Offshore Wind: Can the UK Stay Ahead?

Globally, offshore farms make up just 1.25% of the wind power sector. In the UK, though, government support and attractive sites have catalysed swift development. In the first quarter of 2010, turbine manufacturers Siemens, Clipper, Mitsubishi and GE all committed to establishing a UK presence.

Yet maintaining this momentum will take both a stable, long-term market outlook, and confidence in government policy, finds a recent report prepared for Renewable UK (previously the British Wind Energy Association) by Douglas Westwood Ltd. By examining different development scenarios for the period from 2015 to 2030, it reveals widely differing implications for the wind technology supply chain, as well as the policy drivers that will be needed.

Sites all round the UK have already been identified and are being leased. Possible sites form a number of ’rounds’: Round 1 is underway, while Round 2, 2.5, 3 and projects in Scottish Territorial Waters have been identified.

The 60-turbine Robin Rigg wind farm is part of a surge in wind plants around the UK’s shores (Source: E.ON) 

Three Scenarios

The report uses three different scenarios for the development of these sites, labelled ‘Aggregated Developer Appetite’, ‘A Healthy Industry’ and ‘Low Added Value’.

The aggregated developer appetite shows rapid development from the outset, with installations peaking at 8 GW in 2018 and then plunging. It would require early decisions on Round 4 and would result in a very strong UK market if prompt decisions were taken on new UK manufacturing facilities.

The healthy industry scenario allows for a steadier installation rate of around 4 GW a year, while the low-added value scenario assumes additional delays and project attrition, with installations fluctuating between 2 and 3 GW a year, and reduced opportunity for the supply chain. The three scenarios would result in 42.7 GW, 23.2 GW and 14.1 GW of capacity by the end of 2020, respectively.

The report details the implications for the industry of the different scenarios. Clearly, the assumptions made and the scenario chosen have a big impact on the implications for the supply chain.

First, and most obviously, the size of the turbine will determine the number needed to install a given capacity. The current round is largely based on turbines with an average size around the 3.7 MW mark. As Round 2 starts, some projects will start to use the 5—6 MW class turbines being developed. By Round 3 and later, most projects are expected to use larger turbines.

The delivery profile for each scenario is markedly different. Most importantly, the healthy industry scenario has a turbine production requirement spreading out into the 2020s, and the more stable and consistent market in this scenario is likely to appeal more to the supply chain, with some 650 turbines required from 2016 onwards, a marked jump from the 350 or so anticipated in 2015.

Given the lead times involved, it is clearly important that manufacturers establish facilities promptly. From 2017, this scenario sees about 500 of the larger 5 MW turbines required per year.


The report anticipates four types of foundation: traditional monopiles, jackets, tripods, and others, such as gravity base structures. Round 1 projects are likely to be monopile, Round 2 a mixture of monopile and jacket, with more jackets in Round 3 when some tripod and other designs might also be used.

The healthy industry scenario is thus likely to need some 400 jacket foundations by 2015. Standardising jacket design and fabrication could offer significant cost savings.


The use of two categories of cables is also modelled — inter-array and export, with the export cables a mix of HVAC for projects near to shore and HVDC for projects 60 km or more offshore. For inter-array cabling, an assumption of 1 km of cable per turbine is reasonable, rising to 1.3 km of cable for larger turbines in later rounds. Cable lengths required are based on predicted sites for development in each round.

The healthy industry scenario shows inter-array cable demand peaking at about 1000 km in 2016 but settling at around 850 km in later years. Demand for HVAC cables is likely to peak at about 400 km in 2016 and then slip as more projects start using HVDC cables, with demand for HVDC likely to peak about the 1000 km/year mark in 2020.

The market for HVDC cabling is likely to be tight; there may be significant competition for capacity with interconnector cabling, and massive investment is likely to be required. Long lead times are to be expected, and costs could be very sensitive to demand.


The demand for vessels can be estimated by allowing 3.5—5 days per turbine (depending on the size), 3.5—5 days per foundation, and 5 km per day for cabling.

This allows for the reality that all year round installation will not be possible. In addition, one O&M vessel per 25 turbines during their lifetime has been estimated. Using these figures, the healthy industry scenario suggests a demand for between 5 and 10 installation vessels, 7 to 13 foundation vessels and 3 to 7 vessels for array cable installation, and 2 to 4 ships for export cabling. In addition, some personnel transfer vessels are likely to be required.

Factory Requirements

A set of broad assumptions allows a calculation back from these figures to show the number of factories likely to be required, and using typical lead times the investment pathway these imply.

A typical turbine plant can produce 180 units per year, as can a foundation plant, while array cables can be made at 200 km per factory per year, and export cables at 300 km per factory per year. Turbine plants need to start three years before the turbines are required. Foundation plants and those for cabling typically start two years before they are required.

Using the healthy industry scenario, some 22 factory ‘equivalents’ are likely to be required for UK offshore wind farms. (This does not allow for capacity before 2015.)

