Wind Onshore cost development
Philip Vogel; RWE Innogy GmbH
PAGE 2 RWE Innogy Strategy | 12/03/2013
Expected LCOE developments of wind onshore
> IEA Meta-study (based on 18 separate studies) foresees significant reduction of Wind Onshore LCOE in the longer run (15-40% until 2030) from 2011 level
> Potentials in cost reduction occur from
– Economies of scale in manufacturing from standardisation and automatisation
– Optimisation of turbine designs and control
– Application of light weighted materials (e.g. carbon fibre)
– Cost reduction due to increased competition in turbine and O&M markets
– Improved power electronics and conversion
Relative reduction of Capex* and o&m-cost, increased reliability and load factors
Absolute level of LCOE depends also on average wind speed.
Source: IEA The past and future cost of wind (2012)
Source: Wiser et al. (2012)
* Certain turbines itself will become cheaper; but in terms of LCOE it might be necessary to increase Capex in wind projects
PAGE 3 RWE Innogy Strategy | 12/03/2013
Europe onshore wind turbine pricing Prices continue to vary significantly within the same year by vendor, market, and turbine. This is because turbine prices are usually contingent on several factors:
Turbine model is a key determinant
Two megawatt and larger machines as well as new roll-outs and turbines designed for lower-wind-speed sites and higher towers command higher prices. With European orders, it remains common for turbine prices to vary by machine size, illustrating a nonlinear price premium for higher-output machines.
Country variations are key to supply agreements In supplying over 25 countries, all with varying market environments, turbine prices offered by turbine manufacturers vary significantly in Europe. Key levers for this variation include revenue levels, technology delivered, level of competition and transportation costs.
Limited demand results in pressure on prices With 18 turbine manufacturers delivering to Europe, all of which have production capacity in the region (except Hyundai), lower and more concentrated demand has resulted in vendors reducing prices to capture orders and increase utilization rates of production facilities to avoid or delay downsizing.
Source: IHS cera –Global wind supply chain strategies 2012.
PAGE 4 RWE Innogy Strategy | 12/03/2013
Technology suppliers aim at performance increase plus cost reduction
Source: Nordex capital market day presentation 2011
Process cost optimisation
Turbine performance optimisation
Cost optimisation Capacity ↓ Rotor ∅ ↑
Hub height ↑
Swept area per MW [m2/MW]
Change in Levelised Cost of Energy [€/MWh]
PAGE 5 RWE Innogy Strategy | 12/03/2013
Increasing rotor diameter and hub heights lowers wind generation cost
> Captured Energy (E) of the turbine is increasing with the rotor diameter (D) exponentially and with the hub height due to increased average wind speed
> However, also costs of the rotor and turbine are exponentially increased from increased diameter size and hub height (see graph below; source: Narasimalu/Funk)
> Generally diameters/hub heights have increased significantly in recent years, hence revenue increase seems to be higher than cost increase
> Furthermore, suppliers offer wider range of turbines with different combinations of rated capacity/ hub height and rotor diameter, which gives more flexibility in lowering LCOE of generation and optimisation of sites
E = Captured Energy v =velocity of wind
D = rotor diameter cp = efficiency of turbine (as function of v)
Π = pi ρ = air density
Rotor Diameter (m)
PAGE 6 RWE Innogy Strategy | 12/03/2013
Optimal siting – Optimizing Capex cost vs. revenues by technology selection
> Generally it is tried to optimize the ratio between capex cost and discounted revenues
> Optimal turbine for a site is given where marginal increase of capex equals marginal increase of revenues
> This maximizes economic value per MWh or LCOE for a certain site
> Taking different local characteristics into account different turbines are selected for different wind sites
> Major issues are:
– Wind speed average and distribution
– Maximum load on turbine
– Subsidy scheme for revenues
– Regulation, e.g. constraints on hub heights, noise emission (see next slide)
Hub height/ diameter/ rated capacity
Marginal increase in Capex cost
Marginal increase in Revenues (depending on site
specific wind distribution)
Economic Value per MWh
PAGE 7 RWE Innogy Strategy | 12/03/2013
Differences in wind sites lead to a range of turbines offered to the market
> Different turbines are optimal for different sites. This explains wide range of turbines offered to the market and used by Operators
> Very large turbines are too expensive and capex cost out-level increase in revenues (so far). Hence, they are often not used (yet)
> Very small turbines are not state of the art and there exist functioning alternatives with better revenue/ capex ratio
> However, in older wind farms older technologies are often still in place – often with higher fixed subsidies, which explain continuation of operation
Marginal increase in Revenues (depending
on site specific wind distribution)
Turbine range offered in market
Turbines not yet economic
Turbines not economic anymore
Hub height/ diameter/ rated capacity
€ Marginal increase in Capex cost
PAGE 8 RWE Innogy Strategy | 12/03/2013
Optimal siting – Optimizing capex vs. revenues by technology selection with constraints and subsequent tender
> Development is trying to optimize ratio of capex and NPV of future returns in order to maximize economic value of a project
> Furthermore, constraining site parameters need to be taken into account, which limit the potential for economic optimisation
– Grid connection points
– Regulation of noise
– Regulation of hubheight
– Environmental regulation etc.
