Wed, Jun


Industry Insights

I n 1979, Danish and German manufacturers Vestas, Nordtank, Kuriant and Bonus ushered in wind power’s modern era with the mass production of large wind turbines to produce electricity. These early wind turbines had small capacities by today’s standards – 10‑30 kW – but they have scaled up rapidly, as the modern wind power industry has grown and matured.


Wind power technologies have two main characteristics: the axis of the turbine and the location. The axis of the turbine can be vertical or horizontal and the location can be onshore or offshore. Virtually all onshore wind turbines are horizontal axis turbines, predominantly using three blades and with the blades “upwind”. The utilityscale market for wind technologies uses almost exclusively horizontal axis turbines, both onshore and offshore.

The amount of electricity generated by a wind turbine is determined by nameplate capacity the quality of the wind resource, the height of the turbine tower, the diameter of the rotor and the quality of the O&M strategy. Wind turbines typically start generating electricity at a wind speed of 3-5 metres per second (m/s), reach maximum power at 11-12 m/s and generally cut out at a wind speed of around 25 m/s.

Wind power has experienced a somewhat unheralded revolution since 2008-09. Between 2008 and 2017, improved technologies – such as higher hub heights and larger areas swept by blades – have increased capacity factors for a given wind resource. At the same time, installed costs have fallen as wind turbine prices have declined from their peak in 2008-09. Balance of project costs have also declined, with these factors all driving down the LCOE of wind and spurring increased deployment. Yet there are significant cost differentials between countries. Comprehensive data on installed costs and market performance are crucial to understanding the current cost of electricity and opportunities for future cost reductions from performance improvements and installed cost reductions.

From 2000 to 2016, cumulative installed wind capacity increased at a compound annual rate of 15%, and by the end of 2016, total installed wind capacity had reached 467 GW, with 454 GW onshore (IRENA 2017b). China has the largest share of this – 32% at the end of 2016 – followed by United States (17%), Germany (11%), India (6%) and Spain (5%). China accounted for 38% of new annual capacity additions in 2016, followed by United States (17%), Germany (10%), India (7%), Brazil (4%) and France (3%). Net additions of wind power were 21% lower in 2016 than in 2015, a record year in which 65 GW was added to global capacity. This was mainly due to policy changes in China, which drove a rush of installation before the expiration of a policy support scheme at the end of 2015. China added 42% less capacity in 2016 compared to 2015, accounting for almost all the global difference between 2016 and 2015. The range of expected yearly additions in the next 3-5 years is 40-50 GW. China, the United States, Germany, India, and France are expected to account for the majority of new additions (MAKE, 2017).


The largest share of the total installed cost of a wind project is related to the wind turbines. Contracts for these typically include the towers, installation, and delivery, except in China. The range of the share of wind turbines in total installed costs has historically varied from 64-84% for onshore wind and 30-50% for offshore wind (IRENA Renewable Cost Database; Blanco, 2009; EWEA, 2009; DouglasWestwood, 2010; and MAKE Consulting, 2015a). In major markets, as costs have fallen, the share of wind turbines has tended towards the higher end of this range.

Five major cost categories drive the total installed costs of a wind project:

• Turbine cost: Rotor blades, gearbox, generator, nacelle, power converter, transformer and tower.

• Construction works for the preparation of the site and foundations for the towers

• Grid connection: Includes transformers and substations and connection to the local distribution or transmission network.

• Planning and project costs: Depending on project complexity, these can represent a significant share of the balance of project costs (i.e. the non-turbine costs).

• Land: Cost of land represents one of the smallest shares of total costs. Land is usually leased through long-term contracts in order to diminish the high administrative costs associated with land ownership, but it is sometimes purchased outright.

One of the important trends in the wind market is the larger range of wind turbines offered by manufacturers to allow developers to choose designs that yield the lowest LCOE for the site constraints they are facing. General Electric, Siemens and Vestas have all roughly doubled the number of offerings in their portfolio since 2010, with each now offering over 20 models. This also helps to reduce costs below what they would otherwise be, as utilising the same structural components across a given platform can mean up to 50% of the turbine components are identical, significantly reducing development costs and unlocking supply chain efficiencies (MAKE Consulting, 2015b)

One of the key drivers of the increasing competitiveness of wind power has been continued innovation in wind turbine design and operation (IRENA, 2016a). There has been a continuous increase in the average capacity of turbines, hub-heights and swept areas as blade lengths have grown. These trends work together in synergy to reduce the cost of electricity from wind power. Higher hub-heights allow turbines to access higher wind speeds,2 while larger swept areas from longer blades also increase the yield of a wind turbine. Higher turbine capacities allow larger projects, which can amortise project development costs over a larger output. The trade-off for these developments is that taller towers supporting greater weight typically cost more, so the impact in some markets may be cost-neutral for installed costs, but result in a lower LCOE due to the higher yields. The other challenge is that longer blade lengths come with additional engineering challenges, as loads on turbines increase significantly with longer blades, thus necessitating a different structural design. They also present a logistical challenge onshore, given their sheer length. Research into very long segmented blades is therefore ongoing, but for large projects road upgrades may prove a cheaper option than investing in segmented blades.

