent in terms of what they include in the strike price and what they do not, we see LCOEs in the $50/MWh range today – in many countries. So what are the actual capex costs today?
RG: We cannot disclose CAPEX costs because they vary a lot from country to country. There is no single number that is valid for all regions. Besides material cost and labor we have different import duties and risk cost son top of the pure material and installation cost. I believe that system prices will continue to decline, but for 2018 we do not see a large decrease as was forecast in research studies. The long-term downward trend, however, will continue.
VB: All solar projects should be seen from a perspective of the overall lifetime cost in order to accurately know its viability, which means not only CAPEX but also OPEX. As Rainer said, these costs vary from region to region and country to country. We also note that the price of steel, copper and aluminum has already increased, although we expect module prices to remain the same in 2018.

For how long can module costs decline by around 5-7% per annum, as has been seen recently?
RG: The 20+ years average decline in costs of 6-7 % will remain for some time. It is vital to keep in mind that the absolute numbers for reductions are getting smaller and smaller, and the majority of short-term predictions in the past have been wrong.

What would be the impact on PV generation when using bifacial modules compared to standard modules? And what is the stability of this technology?
RG: This once again depends on the region and the installation. There is no general answer for this. The Albedo of the ground, the distance, and the climate are important. As a rule of thumb one can expect a 5% to < 15 % increase in a proper installation on the appropriate ground. The stability will be as good or bad as PERC and/or HJT modules are.
VB: There will surely be an increase when using bifacial modules (maximum up to 6-8%) as per our in-house preliminary simulations. But presently there is a challenge on two fronts: one is the availability of such modules for large-scale utility projects,  and secondly bifacial technology has no proven track record in the field, if requested by a potential investor.

A second webinar powered by Sterling and Wilson on the topic of solar+storage at scale is planned for May. Watch this space for more information.

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