Volume 2 wind energy 2 15 – wind energy economics

Volume 2 wind energy 2 15 – wind energy economics Volume 2 wind energy 2 15 – wind energy economics Volume 2 wind energy 2 15 – wind energy economics Volume 2 wind energy 2 15 – wind energy economics Volume 2 wind energy 2 15 – wind energy economics Volume 2 wind energy 2 15 – wind energy economics

D Milborrow, Lewes, East Sussex, UK

© 2012 Elsevier Ltd All rights reserved

2.15.2.1.5 Internal rate of return

2.15.2.2 Price Calculation Methods

2.15.2.3 Recommended Practices

2.15.2.4 Interest Rates

2.15.2.5 Amortization Periods

2.15.2.5.1 Influence of interest rates and repayment periods

2.15.3 Cost and Performance Issues

2.15.3.1 Balance of Plant Costs

2.15.3.2 Operational Costs

2.15.3.3 Size of Wind Farm

2.15.3.4 Installed Costs and Wind Speeds

2.15.4.1 Historical Cost and Performance Trends

2.15.4.2 Current Plant Costs

2.15.4.3 Current Electricity Generation Costs

2.15.4.4 Small Wind Turbines

2.15.4.4.1 Offshore wind

2.15.4.5 Historical Price Trends

2.15.4.6 Current Installed Costs

2.15.5 Analysis of Offshore Costs

2.15.5.1 Operation and Maintenance Costs

2.15.5.2 Water Depth and Distance from Shore

2.15.6 Electricity-Generating Costs

2.15.6.1 Generation Cost Comparisons

2.15.6.1.1 Key issues

2.15.6.2 Cost Comparisons – Wind and Other Plant

2.15.6.3 Cost Comparisons on a Level Playing Field

2.15.7 External Costs

2.15.7.1 Types of External Cost

2.15.7.2 Costing Pollution

2.15.7.3 Market Solutions

2.15.7.4 The UK Climate Change Levy

2.15.7.4.1 External costs of renewable energies

2.15.7.5 Renewable Energy Support Mechanisms

2.15.7.6 Embedded Generation Benefits

2.15.8.4 Extra Short-Term Reserve Needs and Costs

2.15.8.5 Carbon Dioxide Savings

2.15.8.6 Extra Backup and Its Costs

2.15.8.10 Wind Surpluses at High Penetration Levels 492

2.15.1 Introduction

The aims of this chapter are:

• To review the generation costs for onshore and offshore wind energy; determine the relative importance of turbine prices, slight costs, and other factors; and indicate how generation costs are influenced by test discount rates and depreciation periods

• To discuss the key factors that need to be taken into account when comparing renewable energy generation costs with those from the thermal sources, principally:

• External costs

• The ‘embedded benefits’ of renewable sources (which can be positive or negative)

• The extra balancing costs incurred by the variable sources such as wind, wave, and solar

There are no absolutes in energy prices No single number can be assigned to the price of wind energy The same is true of energy prices for thermal plant Unless the relevant assumptions are clearly set out, single numbers are virtually meaningless

It is important to distinguish between the cost of plant (such as wind turbines and wind farms) and the price of the electrical energy they produce Capital costs are primarily a function of the size of the installation (due to economies of scale) This chapter focuses principally on large-scale wind farms as these deliver the cheapest electricity costs, but there is a brief review of the costs of smaller installations

Wind energy prices depend on wind speeds and institutional factors, and have two components:

• Capital charges, including depreciation and interest charges

• Operating costs

The calculation of wind energy generation prices follows procedures that are reasonably standardized across the power industry

‘Real’, that is, net of inflation, interest rates (test discount rates) are used to determine the capital charges The term weighted average cost of capital is also used National interest rates and repayment periods vary widely, but comparisons can be made provided the levels are quoted

Institutional factors account for most of the apparent variations in quoted wind energy prices In Denmark, for example, the costs

of grid reinforcement for wind installations are not always charged to the developer and the utilities tend to use relatively low interest rates (5–6%) In Britain and the United States, however, investor-owned utilities tend to use interest rates around 10% In this chapter, for the sake of uniformity, an interest rate of 8% is used, except where stated

Comparisons of generation costs are not necessarily the most equitable way of assessing the competitive position of renewables and so there is a brief description of the ‘external costs’ of electricity-generating sources, drawing on the European Union’s (EU’s)

