The cost of offshore wind energy is a major preoccupation for the UK. In June, two industry initiatives reported on the savings available and how best to deliver them: the UK government’s Cost Reduction Task Force and the Crown Estate’s Offshore Wind Cost Reduction Pathways study.
The Crown Estate study, which was undertaken by BVG Associates for technology, EC Harris for the supply chain and PwC for finance, was significant in two ways. First, the three work streams recognised that innovations are needed not only in technology but also in the relationships throughout the supply chain, and in unlocking the significant amount of finance required to deliver plans in a challenging global economic situation. Second, the study focused on the effects on levelised cost of energy (LCOE), which is a function of not only capital investment (CAPEX), but also operating costs (OPEX) and annual energy production.
Offshore wind CAPEX has attracted a lot of attention in recent years following substantial increases. Indeed, as wind farms are installed at sites further from shore and in deeper water, the industry will have to work hard not to exceed current levels of CAPEX per megawatt installed. The important point is that energy yield from such sites is higher due to increased wind speeds. Revenue therefore is higher, and LCOE lower.
Areas of focus
Further improving the cost of energy relies on doing a number of things better, including reducing risk during construction and operation, increasing reliability, improving the efficiency of maintenance operations and, most importantly, increasing the energy production from assets.
Across the industry, there are plenty of ideas on how to reduce technology and supply chain costs. The key challenge was to quantify the benefits of individual innovations, different for different projects using different base designs, to enable us to focus on what really impacted on LCOE.
For the Crown Estate, we built a cost model where innovations were assessed on their potential for cost reduction. In each case, a conservative approach was taken to build confidence in the results. Figure 1 shows that more than 80% of the total anticipated technology impact is achieved through seven areas of innovation, of which the largest is an increase in turbine size from 4MW to 6MW capacity.
What innovation can do
We analysed the impact of around 60 independent innovations in wind farm development, including: turbine, foundation and cable technology; installation vessels and processes; and operation, maintenance and service. For each one, we quantified the impact on the CAPEX and OPEX of each element of the wind farm, and the impact on gross and net annual energy production.
The upshot of our research was that turbine size has the most impact on LCOE. The transition from today’s turbines with a typical rating of 4MW to next-generation 5–7MW turbines will see CAPEX/MW rise by 11% but — by virtue of needing fewer turbines for a wind farm’s rated power — produce significant savings in other areas of supply, which combined lead to a 9% reduction in LCOE.
This is due to a number of factors. Foundation costs do not increase proportionately with turbine rated capacity. For a project in 35-metre water depth, the cost of a jacket foundation for a 6MW turbine is 35% higher than for a 4MW turbine, but a wind farm of the same capacity has 50% more 4MW units than a project equipped with 6MW turbines.
For installation, the increased time taken to install the larger turbines and support structures is more than offset by the smaller number of structures in a project with 6MW turbines. For array cable installation, a significant cost is the time taken at the cable pull-in at each turbine location. The reduced number of structures, again, results in cost savings.
Operation, maintenance and service (OMS) costs do not rise proportionately as turbines get larger. The cost of operation, unplanned and planned maintenance is less than 25% higher for a 6MW turbine than a 4MW machine.
Costs offset by yield
Rotors contribute a smaller fraction of total cost in offshore wind farms than onshore due to increased balance of plant, installation and OMS costs. It therefore makes economic sense to invest in a larger rotor with a lower specific rating than for an onshore turbine. For a 6MW offshore turbine the optimum rotor diameter was calculated to be around 158 metres. Although this figure will be different for each turbine and foundation assumption, almost all of the 6MW turbines under development today have rotors that approach this size. For example, Siemens has chosen a 154-metre rotor for its forthcoming 6MW direct-drive turbine.
The rotor capital cost rises by 20% when increasing the rotor from today’s baseline to the optimum size for a 6MW turbine. There are further impacts on turbine and support structure costs from the extra loadings and from array cable and OMS costs due to increased turbine spacing, but these are more than offset by increased yield.
Further rotor innovations include improved blade manufacture and design, and aerodynamic control. Our study put the total cost of energy reduction from rotor innovations at 6%, mainly achieved through increases in energy production rather than decreases in costs.
Most next-generation turbines use either direct-drive or medium-speed drive trains. The emphasis from manufacturers is on reducing OPEX through greater reliability. Our study did not find any inherent superiority in either approach. Turbine manufacturers will have to demonstrate this reliability to customers and financiers with experience of operational issues to date. A step-change in verification testing and increased openness is critical to achieving this.
Through our discussions with industry, we saw little sign that departures from the three-bladed upwind turbine configuration would have a significant impact on the LCOE and thus the market. With fewer constraints from noise or visual intrusion offshore, there might be merit in reconsidering other approaches including two-bladed, downwind turbines with higher tip speeds. Similarly, there is a valid argument that vertical-axis turbines may be cost-effective at 10MW or beyond due to the avoidance of reversing gravity loads on the blades.
In all cases, the potential cost reductions from these innovations may be insufficient and the uncertainties so great that a departure from conventional arrangements by established manufacturers is hard for them to justify. The emergence of more radical approaches is likely to come through the successful entrance of new players to the market.
The two biggest innovations in OMS are a move to holistic, condition-based maintenance, with reduced downtime and large component retrofits, and improvements in the transfer of personnel from vessel to turbine. Both will have their biggest impact on far-from-shore projects, where greater transit distances and more severe sea states are experienced. We anticipate a 2% reduction in the LCOE due to such innovations.
Flexibility for developers
Overall, the study confirms that offshore wind has the opportunity to be a major and cost-effective part of a sustainable UK energy mix, provided it can address known issues. The UK needs consented sites for coastal manufacturing and assembly, and for testing and demonstrating turbines and support structures. Flexibility is needed in the permitting process to allow developers to delay technology choices until after consent. Early collaboration between industry partners will also have a significant positive impact.
The focus must shift to full lifetime costs and an appreciation that, in some areas of supply, LCOE savings will come from increased capital expenditure, especially on rotor and nacelle. Most critical, however, is industry confidence in a growing and sustainable UK market in which to invest. Clarity on the mechanism and level of support provided as part of the electricity market reform is a key factor underpinning this growth.
Bruce Valpy is director of BVG Associates. The Offshore Wind Cost Reduction Pathway: Technology work stream report is available at www.bvgassociates.co.uk