Germany’s optimism for speedy offshore wind development has long since given way to the realisation that marine wind power involves much more than transferring onshore wind turbines into the sea. At the end of 2011, just 215MW of German offshore wind was delivering electricity — a large shortfall on the country’s targets, set in 2002, for 500MW of offshore wind by 2006 and up to 3GW by 2010.
Yet, over the same ten-year period, onshore wind has forged ahead. At the end of 2001, Germany had 8.8GW of installed wind capacity, all of it onshore. By the end of 2011, capacity had grown to 29.1GW; less than 1% of which was offshore. The contrast in progress has made it increasingly clear that putting hundreds of megawatts of wind capacity in clusters at sea is a very different ballgame to installing usually small onshore wind farms across the length and breadth of Germany.
Nevertheless, offshore is expected to play a considerably more significant role, with its share of the national market rising to 22% by 2020, according to Germany’s binding National Renewable Energy Action Plan, which forecasts 10GW of offshore wind and 35.8GW of onshore capacity by 2020.
Healthy pipeline
But is this aim realistic in view of the slow progress so far? There are certainly enough projects in the pipeline: the federal authority responsible for most of the projects, the Bundesamt für Schifffahrt und Hydrographie, has already authorised 27 offshore wind farms, comprising 1,930 turbines — enough to meet the 10GW target if 5MW turbines are used. Another 84 wind projects in the North and Baltic seas, with more than 6,600 turbines, are in the permitting process.
But at the end of 2012, operational offshore wind capacity may only just top 400MW, according to the federal wind energy association Bundesverband Windenergie. To hit the target, installations will have to proceed at an average of 1.2GW each year from 2013, with the corresponding requirements for investment, turbines, logistics and cabling to shore.
The slow progress can so far be explained by nature and environmental constraints. Near-shore wind is almost completely ruled out by coastal protected areas and so German developers have had to look for suitable sites well outside the national 12-nautical-mile zone.
The overwhelming majority of projects under development are dozens of kilometres from shore, in Germany’s exclusive economic zones in the North Sea and the Baltic Sea, where water depths can reach 40 metres or more. Far-shore projects face much rougher weather and wave conditions, longer travelling time from shore and a shorter fair-weather working period during the spring to autumn months.
Projects built far out at sea need to be larger to compensate for higher costs. The required investment often exceeds a billion euros, meaning that Germany’s popular onshore model of "people’s" wind stations, where financing is provided by individuals or co-operatives, has not been workable offshore.
Furthermore, the global economic crisis, followed by the euro crisis, has seriously hampered the financing of offshore wind, and many German offshore projects are still owned by developers. Only about half of the permitted projects have found buyers in the form of single large energy utilities such as E.on, RWE or Dong Energy; consortia of smaller energy companies such as Trianel; or banks and investors.
Others have even gone full circle and ended up back with a developer. The 388MW Butendiek project, one of Germany’s earliest with a permit granted in 2002, is a case in point. It was initially set up as a people’s wind project but proved too big and risky to handle and was sold to Irish offshore wind developer Airtricity in 2007. It then passed to energy company Scottish and Southern Energy (SSE) when it bought Airtricity in 2009, and was subsequently sold to German wind developer WPD in 2010.
Nuclear fallout
On top of that, major German energy companies E.on, RWE and EnBW, as well as Sweden’s Vattenfall, which were intending to finance offshore wind largely from internal company resources, were taken by surprise by a sharp change in federal energy policy last summer, when a nuclear phase-out was written into law following Japan’s Fukushima disaster.
For the major energy firms, this meant their nuclear plants, which are highly lucrative now that the capital investment has been paid off, have had their lifetimes drastically cut short, with the reactors to be phased out by 2022. These companies find that large-scale offshore wind now presents the clearest option to at least partially replace nuclear in their generation portfolios.
This is a key reason why energy majors are extremely keen to see offshore wind succeed, even though the support required per kilowatt hour is now higher than that of solar power. They have little interest in onshore wind and solar projects due to their small size, their coal power stations are under fire through carbon dioxide emission restrictions and gas is too expensive for electricity generation in Germany. If offshore projects are delayed or shelved, an important potential domestic pillar of the energy companies’ business could vanish.
It is perhaps no surprise then that E.on and RWE have been among the loudest protestors about the latest problem — anticipated bottlenecks in getting the cable links built from offshore projects to shore and the potentially increased costs that may result.
Providing the right framework for laying offshore cables to the onshore network is not proving easy. An emerging obstacle is the question of liability. If the cable is not ready to commission when the wind farm is ready to begin generation, the transmission system operator (TSO), legally responsible for building the cable, shoulders the risk. And if an accident or failure stops operation of a transmission cable that is servicing the needs of a cluster of offshore stations, again the TSO may be liable.
Taxpayer to the rescue?
In the worst case, the damages could run to billions of euros, according to Ronny Meyer, managing director of the Windenergie-Agentur Bremerhaven/Bremen, a wind agency specialising in offshore wind developments.
Such huge sums could arise if the failed cable is serving a cluster of three 400MW wind stations, Meyer explains. It takes around four years between ordering components and connecting a transmission cable; if the three offshore wind farms were out of action for such a long period, loss of generation could add up to around 19TWh. At the current rate of payment for offshore wind of €0.19/kWh, or €190 million/TWh, this is equivalent to €3.7 billion in lost earnings, without taking into account maintaining the wind farms while they are not operating.
The risk is too high for a TSO such as Tennet, legally responsible for building the cables in the North Sea, to bear alone. Under these circumstances, no insurer would provide cover and no private investor would consider becoming involved in offshore electricity transmission, says Meyer. But if the federal government — that is the taxpayer — shoulders the risk, other investors will become involved, he believes. This would be key in helping Germany to shape a successful offshore future.
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