‘ExternE’ project plus other material

A complete and fair comparison between wind energy generation costs and those of the fossil fuel sources demands that the additional costs associated with the variability of wind is also taken into account and that the relevant issues are discussed The chapter also discusses methods of valuing renewable energy One of the distinctive features of renewable energy is that most plants are ‘embedded’ in distribution networks – rather than connected to transmission networks They therefore accrue additional value, beyond simple ‘fuel saving’ levels The relevant issues are discussed, but it is also noted that the ‘embedded value’ may be negative if exploitation of renewables demands major transmission reinforcement Finally, examples of ‘total cost estimates’ are

discussed, which take into account all the debits and credits associated with renewable energy costs The chapter concludes with a discussion of published forecasts of future price trends

Note on currency conversions: Present-day (2010) prices have been converted on the basis that £1 = $1.60 and €1 = $1.36 Historical data have been converted at the exchange rates prevailing at the time, but where the data are intended to show trends, rather than absolute values, some have been left in the original units

2.15.2 Basic Financial Issues

2.15.2.1 Definitions

To the layman, costs are paid to acquire items and prices are the amount for which items are sold or offered Value is the worth of an item to the recipient The context must therefore be clear Manufacturers incur costs when building wind turbines and sell them at a price that includes their profit A wind energy developer, however, will incur costs throughout the lifetime of the project, which include the turbines, the ‘balance of plant’ costs plus operation and maintenance costs Developers sell the energy at a price that includes profit Inputs are therefore costs and the output is a price However, conventional terminology sometimes means that rigorous definitions cannot be used without causing confusion The term ‘generation cost’, for example, is very widely used, even though it usually includes an element of profit It has been retained here, even though, strictly speaking, the term should be

‘generation price’

2.15.2.1.1 Cost inputs

There are two cost inputs to a wind developer or owner The capital, or installed, costs of the plant are most frequently quoted in terms of investment cost per installed kilowatt, or $ kW−1, and, broadly speaking, are primarily a function of the size of the installation (due to economies of scale) Operating costs are the second input, and, similarly, depend on size, but may be dependent, also, on energy yield

2.15.2.1.2 Energy prices

These depend on installed costs, wind speeds, test discount rates, and capital repayment periods, and are simply the sum of the capital cost element and the operating costs, and are expressed in various ways although $ MWh−1 is used in this chapter

In general, there are three principal components of electricity generation costs:

1 Those associated with repayments of capital (plus interest) Quantifying the total capital costs that need to be included when putting a price on electricity-generating plant is relatively straightforward The capital cost includes the cost of the plant, land acquisition (unless a rent is paid, in which case this is a running cost), grid connection (although in some European states, the utility has borne the cost), and initial financing costs (not repayment costs)

2 Operating costs include insurance, rent, and local authority rates, as well as the costs of labor and materials used for operations and maintenance

3 Fuel costs

Fuel costs for wind, wave, geothermal, and solar installations are zero The term ‘reference price’ is used in this chapter to denote energy prices calculated using standard procedures, with defined interest rates These must be distinguished from prices relevant to particular states, which use appropriate levels of interest rate and repayment period; these are given the generic name ‘national prices’

2.15.2.1.3 Net present value

A number of financial parameters are used when evaluating the viability of wind energy projects The net present value (NPV) is [1]

the net present worth of a time series of cash flows, both incoming and outgoing NPV is a central tool in discounted cash flow (DCF) analysis, and is a standard method for using the time value of money to appraise long-term projects Used for capital budgeting, and widely throughout economics, finance, and accounting, it measures the excess or shortfall of cash flows, in present value terms, once financing charges are met

The NPV is calculated by summing the yearly cash flows that have been discounted by an appropriate discount rate That rate may be set by government – if a wind project is a public sector initiative – or by the individual developer Public sector projects tend

to use lower rates – 5% or 6%, say – and private sector developments usually use rates in the range 8–10%

2.15.2.1.4 Payback period

When calculating NPVs, the first term in the time series – in the case of a wind project – is the outlay for the capital cost of the plant That has a negative value and the remuneration from the electricity sales minus the provisions for operation and maintenance charges and other outgoings generally has a positive value When the sum of these positive monies equals the initial capital outlay,

this defines the ‘payback period’ ‘Simple payback’ is calculated in a similar way, but no discount rate is applied to the summation of the yearly cash flows and so it is invariably less

2.15.2.1.5 Internal rate of return

The internal rate of return (IRR) of an investment is the interest rate at which the NPV of costs (negative cash flows) of the investment equals the NPV of the benefits (positive cash flows) of the investment

