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Revolutions at sea – reflecting on the cost of offshore wind

The costs of offshore wind are falling dramatically. Several European countries have now agreed to buy power from offshore wind farms at costs which challenge the notion that renewable energy must be heavily subsidised to survive.

The UK government has recently awarded contracts to offshore wind projects scheduled for the early 2020s, at prices 50-60% lower than those it handed to offshore wind projects in 2014.  Germany and the Netherlands have recently announced contracts, also for expected delivery in the early 2020s, in which offshore wind developers have agreed to receive the market price only – zero subsidy contracts.

What has caused these rapid cost reductions? Can we expect the costs of offshore wind contracts to remain at these relatively low levels, or even to reduce further?

The cost reductions are likely to have had a few contributing factors, several of which can be seen optimistically as factors that will continue to keep costs low in the future.

One such factor is an innovation relating to policy design. The payment level received by offshore wind projects is now increasingly decided not by governments, but by requesting companies to bid in for the contract, declaring the price at which they would be prepared to deliver it. Such auction-based systems allow governments to choose the lowest cost of the now revealed bids. It seems plausible that the move towards auction-based allocation systems may have helped to drive down prices by introducing price competition into the bidding process.

Technological improvement is an important factor for enabling such cost reductions. There has been a clear trend towards larger and more efficient turbines which can deliver greater amounts of energy, increasing return on investment, thereby lowering costs. The trend is set to continue, with one major company expecting the turbines they will use in 2024 to be double the current size.

However, other factors that could explain the recent low bids may give a less clear grounds for optimism that the low prices are here to stay.

It is possible that companies may currently be bidding low for strategic reasons. For some companies, a lower return may be considered worthwhile, at the present time, for the benefit of maintaining their project supply chains. If subsidies in some previous rounds were overly generous, as some have suggested, it might be that this is currently enabling some flexibility on the balance sheet for low bids. If this is part of the explanation, such strategic bidding could not be maintained in the long run.

Auction design can also incentivise companies to put in bids lower than they would ideally accept, if they believe that another project will bid in higher and set the price received by all selected bids. However, if such a strategy backfires then a company could win a contract but at a price at which it is impossible to deliver the project – sometimes called “the winner’s curse”.

Another important factor likely to be lowering costs at the present time is the relatively low cost of financing. Investors have increased familiarity with offshore wind, and the long term contracts being issued by governments help to manage uncertainty, enabling lenders to lend at lower rates of interest. However, there are also important external conditions – interest rates in general are exceptionally low at the moment. As interest rates are likely to rise again in the future, it is possible that this could add to the cost of future projects.

Costs of projects are also strongly affected by site conditions, such as distance from shore and depth of water. There is a limited number of sites close to shore and in shallow water, and if future sites are in deeper water and further from shore this could drive up costs.

It is also important to recall that not all costs associated with offshore wind farms are necessarily accounted for in the costs paid for by project developers, and thus covered by the subsidies. Important additional costs are the costs of connections to power grids, and of balancing the system, for example in the event of too much power being injected on to the grid at the wrong time and wrong place. Because wind turbines have variable output dependent on wind conditions, they can exert significant costs on the system in this way. In some countries generators must pay for, or at least make a contribution towards these kinds of costs. In other countries, generators are not required to cover their own balancing and transmission costs, as these are met by the network operator. This is an important contributing factor towards the difference in costs between offshore wind projects in different European countries. Clearly, systems that do not target transmission and balancing costs at generators to some extent create favourable conditions for offshore wind, and they certainly make achieving zero-subsidy auctions more likely. However, if not paid by generators, transmission and balancing costs still have to be covered by system operators and are ultimately paid for by consumers. Thus, there is a strong argument that to herald a ‘zero-subsidy’ auction within a system that does not direct transmission and balancing costs at generators is misleading – especially if offshore wind exerts greater than average transmission and balancing costs – as the socialisation of transmission and balancing costs is a clear subsidy. Giving generators some kind of signal as to the costs their output imposes on the network is an important part of developing a well-balanced and efficient system. While shielding offshore wind generators from these costs may have attractions in the short term, it could lead to greater costs in the longer term, if it means the system develops in a way that is harder and more expensive to balance.

Of course, the news of extremely low prices for offshore wind contracts is to be welcomed. However, rather than becoming too focussed on zero-subsidy auctions as ends in themselves, we should continue to pay attention to making policies that look robust across all market conditions: long-term policy stability; careful attention to auction design; allocating transmission and balancing costs to support rational network development and incentivise innovations in storage and flexibility; and supporting and coordinating innovation chains.

Is the IEA still underestimating the potential of photovoltaics?

Photovoltaics (PV) has become the cheapest source of electricity in many countries. Is it likely that the impressive growth observed over the last decade – every two years, capacity roughly doubled – will be sustained, and is there a limit to the growth of PV? In a recently published article (Creutzig et al 2017), we tackle this question by first scrutinizing why past scenarios have consistently underestimated real-world PV deployment, analyzing future challenges to PV growth, and developing improved scenarios. We find that if stringent global climate policy is enacted and potential barriers to deployment are addressed, PV could cost-competitively supply 30-50% of global electricity by 2050.

A history of underestimation

Any energy researcher knows that projecting energy use and technology deployment is notoriously challenging, and the results are never right. Still, the consistent underestimation of PV deployment across the different publications by various research groups and NGOs is striking. As an example, real-world PV capacity in 2015 was a factor 10 higher than projected by the IEA just 9 years before (IEA, 2006).

