Germany

Germany

Viewpoint: 'No-cost' offshore wind -- how did Germany do it?

The most remarkable thing about three of the four winning bids in the recent German offshore-wind auction is that the successful bidders have rejected the safety net of a minimum reference price.

This provides a top-up when electricity prices are lower than a reference price, in a similar way to a contract for difference (CfD). Systems of this type remove most of the uncertainty around future revenues.

By contracting to deliver energy without a minimum reference price, the developers must be expecting to make a better return based on the (uncertain) future electricity prices in 2025-2055 than from a fixed bet on the Capex of offshore wind in 2025 and the Opex in the 30 years after that.

The developers are, in effect, basing their bids on forecasts of the difference between the levelised cost of energy (LCOE) from offshore wind and Germany's wholesale electricity price in ten years' time and beyond.

Major electricity generators already have significant expertise in forecasting future energy markets and prices. These teams look to have had just as big an impact on their company's offshore-wind strategy as those looking at technology development and LCOE.

We have calculated the LCOE of the wind farms coming into operation in 2025 at all the sites, taking into account our expectations of technology and costs, published information and statements from the winning bidders, Dong Energy and EnBW. We also considered the following key site characteristics:

  • 30-40-metre water depths
  • 10.7-11.5m/s average wind speeds
  • 70-115km distances to port
  • 5-16km distances to grid connection at an offshore hub
  • 30-year project lifetime
  • 13MW turbines

Both bidders implied the use of much larger turbines than today's. This is in line with our expectations that such turbines will just be becoming available when these projects are built.

If we consider the two neighbouring Dong sites - OWP West and Borkum Riffgrund 2 West - together, we calculate an average LCOE (in today's terms) of just over EUR51/MWh at 6% cost of capital.

It is instructive to consider how different electricity prices achieved affect these returns. If the generated electricity were to be sold at an average price of just under EUR31/MWh, the project return rate will be 0%. If it could be sold at EUR60/MWh, returns increase to 8%.

Predicting future electricity prices is a complex area with many uncertainties. In comparison, we calculate that in 2025, new-build combined-cycle gas turbine technology (CCGT) — likely to be the cheapest available "conventional" technology in 2025 — will cost €60/MWh, assuming a CO2 price of €10/tonne.

When the wind blows, all wind farms are generating and short-term electricity prices fall. Indeed, in the current German market, we have seen instances of this effect pushing electricity prices into the negative for short periods in 2015, 2016 and 2017.

Increasing storage and interconnections will mitigate this effect to some degree. Even so, the average price achieved for offshore-wind-generated electricity is likely to be at a considerable discount below €60/MWh.

These projects do not provide electricity at "no cost", rather they will supply it at a little less than average market price. That assumes, however, that they are actually built.

With final investment decisions not until after 2020, there is a chance that expectations could change regarding offshore wind LCOE and/or electricity prices post-2025, and it may no longer be economically viable to take the projects forward.

Jumping too far ahead?

While these headline-grabbing results have demonstrated the cost reductions coming through in offshore wind, I can't help reflecting that they add ambiguity to an already complex picture.

The approach of running an auction for capacity built so far ahead also perhaps places unreasonable weight on predictions of future technology capability and wholesale electricity prices.

The final business case could turn out to be very favourable (so consumers pay higher prices) or it becomes unviable and the project is not built, again ultimately to the consumer's detriment.

By all means, let's have strong plans about future auction volumes and timings that are kept to, but for now, the combination of a CfD and a project operational date mandated to be within a maximum of five years of the auction seem the best way forward for the industry, the energy supply and the consumer.

And before the rush to copy what has been done in Germany starts, it's worth remembering that this is an interim system for this and next year only.

Giles Hundleby is a director of BVG Associates

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