IRRs are commonly used to evaluate the desirability of investments or projects The higher a project’s IRR, the more desirable it is

to undertake the project Assuming all other factors are equal among the various projects, the project with the highest IRR would probably be considered the best and undertaken first [2]

2.15.2.2 Price Calculation Methods

The basic procedures for setting selling prices for electricity are set out in standard texts [3] The first step is to calculate the annual capital charge, which depends on the project interest rate, or ‘test discount rate’ and repayment period An ‘annual charge rate’ is used, which expresses the fraction of capital cost that needs to be charged each year in order to yield the required rate of return over the specified period

The annual capital charge includes capital depreciation and interest charges and is divided by the annual energy output to yield the capital element of energy price The energy output of wind plant is primarily dependent on the wind regime, that is, on its geographical location, and on the performance of the wind turbines

Institutional factors arguably account for most of the apparent variations in quoted wind energy generation costs These factors may also influence the exact makeup of capital and operating costs In Denmark, for example, the costs of grid reinforcement for wind installations have not always been charged to developers Similarly, utilities in Denmark and elsewhere may not always charge their overheads to ‘operating costs’, whereas in Britain, by contrast – where private developers undertake all wind developments – all costs are included

2.15.2.3 Recommended Practices

The calculation of wind energy generation costs follows procedures, which are reasonably standardized across the power industry The International Energy Agency (IEA) has published guidelines in the form of a ‘Recommend Practice’ [4] for wind energy, and these are similar to those used for other renewables and for thermal plants The IEA document advocates the use of ‘real’, that is, net

of inflation, interest rates – more accurately, test discount rates – for the calculations, which is also common practice

The following items are included in energy price calculations:

• Planning costs

• Capital cost of plant

• Construction costs

• Interest during construction

• Land costs (either as part of the capital or as annual leasing payments)

• Fuel costs – zero for renewable energy plants

• Operating costs (O&M), including labor, materials, rents, taxes, and insurance

2.15.2.5 Amortization Periods

Amortization and depreciation periods also vary, and are not necessarily as long as the life of the plant This is rarely used outside the public sector The IEA Recommended Practice notes that “20 years is commonly used for proven grid connected wind turbines” and is used in this chapter as a default value

Amortization period (years)

2.15.2.5.1 Influence of interest rates and repayment periods

National institutional factors have a major influence on the financing terms for borrowing money and on investors’ expectations for the return on the equity they put into a project In some places, all the investment is provided by the state, or by nationalized industries, and so the equity contribution is zero Before privatization of the electricity industry in the United Kingdom, the test discount rate was set by the Treasury and was 8% in 1990 In Denmark today, utilities almost invariably use ‘public sector’ test discount rates, typically 5% or 6% In Britain and the United States today there are no fixed criteria and project developers use criteria that tend to be strongly influenced by the financiers The overall interest rate is dependent on the relative proportions of debt and equity and the appropriate interest rates; most tend to be in the range 8–11%

The other parameter that strongly influences generation costs is the repayment period The longer this is, the lower the annual payment to cover depreciation and interest and hence the lower the generation cost In Denmark, this period often corresponds to the expected life of the project – 20–25 years is common In the private sector, depreciation periods also vary, they were generally in the region of 12–15 years in the early years of wind energy development, but increasing investor confidence means that finance can now be secured for up to 20 years in some instances

The ‘annual charge rate’ is the fraction of capital payable each year to cover repayments of the original investment plus interest, and depends on both interest rate and repayment period Typical values are shown in Table 1 Once the annual cost has been determined, the corresponding generating cost component is simply the annual cost divided by the annual energy generation Financing terms can have a significant impact on the ‘capital cost’ element of electricity-generating costs The most stringent criteria (bottom line of Table 1) mean that annual charges will be double those associated with more relaxed criteria (top line of table) If the capital cost element of the total generation cost is small (as in the case of gas-fired generation), changes in the financing terms will have very little impact on generating costs In the case of renewable energy technologies such as wind, wave, photovoltaics (PVs), and tidal, where capital costs form the largest element of generation cost, the impact will be much greater

The data shown in Figure 1 illustrate just how important interest rates are to capital-intensive electricity-generating technologies such as wind The estimates of electricity generation costs have been derived using the cost data listed in Table 2 Note that these

Table 1 Typical annual charge rates

Interest rate Repayment period

8 15 0.1168 Typical UK Non-Fossil Fuel Obligation criteria

10 20 0.1175 Widely used now that wind is well established

12 12 0.1614 For investments seen as more risky, for example, offshore wind

Figure 1 Gas and wind energy prices – influence of interest rates and repayment periods