Being online in 2015 requires factories to be signed off by 2011. In particular, three turbine plants will need to be signed off by 2011, and a further five by 2014 to meet the anticipated rise in demand as the first Round 3 projects come into production. Similarly, these capacities imply that some six array cabling plants will be needed by 2014, and seven export cable plants by 2018. The total capital expenditure required is likely to be of the order of £1 billion ($1.5 billion).

Longer-term forecasts for offshore wind capacity largely assume the UK will be the first area to be developed, but other European waters will soon follow, together with wider deployment in other regions.

Early development of plants in the UK should leave these facilities well placed to service growing demand elsewhere. Of course, if the UK took the low added value scenario, it could easily be overtaken, and supply chain development could thus end up in Europe.


The offshore wind sector is likely to face competition for lifting vessels and engineering services from the offshore oil and gas sector.

While the UK is past its oil and gas production peak, high oil prices have given more of an incentive to renewed activity offshore. There is also anticipated decommissioning work of some 8900 vessel-days between 2010 and 2025.

On the positive side, offshore expertise from the oil and gas sector could be redeployed into the wind sector. An immediate issue, though, will be salary levels. Commercial returns from offshore wind are, at present, much lower than in the oil and gas sector.


The labels used on the scenarios give a clear indication of which is seen as the most desirable, and the most sustainable.

The very rapid growth implied in the Aggregated Developer Appetite would require swift mobilisation of capital and major government commitment. But this model represents a risk that so much capacity could be built to fulfil a short-term demand that some might end up standing idle in a few years’ time.

Similarly, the low added value scenario would see most of the supply chain capacity being developed outside of the UK.

By contrast, the healthy industry scenario would steer a course between these alternatives, and could result in the establishment of significant facilities in the UK with a sustainable, long-term demand for their output.

The logic is clear, the risks are quantifiable. But the question is can the various stakeholders – the government, industry and utilities – all work together to achieve a healthy industry?



Investment to Hinge on Market Reforms



Without a ‘quantum leap’ in offshore wind capacity investment through reforms to the energy markets in order to attract pensions and life assurance funding, the UK will miss its 2020 renewable energy targets, according to a new analysis by Pricewaterhouse Coopers (PwC).

Offshore wind plays a make-or-break role in the UK’s renewable energy strategy. It is targeted with delivering around half of the additional 27 GW generation capacity required to meet the country’s 30% renewable generation target by 2020. Last year, less than half the average annual roll-out rate of 1.1 GW needed to meet the 2020 target was achieved, PwC says.

It believes current incentive mechanisms, in the form of Renewable Obligation Certificates (ROCs) and the carbon price (even with a floor) are unlikely to address the specific challenges of offshore pre-construction financing, but could still push excessive costs onto the consumer. The report outlines mechanisms to address construction risk and stimulate investment by improving short-term returns. According to PwC, developers will face a peak cumulative funding need of up to £10 billion ($15 billion) per year to achieve the annual roll-out rate needed to meet the target, assuming limited project finance is available during the construction stage.

The constraints threatening offshore wind development include supply-chain bottlenecks (including people with the right skills mix) as well as issues related to obtaining consents and access to the grid. But perhaps the most significant barrier is the difficulty developers face in securing pre-construction finance.

If this financing issue can be resolved on a large scale it would not only enable sufficient investments, but would drive confidence within the supply chain and help ease other constraints, PwC believes. It would also provide a strong signal to the market that the offshore wind deployment target is achievable and realistic. However, the danger is that unless constraints are eased soon, developments will fall significantly short of the required roll-out path and targets will not be met.

With projects facing considerable construction, technology, operations and maintenance (O&M), price and volume risks — many of which are front-loaded — historically, the large utilities have dominated the development of offshore wind. But these firms now have many competing pressures for capital which may limit their ability to fund all the required offshore wind projects. Indeed, PwC found that, against an average £17 billion ($25.5 billion) per annum investment needed across the energy sector to 2020, the current combined capital expenditure of the six largest UK utility companies and the National Grid was less than half the 2009 level.

A key reason why the financial constraint is an issue is that project finance to support the development phase of offshore wind projects has not been available to UK projects to date, the company’s analysis finds. The challenge for banks and other financial investors is to take construction risk in the absence of an engineering procurement contract (EPC) from the sponsors. Among its key conclusions, PwC says that reducing risk or improving returns for investors would attract more pensions and life assurance funding.

Michael Hurley, global energy and utilities advisory leader at PricewaterhouseCoopers LLP explained: “The required roll out rate to achieve the 2020 targets is being hampered by the scarcity of pre-construction finance. We need to dismantle the barrier to investment by creating mechanisms to either limit the risk associated with the construction phase or to improve short-term returns, without unduly pushing excess costs on to the consumer.” He concluded: “The stable and predictable annual cash flows of infrastructure investments are attractive to pension and life companies provided that the construction risk is understood and steps taken to either insure or transfer it.”

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