> Constraints usually increase the LCOE of a project and limit potential for optimisation
Screening of target suppliers for suitable turbines
Hub height/ diameter/ rated capacity
Marginal increase in Capex cost
Marginal increase in Revenues (depending on site
specific wind distribution)
Economic Value per MWh
Identification of optimal possible turbine design for site
Optimal wind turbine design
€ Constraining site conditions: grid;
noise; hub height
PAGE 9 RWE Innogy Strategy | 12/03/2013
Offered range of turbines is changing with technical progress in the industry
> During the last years, offered turbines have changed significantly and new prototypes were getting onto the market frequently (until now)
Marginal increase in Revenues (depending
on site specific wind distribution)
Hub height/ diameter/ rated capacity
€ Marginal increase in Capex cost – old
Old Turbine range offered in market
New Turbine range offered in market
Technical Innovation
PAGE 10 RWE Innogy Strategy | 12/03/2013
0255075
100125150175200
20% 25% 30% 35% 40% 45% 50%
Hubh
eigh
t
Loadfactor
112m-3.0MW-80m
114m-3.2MW-140m
82m-2,3MW-80m
82m-2,3MW-140m
82m-3,0MW-80m
117m-2,4MW-140m
bubble size = swept area
3.0 2.3 3.0 3.2 2.4
Example for turbine design – performance increase
Assumptions on wind value dimension Weibull-A-Parameter 7 m/sec
Weibull-k-Parameter 3 -
average wind speed 80 m 6.3 m/sec
air density 1.225 kg/m3
average wind speed 140 m 7.2 m/sec
Efficiency of wind turbines Cp manufacturer data depending on wind speed %
> Using a simplified example for available turbines at different hub heights/ rotor diameter and rated capacity on the same site shows significant differences of load factors (or full load hours)
> Local inefficiencies are not considered here, which might reduce the output of a turbine significantly, e.g. turbulence and wake effects
> This alone is no indication for improved economics in low wind areas
Rotor - capacity - hub height
2.3
PAGE 11 RWE Innogy Strategy | 12/03/2013
€0
€500
€1.000
€1.500
€2.000
> Optimal turbine for example is with high hub height, large rotor diameter and smaller rated capacity (pink data)
> Lowest LCOE are associated with higher Capex cost, which are more than outlevelled by increase in returns
> This does not necessarily hold true for all wind sites
> Results indicate that newer turbines at low wind sites (~6,5m/sec) could become even cheaper than conventional generation
Capex increase but LCOE decrease
Further economic parameters Opex cost 38.7 €/KW
Availability 97 %
Inefficiencies via turbulence, wake effect etc. 10 %
Lifetime 20 a
Assumed Interest rate 7 %
LCOE €/MWh
Invest cost €/kW (assumptions)
€0
€20
€40
€60
€80
€100
€120
Optimal turbine with lowest
LCOE*
* This might look different for other wind sites/ distributions; it also is driven by assumptions on CAPEX/ which might differ significantly.
