Risk Allocation in UK Wind Projects
By Adrian Congdon
The United Kingdom government has committed itself to meeting 10% of UK electricity supplies from renewable sources by 2010 and aspires to increase this to 20% by 2020. Given the low starting point, this means that some 8,000 additional megawatts and some £6 billion investment will be needed to meet the 2010 target. Windpower — both onshore and offshore — is seen as the best means of providing most of this capacity.
This article reviews recent progress in UK wind farm projects, how risks in such projects are being apportioned, and what some of the principal obstacles are ahead.
The rate of planning approval of UK wind farm projects has increased exponentially over the last year and is expected to improve further. Onshore, it is reported that some 1.4 gigawatts are in the planning stage with some 6.0 gigawatts being prepared for submission over the next 18 months. Offshore, 700 megawatts have reportedly been approved, a further 700 megawatts are in planning and 4.0 to 6.0 gigawatts of capacity will be applied for in round 2. Round 1 of this process was covered in the December 2002 issue of NewsWire: it contemplated relatively small projects within UK territorial waters (broadly within 12 nautical miles of the mainland). The first of the round 1 projects to achieve operation (in November 2003) is National Wind Power’s 60 megawatt project off North Hoyle. Round 2 builds on the perceived success of its predecessor and envisages much larger projects beyond the territorial waters. The first round 2 projects are expected to be awarded shortly. However, there are problems with the planning process, and these are addressed below.
A pattern of financeable risk apportionment is emerging in wind farm projects.
Turbine manufacturers have assisted by offering robust warranties. Warranties of five years duration are typical and, while lesser periods may be acceptable for proven technology, 10-year warranties have been reported. Twenty thousand operating hours are needed to demonstrate that technology is proven. Offshore in particular, wind turbine manufacturers are keen to stake a position at the forefront of an industry in its first stages and to identify first hand the actual and potential problems. Wind turbines are growing larger in size, producing greater yields, with offshore providing more opportunity than onshore in this respect. GE is a market leader, employing its 3.6 megawatts offshore turbine at Airtricity’s Arklow Bank project in Ireland: this is the world’s first commercial use of offshore wind turbines more than 3.0 megawatts in capacity. GE Wind is also active in the UK market.
Contractors who are responsible for civil works and balance of plant have been reluctant to enter into EPC (engineering, procurement and construction) arrangements that would make them jointly and severally liable with the turbine manufacturers for risks for which the turbine manufacturers are responsible (design, supply and installation of the wind turbines). Instead, general contractors prefer that each should contract directly with the developer in respect of the scope of its own works: the various contractors then enter into an interface agreement among themselves, regulating their mutual liabilities.
The conventional EPC structure is still used by some consortia, together with back-to-back agreements apportioning liability among the consortium members. Conceptually, there is no great distinction between the ultimate liabilities under an EPC arrangement with a back-to-back agreement as compared to separate contracts with an interface arrangement: so long as the responsible party is financially sound (and there have been questions raised as to the creditworthiness of some manufacturers), a company incurring exposure through no fault of its own should ultimately have satisfactory recourse against the responsible party. Some argue that the EPC structure with its single point of responsibility is itself too rigid for the practicalities of offshore wind projects. Such concerns might be assuaged by introducing an element of partnering to address, for example, weather risk and cost overruns. At North Hoyle, a long lead time of 12 months was used to mitigate schedule risk.
Apportionment of weather risk is still an issue between developers and contractors. However, it is particularly noteworthy that non-recourse financing is not currently available for the construction phase of offshore wind projects: while this may lessen the demands for an EPC structure, it raises further questions of how developers should raise funding. There is room here for deep-pocket sponsors and, possibly, private equity.
While who takes weather risk may be an open question among the various parties, lenders appear increasingly comfortable with wind risk. Data are available to identify the wind risk in a particular area: if the area is assessed as “P99,” for example, then that means that the wind is expected to be enough at the project site to enable debt service to be covered in 99 out of 100 years. Weather derivatives are also available if the generator chooses to hedge the risk: the downside is that, in so doing, the generator trades away any upside in price (unless it chooses to trade in the market by buying wind “puts”).
Financing is offered for terms of up to 15 years. Offshore leases range from terms of 22 years (in round 1) to 40 years (in round 2), so there is enough of a tail after the financing has been repaid for comfort, and lenders do not need to concern themselves with decommissioning issues.
Lenders are willing to accept contracted O&M (operation and maintenance) support for just the first five years of commercial operation of onshore projects, but a longer period will be required offshore. Maintenance reserve arrangements are open for discussion, but lenders will typically require six months of debt service reserve.
Debt service coverage ratios of 1.3 to 1.4 might be expected, although the market is fluid in this respect. Debt-equity ratios are in the region of 75-25.
A firm offtake contract is key: windpower is claimed to be unbankable in the UK on a merchant basis (although it has been banked in Ireland). As reported in the December 2002 issue of NewsWire, renewable obligations certificates, or “ROCs,” are key to making a successful offtake contract. To recap briefly, ROCs constitute government support: renewable generators are awarded ROCs that can be sold on the open market. Electricity suppliers (as opposed to generators) and traders pay a penalty of £30/mWh (indexed) to the extent they fail to supply (or trade) 3% from renewable sources. The proceeds of this penalty are distributed among the ROC holders, thus creating a market dynamic. Under offtake contracts, generators will transfer their ROCs to their offtakers in return for a fixed price.
