UK wind projects
By Adrian Congdon
Interest is increasing across the world in renewable sources of energy, especially wind. The commitment is perhaps greatest in Europe. Germany has half the installed windpower in Europe, and a third of that in the world. In the United Kingdom, the government has attracted attention by introducing a scheme under which suppliers of non-renewable energy pay financial penalties, the proceeds of which are distributed among those supporting renewable sources. At the same time, conscious of the limited space inland, the UK government is promoting the construction of wind farms off the coast: 18 agreements for such projects have been signed so far.
This article looks at the “renewables obligation”— as the law in the UK is called that promotes use of renewable energy — and at offshore wind farms in the UK.
Since earlier this year, every supplier of electricity in the UK has been under a “renewables obligation,” meaning that it has to pay £30/mWh for electricity supplied from nonrenewable sources such as coal and gas. A supplier for these purposes is not a generator; it is someone who buys electricity from a generator and resells it to users. An example of a supplier is London Electricity plc.
Generators using renewable sources such as windpower are awarded renewables obligations certificates — called “ROCs” — which exempt the holders from having to pay this penalty.
The proceeds from the penalties do not go to the government: instead, they are distributed among renewable electricity generators and other holders of ROCs. This dynamic creates a market for ROCs. The generators can sell them for at least £30/mWh, effectively receiving something for nothing.
Suppliers have an interest in obtaining ROCs, not just because they will thus avoid having to pay the £30/mWh penalty, but also because of the right to a share of the penalty proceeds. The market has yet to settle down, but — in September 2002 — ROCs were at one point trading at £48/mWh.
Generators get value for their ROCs by selling them for cash. There is no inherent reason why a generator should not sell the ROC to someone other than the person to whom he sells the electricity, but this is not very common in practice. Usually, the “supplier” buys the ROCs along with the electricity.
Prices for ROCs might differ from one project to the next. The price is a function of such things as the flexibility of the generator, the length of the contract, the technology and size of the renewables project, and the general apportionment of risk sharing. For example, the greater the commitment the generator can give in respect of reliability and flexibility, the higher the price the supplier should be willing to pay for ROCs. Conversely, the longer the term of the offtake contract, the more willing the generator may be to lower the price. Despite the fact that there will be two separate price negotiations, one for electricity and the other for the ROC, the existence of the ROC will be key. A political act resulting in the abolition of ROCs is likely to lead to the termination of the offtake contract; and lenders’ funding of a renewables project will be contingent on the continuing existence of the ROC mechanism.
In the renewables obligation, the British government has developed a market-based policy for reducing greenhouse gas emissions rather than one based on taxation. The European Commission is planning an EU-wide emissions trading scheme of which ROCs will form part. (They will be cancelled for domestic purposes to the extent that they are used in the wider scheme.) The government has given a commitment that ROCs will be around until at least 2027; and, while this does not eliminate political risk, it should be of comfort to sponsors and lenders wishing to take advantage of the scheme.
A final observation on the financial incentives created by ROCs is that they may end up as victims of their own success. The less renewable energy is generated, the more £30/mWh penalties will be paid and the greater the rewards for ROC holders. However, as more renewable sources come on line, there may be fewer people paying penalties and so less to be shared round the greater number of ROC holders.
Offshore Wind Farms
The British government is also providing capital grants towards offshore wind projects.
A preliminary sum of some £70 million has been allocated for the development of offshore windpower over the next three years. It is unclear whether this will be targeted or thinly spread, although it appears likely it will be applied to up to 40% of a project’s eligible costs (in order to comply with EU competition law). Some might argue that it would be preferable to subsidise the tariff rather than construction since the subsidy would then apply only to the extent assets actually generate electricity and not to underperforming ones.
Wind farms have been constructed inland over the past dozen years or so, but with improvements in turbine technology, wind farms off the coast have increased in appeal. Space is constrained on a small island, and there is a limit to the number of places - almost inevitably places of natural beauty - in which wind farms can be located. Onshore wind farms have typically been around 10 to 20 megawatts in size. Offshore, 20 megawatts is seen as a minimum and projects of around 100 megawatts are contemplated. Indeed, the proportionate cost of an offshore wind project is, at an estimated £1,000 a kilowatt, some 30% more than that of an onshore wind farm. This means there is an added incentive to build larger projects. Economy of scale and bigger turbines may lead to higher yields.
The Crown Estate, which owns the seabed, has entered into 18 agreements for lease of sites for offshore wind farms. Property held by the Crown Estate is, as the name suggests, owned by the Crown itself, technically the owner of last resort of all land in the UK. The revenue from these leases will however, like all Crown Estate revenue, be assigned to the Treasury and thus be under the control of the government. It is envisaged that a similar number of leases will be made available in mid-2003.