PAGE 12 RWE Innogy Strategy | 12/03/2013
Backup: Smaller turbine – less energy but larger load factor
0
25
50
75
100
125
18% 23% 28%
Hubh
eigh
t
Loadfactor
82m-2,3MW-80m
82m-3,0MW-80m
bubble size = swept area
??? 2.3 3.0
> Building a turbine with lower rated capacity but same design, results in decrease of produced energy as absolute measure, because in high wind situations less is produced
> However, the load factor/ fullloadhours are a relative measure and energy produced is only part of the enumerator. At the same time rated capacity is the denominator
> If the reduction of the denominator is larger than the decrease of the enumerator, the fulload hours/load factor as relative measure is increasing – which might not seem intuitive on first thought
> Turbines are not optimal if they maximize MWh, they are optimal if they minimize the specific cost of generating one MWh at a site ( optimal siting)
> Smaller generators are cheaper and if load factor is increasing by reducing rated capacity, LCOE are also decreasing
Rotor - capacity - hub height
Energy [MWh]
Fullload hours
[MWh/MW]
Load factor [Flh/8760]
Specific Capex [€/kW]
LCOE [€/MWh]
82m-3,0MW-80m 5826 1942 22,17% 1.250 108 82m-2,3MW-80m 5478 2382 27,19% 1.100 80
∆ 𝑀𝑀𝑀∆𝑀𝑀
=(5826−5478)
5826(3−2,3)
3
= 6%23%
Increase in energy
Increase in capacity
Larger turbine leads to relative decrease of
Output – despite increasing output
PAGE 13 RWE Innogy Strategy | 12/03/2013
0
500
1000
1500
2000
2500
3000
158
511
6917
5323
3729
2135
0540
8946
7352
5758
4164
2570
0975
9381
77
82m-2,3W-80m
117m-2,4MW-140m
Backup: Turbine design affects generation profile
> Improving hub height increases wind speed and rotor diameter increases captured wind energy - in total increasing energy generation
> Meanwhile there are always periods with no or almost no wind, hence improved design is not increasing the capacity credit/ secured capacity of wind power
> In this example production is smoother in windy situations and incremental changes in wind generation are lowered sometimes (at least in this example)
> By increasing hub height and rotor and capacity, the production duration curves are not fully comparable, because average wind is increasing etc.
0
50
100
150
200
25,00% 30,00% 35,00% 40,00% 45,00%
Hubh
eigh
t
Loadfactor
82m-2,3MW-80m
117m-2,4MW-140m
bubble size = swept area bubble size = swept area
2.4 2.3
Rotor - capacity - hub height
More generation
No firm capacity independent of
design
h
Wind generation duration curve
Partially smoother generation
PAGE 14 RWE Innogy Strategy | 12/03/2013
Optimal siting – Different technology designs for different wind speed sites
Prob
abili
ty
Wind in m/s
Potential wind distributions
> Some turbines are extra designed for sites with lower wind speeds
> They offer higher efficiency during periods of lower wind speeds
> Despite, lower maximum rated capacity (kW) the green curve might yield higher energy returns (kWh) than the red curve if the green wind probability density is considered
> There is no turbine that fits to all sites, local measurement on wind distribution is necessary
> Optimisation is done site specific during development of projects
> No manufacturer offers turbines suitable for all wind sites, hence several suppliers are needed for developing a wider range of wind projects
PAGE 15 RWE Innogy Strategy | 12/03/2013
Annex: Offshore
PAGE 16 RWE Innogy Strategy | 12/03/2013
New projects will be in deeper water and further from shore
Distance to shore and water depths pose additional challenges
2015 + X
8
6
5
4
Princess Amalia (Q7)
Burbo Bank
Samso
Belwind
Robin Rigg
Lynn & Inner Dowsing
Lillgrund
Barrow
Beatrice Field
Kentish Flats Scroby Sands
Arklow Bank
North Hoyle
Nysted
Innogy Nordsee 1 London Array
Nordsee Ost Sheringham Shoal
Lincs
Rød- sand II
Côte d'Albâtre
Baltic 1
Bard Off- shore 1
Greater Gabbard
Thanet
Gunfleet Sands
Horns Rev 2
Rhyl Flats
Alpha Ventus
Thornton Bank
Gwynt y Môr
Global Tech 1
Amrum Bank West
Dan-Tysk
Sandbank 24
Hochsee- windpark De Dreiht
Gode Wind
Butendiek
0
10
20
30
40
50
10 20 30 40 50 60 70 80 90 100
Distance to shore [km]
Avg.