Perhaps unsurprisingly, most of the income of renewable generators comes from ROCs rather than electricity sales — some £47 a megawatt hour against £17 a megawatt hour in 2003. It can be seen from this how important ROCs are to the bankability of a project.
Conversely, actual and potential weaknesses in the ROC mechanism may serve to undermine the renewables market disproportionately. First, there is the commercial risk that parties will default on their penalty obligations, thus reducing the amount to be distributed and the value of ROCs themselves: TXU failed to pay £23.1 million owing in this respect when its UK operations collapsed. Second, the value will be diluted as more renewable generation comes on line. Third and most important is the political risk. The UK government states that it is committed to ROCs in the long term, but lenders and developers focus on the fact that, whereas 10% of all electricity supplies from renewable sources by 2010 is a target, 20% by 2020 is no more than an aspiration. On that basis, lenders and developers argue that all renewable projects are deemed merchant after 2010. Some might regard this argument as somewhat disingenuous: the implication is that such projects then become unbankable while, actually, terms of offtake contracts for renewable projects do extend beyond 2010 (even if the balance of contractual risk may change) as do the terms of the requisite loans. Therefore, there is presumably some confidence that ROCs will remain in place after 2010. Nevertheless, the government is committed to review the ROC mechanism in 2005 or 2006, and there are calls for it to boost the market by making 20% by 2020 a target rather than an aspiration as well as by increasing ROC prices.
Political and regulatory risk remain a material issue, both on a UK and a European Union level. The EU is expected to introduce an emissions trading scheme in 2005, and it is unclear how this will interact with the ROC mechanism, which is a different type of product. The UK government needs to maintain financial support for the renewables sector, particularly offshore wind while that market is nascent with the attendant high prices. Government support is seed corn money. As well as ROCs, it takes the form of capital grants. In October this year, the government announced it was giving £59 million in grants to six offshore wind farms in addition to £58 million previously allocated to another six.
While most risks can be managed between the parties to a project, there are some large-scale obstacles to the initial development of wind farms. These relate to planning and the grid network.
The planning approval process onshore and offshore has not been uniform throughout the UK. Onshore, the approval rate in Scotland is 90% while in Wales it is only 20%. This regional variability fuels further applications in Scotland, but it may lead to a Scottish backlash against wind farms on the basis that the Scots have to view what some regard as eyesores so that others elsewhere can feel environmentally virtuous. Reasons for delay in the planning stage include landowner and developer inexperience of “section 106 agreements.” Section 106 agreements are contracts between developers and local authorities under which planning permission is granted in return for developers upgrading highways and other public works. Offshore, planning has been complicated by there being two alternative routes to obtain approval, one centered on section 36 of the “Electricity Act 1989” (also the route used onshore), the other centered on the “Transport and Works Act 1992.”
The government is seeking to address problems both onshore and offshore. In October 2003, it issued a consultation paper seeking comments on the proposed Planning Policy Statement 22, or “PPS22.” PPS22 is intended to set out the framework within which planning decisions on onshore renewable energy projects should be made by local planning authorities. The object is to assist in meeting the target of 10% by 2010 as well as in cutting CO2 emissions by 60% by 2050. Among the government’s proposals are that planning policies that rule out or place constraints on renewable energy technologies should be barred. In addition, planning authorities should seek to promote public knowledge and acceptance of renewable projects. The government wants regional targets to iron out disparities. It also wants to prevent local landscape from being used as a reason to prevent development. What form PPS22 finally takes remains to be seen, but it should be expected that onshore planning policy guidance will evolve in a more renewables-friendly direction.
PPS22 applies to England: equivalent documents are being issued by the Scottish Parliament and the Welsh Assembly. Regarding offshore wind farms, the government plans to assert jurisdiction in relevant areas outside territorial waters in a similar way to that used to exploit North Sea oil and gas and to rationalize the planning process so that section 36 becomes the lead consent in the way that it is onshore (although additional types of consent will be needed to address the fact that these projects are marine).
The obstacles relating to the grid network are regulatory and practical in nature. One concern is whether wind farm generation can be suited to the grid code (part of the regulatory regime). The grid’s requirement for stability conflicts with the sporadic nature of wind farm generation.
Some in the industry take the positive view that it is up to manufacturers to carry out the requisite research and develop wind turbines that can cater to the grid’s demands for stability, frequency response, reactive power and fault ride-through. However, all sides recognize that the grid system needs upgrading in any event. Even though the UK network does have an availability of 99.98%, much of the transmission network was constructed more than 40 years ago and is regarded as needing urgent replacement. The problem this raises is that the time required for the planning and construction phases of new grid infrastructure is historically some six to seven years, which means that, if the planning phase started now, the infrastructure would be unlikely to be available for transmission of the 8,000 additional megawatts needed from renewable sources in order to meet the government’s 10% target for 2010. Even before the planning stage begins, a decision will have to be made how to fund the £1 to 1.5 billion anticipated costs of the infrastructure works. Ofgem — the industry regulator — has recently issued a consultation paper on this. The government will have limited scope to expedite this process since there will be numerous private land interests involved.
Planning thus appears the main outstanding issue facing those seeking to develop the UK renewable sector, particularly windpower, and this is in the context of both approval of specific schemes and the upgrade of grid infrastructure. There are other complications in the planning process relating, for example, to the Ministry of Defense and the protection of birds. Nevertheless, planning approval rates are accelerating, and the government is committed to facilitating the planning process and supporting the industry financially.
Meanwhile, there is the requisite will among lenders, developers and manufacturers to make wind projects commercially viable and to take advantage of offshore projects to develop technologies which produce greater yields.