In order to pre-qualify for the right to a lease, an applicant must have at least £50 million in net assets, offshore development expertise and wind turbine experience. The financial standing requirements suggest that no such project can be nonrecourse. Exploration for, and extraction of, oil and gas from the North Sea over the past quarter century means there is plenty of offshore development expertise; but that is unlikely (at least at first) to be found in those with wind turbine experience. The result is that consortia will be formed.
The site for a project must be within 12 miles of the coast and not more than 10 kilometers from any other wind project. Each project must have a minimum generating capacity of 20 megawatts but no more than 30 turbines. In addition, no site can be more than 10 square kilometers. A successful applicant has a three-year grace period within which to decide whether to go ahead. On grant of the lease, the applicant has two years within which to commission the project. Each lease is for a term of 22 years, which includes one year at the end for decommissioning. The rent is broadly 2% of project revenues. Force majeure is at the tenant’s risk, as is change in law (typical in UK government-promoted projects). The lease is granted subject to public rights of navigation and fishing.
While incentives have been put in place to make offshore wind farms attractive to investors — ROCs, capital grants and the generally favorable political environment being among them — there are a number of substantive risks that need managing.
Onshore wind turbines have typically been around 0.6 to 1.5 megawatts in size. The UK government expects that, owing to higher installation costs, turbines used offshore will exceed 2 megawatts. Taller turbines experience higher wind speed and thus should produce greater yields. Turbines are available currently with output of up to 4.3 megawatts, but bankability and syndication both demand a conservative approach that does not favor unproven technology. Lenders will look for an established name and the history of operating hours for a particular turbine make, as well as for an independent engineer review. Warranties of at least five years duration are likely to be sought, and this means that the interests of the turbine supplier and the operator tend to conflate.
The turbine supplier is usually responsible for installing the turbine. It does not follow that lenders will be looking for a single point of responsibility for all engineering, procurement and construction works. The turbine supply and installation works may be split from the balance of plant (for example, civil works onshore). Key risks to be allocated between the developer and the construction contractor include what happens if there is a shortage of cranes, the difficulty of raising turbines in a windy environment, and weather risk generally. How the weather risk is apportioned may well be contentious: the developer may take this risk in the construction phase, but the turbine supplier may be required to assume it during the warranty period.
Operation and maintenance services, and reliance on the turbine supplier’s warranty, are matters of greater sensitivity in offshore projects than would be the case with an onshore wind farm. Unscheduled maintenance is likely to be required at times when accessibility is most difficult, during bad weather. Particular areas in which problems have arisen on existing offshore wind turbines have included gear boxes, cabling and blades coming off. The risks that the O&M contractor will be required to assume will be disproportionate to the financial rewards typically available to such a contractor in a power project. For this reason, there are merits in combining the construction and O&M functions and paying the construction fee on an amortized basis over not just the construction phase, but also the first, say, five years of operation, subject to achievement of performance, warranty and availability obligations. This is the same approach taken to the construction and operation of gas storage facilities within salt caverns. However, the difference between such gas storage facilities and an offshore wind farm is that, after the first five years of operation, the geological risks inherent in a salt cavern should be in the past, while there will still be a need to carry out maintenance of a wind turbine in stormy seas.
Finally, there is the offtake risk, or the question of who takes the risk of shortfall in dispatch of the generator. This is particularly sensitive in the UK following the introduction in 2001 of new electricity trading arrangements, or “NETA,” under which a generator can face very high financial liabilities for dispatching, in a half-hour period, a volume different than that which it notified centrally at least an hour before. Typically, offtakers are better suited than generators to manage this risk: for example, it can be hedged by way of derivatives in the electricity trading markets. The risk is most likely to materialize for reasons related to the weather. In addition, weather derivatives are available to protect against weather risk, and these should enhance both bankability and return on equity. The particular advantage they have over insurance policies is that no loss need be shown. In practice, the offtaker will tend to take the risk of non-delivery, but the one risk it will not take is the political risk of the loss of the renewables benefit.
The British government agreed at Kyoto in 1997 to reduce the country’s greenhouse gas emissions by 12.5% by the period 2008 to 2012. It has an additional target of reducing carbon dioxide emissions by 20% by 2010 (against 1990 levels). To further this goal, it is aiming for 5% of UK electricity to be generated from renewable sources by 2003, rising to 10% by 2010. The “renewables obligation” fits well with these targets and its existence (together with the direction of EU policy) may give offshore wind projects the push they need.