Offshore wind costs and development risk

How procurement strategies, manufacturing costs and new technology stack up against development risk in Offshore Wind Projects.

Offshore wind is changing, and it is changing for the better. In 2006, offshore wind deployment costs started rising significantly, from £1.5m/ MW, in 2016 prices, to over £4m/MW in 2012, without a clear indication as to what the price ceiling would be. There was an industry-wide realisation that a significant shift was necessary to avoid losing out on investments to alternative renewable or low-carbon energy sources. Multiple European initiatives have since emerged, such as the Offshore Wind Cost Reduction Pathways Study in the UK, which aimed to reduce costs and ensure the viability of the industry. The general concern led to challenging targets being defined, steering the sector towards a levellised cost of energy (LCOE) of £108/MWh, in 2016 prices, by 2020, from the £152/MWh levels reached in 2016. As something of a hot topic, the industry had to stand up and deliver the cost reduction message across the board.

According to the latest Cost Reduction Monitoring Framework, not only is the sector well on its way to achieving its goals but it has continued to set increasingly challenging targets. In June this year, 11 major European energy companies signed a declaration stating that offshore wind can achieve a cost of €80/MWh (£62/MWh at that time) and below, including transmission costs, for projects reaching final investment decision by 2025, aiming to achieve grid parity, ie generate power at an LCOE that is less than or equal to the price of purchasing power from traditional technologies without subsidies. In recent weeks, Dong Energy has achieved competitive prices in its successful bids for Borssele (1 and 2) as has Vattenfall at Kriegers Flag in Denmark, which indicate these target levels can be achieved.

This cost reduction covers both capital expenditure (capex) and operational expenditure (opex). In relation to capex, reductions are being achieved by means of optimised design, with larger wind turbine generators (WTGs) being deployed that require fewer balance of plant elements (fewer foundations and cables per MW).

Opex improvements have been achieved through fewer trips during the operations and maintenance of the WTGs, as contractors gain experience and knowledge from lessons of the past. The lower cost of capital has also helped developers to significantly drive down the cost of energy.

Change has not only been driven by the  industry. Governments are modifying the criteria  for awarding subsidies, which are still required,  for the time being.

Previously projects could simply achieve  certain milestones and become eligible to receive  subsidies, such as the renewables obligation  certificate (ROC) in the UK. In the current  market, subsidies in most European countries are  awarded following a cost-driven auction process  between developers.

This change in the process is fundamental;  since the subsidy is no longer guaranteed and  developers must compete among themselves  to deliver profitable projects successfully at the  lowest cost, or miss out entirely.

However, there are technical concerns with  current cost reduction measures. At what price  will this cost reduction be delivered and what are  the associated risks? Are the changes in strategy  that have been adopted to reduce capex and opex  compatible with a low cost of capital?

Development risk in different markets
The risk of developing offshore wind projects in  each country is inherently different. The scope  of development varies by means of changing the  grid connection arrangements or through the  type of studies a developer needs to undertake,  all set against the uncertainty of whether a  subsidy will be awarded.

In the UK and France the developer needs  to construct all transmission assets from the  offshore wind farm to the onshore connection  point, including the offshore substation, export  cable and onshore substation.

The governments in Denmark and the  Netherlands provide grid access offshore – hence  only WTGs and array cables need to be installed  – while the German government provides grid  connection beyond the offshore substation,  including any possible converter from AC to DC  and the export cable link.

Developers in the UK have to undertake the  complete site assessments, including geotechnical  investigations and metocean studies. However, in  Denmark and the Netherlands the government  runs most of the site assessment activities,  including metocean measurement campaigns and  wind resource assessments.

Considering the above points, development risk  in the UK is significantly higher than in Germany,  the Netherlands or Denmark. Anyone wishing to develop a project in UK waters needs to have  significant backing to manage the development  expenditure (devex) risk they are exposed to.

So, the question is, why invest in pre- construction projects? The answer is, the internal  rate of return (IRR) tends to be significantly  higher (an increase of 20% or more) than  investments in projects already subsidised. This is  a significant amount of money when we consider  that offshore wind developments routinely  exceed the £1.5bn mark.