A main reason for this underestimation is strong technological learning in combination with support policies. PV showed a remarkable learning curve over the last twenty years: On average, each

doubling of cumulative PV capacity lead to a system price decrease of roughly 20%. With substantial support policies such as feed-in-tariffs in many countries including Germany, Spain and China, or tax credits in the USA, the learning curve was realized much faster than expected, which in turn triggered larger deployments. These factors together have led to an average annual global PV growth rate of 48% between 2006 and 2016.

Can continued fast growth of PV be taken as a given? We think not. Two potential barriers could hinder continued growth along the lines seen over the last decade, if they are not addressed properly: integration challenges, and the cost of financing.

Integration challenge: Many options exist

Output from PV plants is variable, and thus different from the dispatchable output from gas or coal power plants. However, power systems have always had to deal with variability, as electricity demand is highly variable. Thus, a certain amount of additional variability can be added to a power system without requiring huge changes, as examples like Denmark, Ireland, Spain, Lithuania or New Zealand show: In these countries wind and solar power generates more than 20% of total electricity, while maintaining a high quality of power supply (IEA, 2017).

Under certain conditions wind and solar can even increase system stability. In fact, the size of the integration challenge largely depends on how well the generation pattern from renewable plants matches the load curve. Accordingly, in regions with high use of air conditioning such as Spain or the Middle East, adding PV can benefit the grid: On sunny summer afternoons when electricity demand from air conditioning is high, electricity generation from PV is also high.

As the share of solar and wind increases beyond 20-30%, the challenges increase. Still, there are many options for addressing these challenges, including institutional options like grid code reforms or changes to power market designs in order to remove barriers that limit the provision of flexibility, as well as technical options like transmission grid expansion or deployment of short-term  storage (IEA, 2014a). None of these options is a silver bullet, and each has a different relevance in different countries, but together they can enable high generation shares from photovoltaics and wind of 50% and beyond.

Financing costs: international cooperation needed

Many developing countries have a very good solar resource and would benefit strongly from using PV to produce the electricity needed for development. However, because of (perceived) political and exchange rate risks as well as uncertain financial and regulatory conditions, financing costs in most developing countries are above 10% p.a., sometimes even substantially higher.

Why does this high financing cost matter for PV deployment? One of the main differences between a PV plant and a gas power plant is the ratio of up-front investment costs to costs incurred during the lifetime, such as fuel costs or operation and maintenance costs. For a gas power plant, the up-front investment makes up less than 15% of the total (undiscounted) cost, while for a PV plant, it represents more than 70%. Thus, high financing costs are a much stronger barrier for PV – the IEA calculated that even at only 9% interest rate, half of the money for PV electricity is going into interest payments (IEA, 2014b)!

Clearly, reducing the financing costs is a major lever to enable PV growth in developing countries. Financial guarantees from international organizations such as the Green Climate Fund, the World Bank or the Asian Infrastructure Investment bank could unlock huge amounts of private capital at substantially lower interest rates.

Such action could help to leapfrog the coal-intensive development path seen, e.g., in the EU, US, China or India. Replacing coal with PV would alleviate air pollution, which is a major concern in many countries today – in India alone, outdoor air pollution causes more than 600,000 premature deaths per year (IEA, 2016a).

Substantial future PV growth possible if policies are set right

How will future PV deployment unfold if measures to overcome the potential barriers integration and financing are implemented? To answer this question, we use the energy-economy-climate model REMIND and feed it with up-to-date information on technology costs, integration challenges and technology policies. The scenarios show that under a stringent climate policy in line with the 2°C target, PV will become the main pillar of electricity generation in many countries.

energy-economy-climate model REMIND

We find a complete transformation of the power system: Depending on how long the technological learning curve observed over the past decades will continue in the future, the cost-competitive share of PV in 2050 global electricity production would be 30-50%! Our scenarios show that the IEA is still underestimating PV. The capacity we calculate for 2040 is a factor of 3-6 higher than the most optimistic scenario in the 2016 World Energy Outlook (IEA, 2016b).

We conclude that realizing such growth would require policy makers and business to overcome organizational and financial challenges, but would offer the most-affordable clean energy solution for many. As long as important actors underestimate the potential contribution of photovoltaics to climate change mitigation, investments will be misdirected and business opportunities missed. To achieve a stable power system with 20-30% solar electricity in 15 years, the right actions need to be initiated now.

References:

Creutzig, F., Agoston, P., Goldschmidt, J.C., Luderer, G., Nemet, G., Pietzcker, R.C., 2017. The underestimated potential of solar energy to mitigate climate change. Nature Energy 2, nenergy2017140. doi:10.1038/nenergy.2017.140. https://www.nature.com/articles/nenergy2017140

IEA, 2017. Getting  Wind  and  Sun  onto the Grid. OECD, Paris, France.

IEA, 2016a. World Energy Outlook Special Report 2016: Energy and Air Pollution. OECD, Paris, France.

IEA, 2016b. WEO – World Energy Outlook 2016. OECD/IEA, Paris, France.

IEA, 2014a. The Power of Transformation: Wind, Sun and the Economics of Flexible Power Systems. OECD, Paris, France.

IEA, 2014b. Technology Roadmap: Solar photovoltaic energy. OECD/IEA.

IEA, 2006. World Energy Outlook 2006. IEA/OECD, Paris, France.

Author

By Dr. Robert Pietzcker,  Post-doctoral researcher, Potsdam Institute for Climate Impact Research (PIK)