The roots of the current situation stretch back to 2005. In that year, negotiations on turnkey engineer, procure and construct (EPC) contracts for two key projects, Lynn & Inner Dowsing and Robin Rigg, broke down. Difficulties in apportioning risks and costs between parties in the EPC consortia and their subcontractors, and consequently the price to be charged to the developers, were to blame. It was becoming clear that a "funding gap" was opening up between the revenue available under the government's support mechanism, the Renewables Obligation (RO), and the higher cost of offshore.
Policy proposals to remedy the situation came thick and fast, particularly as government announced an energy review in 2005. This proposed that the RO be banded - that is, that different technologies receive different multiples of renewable obligation certificates (ROCs) per megawatt hour. Up to that point, all technologies received 1 ROC per megawatt hour. In 2007, when the Energy White Paper was published, the decision was made that offshore wind should receive 1.5 ROCs per megawatt hour. After the necessary legislation was passed as part of the Energy Act 2008, the Renewables Obligation Order 2009 entered into force on April 1 this year, with banding a key part of the reforms implemented therein.
But while analysis by Ernst & Young published alongside the White Paper, and used as evidence for the decision on banding, used capital cost estimates for offshore of £1.5-2 million/MW, costs continued to rise. Further experience in project development has led to more contingencies and other risk pricing being factored into contract costs in the last few years. This has been complicated by the multi-contracting approach required after the collapse of the EPC market. Increases in costs for basic commodities like steel and copper have been compounded by fierce competition for components in the wind industry globally, while in the offshore sector specifically, the number of suppliers is limited and they are competing for resources with an offshore hydrocarbon sector stimulated by a rapidly rising oil price. By summer 2008, capital costs had spiralled to around £3 million/MW. The Energy White Paper's 1.5 ROC per megawatt hour was already looking like it could be inadequate.
On the face of it, the market maelstrom provoked by the collapse of Lehman Brothers in September 2008 could have had some positive effects. A slowdown in the general economy leads to lower steel and copper prices; the US wind market hitting a brick wall means capacity in the industry to supply turbines; interest rates are at historic lows. However, in the UK the crunch has been accompanied by a plunge in the value of its currency, the sterling, against the euro. Since much of the value of wind projects, particularly the turbines, is denominated in euro, this has led to a steep rise in the capital cost of projects. This has not been balanced by falls in the euro price of turbines. Power market prices have also fallen with the price of oil and lower demand. As the RO is a quota system, this is a key part of the economics of projects. And with capital markets drying up, money is both scarce and expensive.
With this "perfect storm" hitting the UK offshore wind sector, the British Wind Energy Association (BWEA) drew up a submission to Treasury, outlining a case for the action needed to prevent offshore development stalling. As a sign of how this sector has risen on the corporate radar, individual utilities with stakes in leading projects were also lobbying on their own behalf, most notably E.ON and Centrica, whose chief executives were seen in the national press speaking out for more support for offshore.
On budget day, April 22, it was clear that Chancellor Alistair Darling had been listening carefully. He announced plans for an "emergency review" of the banding for offshore, with a view to increasing support to 2 ROCs per megawatt hour for projects which reached financial close and ordered turbines before April 1, 2010. Support will fall to 1.75 ROCs for projects reaching financial close in the following year up to April 2011, after which it will revert back to 1.5 ROCs. The evidence presented by industry has been backed up by further analysis by Ernst & Young, published days after the budget. This confirms that at least 2 ROCs per megawatt hour is needed for projects to be viable (page 8).
Still, there is a process that needs to be undertaken before the 2 ROC rate enters into force. The Renewables Advisory Board needs to formally launch the offshore banding review. At the time of writing it is still to give its opinion, though this is unlikely to disagree that a review is merited. There will then be a 12-week public consultation period, after which the final proposals need to be included in the Renewables Obligation Order 2010. Further changes to the RO to extend it to at least 2037 and allow it to rise beyond 20%, flowing from the renewable energy strategy to be published in June, will also need to be included in this order, so further statutory consultation is likely. The order then needs to be approved by parliament.
The fact that this process is only at the beginning seems not to be holding developers back though. On budget day itself, Dong Energy said the second phase of its Walney project in the Irish Sea is now going ahead. This was followed last month with the news that the partners in the 1000 MW London Array project would now push ahead with delivery of its 630 MW first phase.
The solution announced in the budget is not without costs and risks. There will be some impact on other renewables, since there will be more ROCs on the market than would otherwise be the case, which will reduce the price and bring forward the day when "guaranteed headroom" is invoked. The 12-week consultation period will give all sides the opportunity to comment on whether the extra ROC production from the stimulated offshore projects will materially impact their business.
The key to whether this proposal is the bridge into a stable policy support world at 1.5 ROCs per megawatt hour is whether costs can be brought down enough by 2011 to make the remaining Round 2 projects - those approved for development under the government's second round of site leasing concessions - economic at that level. There are many variables in play here, many outside the control of the UK wind sector. Most notably, the value of sterling would have to rise significantly against the euro, and this is not easily amenable to influence.
Two years is too short a time to establish a manufacturing base in the UK that would get around this key issue, though there is welcome additional support, announced in the budget, for this purpose. BWEA will be lobbying to direct it in the best ways. It is too little time for there to be much change in terms of competition in the offshore turbine market, though there may be improvements in other parts of the offshore supply chain, like installation vessels. Uncertainty about how the general economic situation will evolve also remains, and about how developments in the wind market elsewhere, most notably the impact of the US economic stimulus package, will affect the ability of turbine manufacturers to supply offshore.
BWEA is looking to provide evidence to government and others on these issues and look at how costs are likely to evolve for Round 3 and the Scottish Territorial Waters projects, given many of these will be in challenging environments, deep water and further offshore. The only way this industry will survive in the long term is if there is a clear vision on how to reduce the costs, backed up with a plan to deliver that in the next decade. The budget stimulus should keep the sector from stalling in the short term. The challenge is to use the breathing space provided to set out the long-term vision and start to deliver it. The sector must step up to this challenge, otherwise it will have to keep returning to government for further help, which will not deliver the stable conditions needed to build a strong industry.