wat
er d
epth
[m]
7
Hochsee Windpark Nordsee
1
9
Dogger Bank [125 km]
Wind farms in operation Planned projects Projects with RWE participation
1
2
2 3
3
Triton Knoll 4
5
6
7
8 Horns Rev
Nordergründe 9
Commer- cial
Albatros
Egmond aan Zee
“Pioneer” phase
PAGE 17 RWE Innogy Strategy | 12/03/2013
RWE Innogy’s stepwise approach to reduce execution risk
Bigger, deeper, further offshore – an inevitable path forward
Pipeline
Gravity
Monopile
Operational
Under Construction Dogger Bank
2017+ 250 × 6.0MW+
18 – 50m depth Nordsee Ost 2012
48 × 6.15MW 22 – 26m depth
Thornton Bank 2009
6 × 5.0MW 12 – 25m
depth
North Hoyle 2003
30 × 2.0MW 7 – 11m
depth Jacket
Rhyl Flats 2009
25 × 3.6MW 10 – 15m
depth
Dogger Bank – 125km
North Hoyle – 7km
Rhyl Flats – 8km
Gwynt Y Môr – 13km
Greater Gabbard – 25km
Thornton Bank – 30km
Nordsee Ost – 45km1
Gwynt y Môr 2012
160 × 3.6MW 12 – 28m
depth
Greater Gabbard
2010 140 × 3.6MW
25 – 30m depth
PAGE 18 RWE Innogy Strategy | 12/03/2013
Cost reductions to be expected for: foundations
1 Comparing weights and thus costs of 48 jacket foundations at Nordsee Ost (built according to German regulations) and at Thornton Bank (built according to international regulations) shows the effect. Given similar average water depths (Nordsee Ost: 23m, Thornton Bank: 18m) and comparable soil conditions the average weight of a Thornton Bank jacket is only 500t whereas the average weight of a Nordsee Ost jacket is 600t and thus 20% above the weight of the jacket built according to international regulations.
Serial production of foundations leads to reduced prices and faster production
Optimised designs for various foundations types (monopiles, jackets, gravity foundations etc.) redu-ce prices (e.g. due to lesser steel requirements)
Alignment of German industry regulations with international regulations would lead to significant reductions of foundation costs (e.g. due to less strict requirements regarding steel thicknesses1)
PAGE 19 RWE Innogy Strategy | 12/03/2013
Cost reductions to be expected for: O&M
Increased in-house activities regarding O&M for offshore wind farms will partly or fully replace costly O&M contacts with turbine manufacturers
Geographical clusters for offshore wind farms (e.g. off the coast of North Wales: North Hoyle, Rhyl Flats, Gwynt y Môr) create synergies for O&M activities
Increased reliability of components (turbines, foundations, substations etc.) reduces numbers of arduous and expensive offshore service activities
Increased rated power of turbines means a reduced number of turbines to be maintained without reducing the capacity of the wind farm
PAGE 20 RWE Innogy Strategy | 12/03/2013
Average LCOE [€/MWh]
Cost reductions with 2020 target level of €120/MWh in mind
UK industry task force has shown development paths to achieve a LCOE1 level of €120/MWh by 2020 – reduction in the range of 30% required
1 LCOE: Levelised cost of energy including development and capital expenditure | Data source: Desertec Initiative 2011; RWE 2012
020406080
100120140160180200
2010 2020 2030
Offshore development path
Large PV Southern Europe Large hydro Onshore wind
Approx. range CCGT (depends on gas & CO2 price)
Main cost reduction drivers > Cost reduction turbines > Design & cost improvements
foundations > Advanced O&M solutions
and increased reliability
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