Demand for the latest turbine technologies is being driven by Europe, where space constraints and siting challenges mean that profitability rests heavily on using the highest performing technologies. Crucially, taller towers in European markets allow for the exploitation of marginal wind sites and existing forested land that is available for development (MAKE Consulting, 2013 & 2017b). The rapid development of wind turbine technologies has seen the most advanced turbine designs available change rapidly. In 1985, typical turbines had a capacity of 50 kW and a rotor diameter of 15 metres (UpWind, 2015). In 2016, offshore wind turbines of 8 MW capacity with a rotor diameter of 164 metres were in operation, while a 9.5 MW version of the same turbine is now available.

Figure 5.1 presents the evolution of wind turbine rotor diameter and nameplate capacity between 2010 and 2016 for countries where data is available. The ongoing trend towards larger turbines with greater swept areas is clear. Ireland stands out, having increased average nameplate capacity by 79% between 2010 and 2016 and rotor diameter by 53%. Canada, and to a lesser extent, the United States, are interesting examples of markets that have increased the rotor diameter faster than the nameplate capacity. Between 2010 and 2016, the rotor diameter of newly commissioned projects increased by 47% in Canada and 22% in the United States, while the growth in nameplate capacity was 7% and 13% respectively. Overall, the largest increases in rotor diameter occurred in Ireland (53%), Canada (47%) and Germany (36%). In percentage terms, the largest increase in nameplate capacity was observed in Ireland, followed by Germany (42%) and Denmark (42%).

WI Press R 1


Wind turbine prices fluctuate with demand and supply, as well as with economic cycles. The latter can affect the cost of the materials used in wind turbine manufacturing, as these have a significant exposure to commodity prices – notably those of copper, iron, steel and cement – given these account for a sizeable part of the final cost of a wind turbine.

Wind turbine prices reached a low in the period 2000-2002, but prices then increased, as commodity prices rose, turbine supply tightened and the growth in larger, higher performing turbines accelerated. During 2000-2002, the average turbine price in the United States was at its lowest, at around USD 800/kW and peaked at around USD 2 000 to 2 100/kW in 2008, (Wiser and Bollinger, 2017). In Europe, average prices peaked at around USD 1 900/kW for contracts signed in 2008/2009 (BNEF, 2017).

Depending on the market and technology segment, wind turbine prices peaked between 2007 and 2010 before starting to decline (Figure 5.2). The cost increase was driven by three factors. Firstly, the increase in construction costs, with materials (e.g. steel, copper, cement), labour and civil engineering costs all rising prior to the 2009 financial crisis. Secondly, for a few years, demand outstripped supply as many countries adopted policies favourable to wind deployment. This allowed manufacturers to operate with higher margins, as they struggled for a time to meet rising demand. Lastly, technology improved markedly; a trend that has continued ever since: wind turbine manufacturers introduced larger, more expensive turbines, with higher hub heights. As a result, more capital-intensive foundations and towers were needed, but helped deliver higher energy outputs, largely offsetting the higher installed costs and hence delivering a lower LCOE.

Bloomberg New Energy Finance's (BNEF) index for turbines with rotor diameters of less than 95 metres declined by 53% between 2009 and 2017, while the index for diameters greater than 95 metres declined by 41%. This value is in line with the decline observed in the average selling price for Vestas wind turbines over the period, at 48%, and close to values observed in the United States, for the vast majority of contracts. Chinese wind turbine prices peaked in 2007 and have fallen 37% between 2007 and 2016 – but started from lower levels, thus having slightly less room for cost declines.3 The decline in turbine prices globally has occurred at the same time as improved wind turbine technology: rotor diameters, hub heights, and nameplate capacity have all increased markedly.

Provisional data for 2017 indicates that average wind turbine prices across most, if not all, markets were below USD 1 000/kW by the year’s end. The last time this happened, in 2002, was when the most common installed turbine was in the 750-1 000 kW range. Contracts for onshore wind turbines signed in 2017 were for a weighted average turbine rating of 2 400-2 800 kW (BNEF, 2017;a;b;c). This is in addition to the fact that more favourable terms are now often being extracted from turbine manufacturers. These can include shorter delivery lead times, more generous initial O&M contracts, better performance guarantees and a reduced need for the order to be part of a larger framework agreement (Wiser and Bollinger, 2017).

WI Press R 2

The drivers of wind turbine price declines since 2007-2010 have been falling commodity prices, greater supply chain competition, manufacturing economies of scale and process improvements; transforming the global market into one more favourable for buyers. Competition has also increased in the wind turbine market. In 2016, the manufacturer with the largest share of global new capacity installed accounted for just 16.5% of total installations (BNEF, 2017). Indeed, competition has heightened to such an extent in the last few years that consolidation in the sector is gathering pace (Reuters, 2015, 2016 and Bloomberg, 2015).