Table 2 Data used to illustrate effects of interest rates and repayment periods

Capital cost, $ kW−1 1000 724 Build time, yr 0.5 1 Load factor, % 0.26 0.8 Fuel cost, $ MWh−1 0 33O&M cost, ECU MWh−1 10 6

Table 3 UK Renewable energy prices

Technology

NFFO5 price (£ MWh−1)

August 2006 price (£ MWh−1) Landfill gas

Energy from waste Hydro

Wind projects > 2.3 MW

27.3 24.3 40.8 28.8

108.3 54.8 98.0 102.3

data are purely for illustrative purposes Whereas the spread of prices from gas-fired generation is only about $10 MWh−1 (from a 10-year amortization period and 10% interest rate to 25 years amortization and 5% interest rate), the corresponding spread for wind energy is about $42 MWh−1 With a 20-year amortization period and 10% interest rate, wind is dearer than gas, but a change in the interest rate to 5% brings the prices into line Extending the amortization period to 25 years brings wind prices below gas prices It is assumed that gas prices remain constant in real terms over the period

Changes in national institutional frameworks illustrate the maxim “Prices are what you want them to be,” and price variations in recent years for renewable energy in the United Kingdom bear this out In the last round of contracts under the Non-Fossil Fuel Obligation in 1998, the average price for ‘large’ wind energy projects was £28.8 MWh−1, whereas the prices realized in the auction by the Non-Fossil Purchasing Agency in August 2006 was £102.3 MWh−1 Table 3 illustrates how dramatically headline prices for four technologies have changed; the 1998 prices have not been corrected for inflation but this would make little difference to the comparison Under the previous arrangements – the Non-Fossil Fuel Obligation – the prices bid by renewable generators were (assuming they were successful) the prices they were paid Under the new arrangements, prices are subject to negotiation between generators and suppliers and are a function of ‘supply and demand’ While the plant costs of renewable generation have not changed dramatically, the price paid, under the new arrangements, is now a complex amalgam of numerous different components The generators are paid less than the price in Table 3, but the supplier takes the risk that prices into the future may be less than the prices quoted here Further details of wind energy support mechanisms are discussed later It may be noted that national institutional factors are responsible for most of the apparent variations in renewable energy generation prices These influence the ‘cost of capital’ and depreciation periods – the latter are not necessarily the same as project lifetimes

2.15.3 Cost and Performance Issues

Wind turbine and wind farm costs are often quoted on the basis of a price per unit of installed capacity ($ kW−1), but such data can

be misleading as manufacturers have differing design philosophies – there is no fixed relationship between rotor size and rating

A 40 m machine, for example, may have a rating anywhere between 350 and 500 kW The price of a machine with a high rating, relative to its size, will therefore tend to appear low when compared with one that has a low rating for its size More reliable comparisons may be made by comparing prices on the basis of price per unit swept area ($ m−2) However, although this may be more rigorous, it is probably less readily understood and is used less often

2.15.3.1 Balance of Plant Costs

Balance of plant costs – the extra costs, additional to those of the wind turbines – add between 15% (onshore) and 100% (offshore) to wind turbine costs, depending on the number and size of machines in the wind farm, and the location The windiest onshore sites – on hilltop sites, often remote from a grid connection, or coastal locations where deep piling into silt is needed, tend to incur costs above average Similar considerations apply offshore, where sites in deep water and far from shore are the most expensive

Although wind turbine prices (in $ kW−1) may increase at the large size ranges, there are nevertheless sound reasons for pursuing the development of such machines A number of items in the ‘balance of plant’ costs decrease with size (in $ kW−1 terms) of machine and/or machine numbers such as:

Average machine price ($1996/kW) 5000

Table 4 Operational costs

Service contract $ kW−1 and $ MWh−1 both used Administration Cost basis varies, $ kW−1 common Insurance $ kW−1 more usual

Land rent 1–2% of revenue, if land not bought Local rates $ kW−1 more usual

Electricity usage Standard tariffs Reactive power Up to 0.4 kVArh

most of Europe, fell from around 38 electronic control unit (ECU) kW−1 yr−1 at the 200 kW size to around 15 ECU kW−1 yr−1 at

600 kW [5] (the ECU was slightly above parity with the US$ during this period)

Operational costs vary between countries and wind farms Some elements are fixed annual sums, so wind farms on high wind speed sites may have lower costs per unit of electricity generated Table 4 shows the main components and the usual basis of charging is denoted Several costs are size-dependent Total costs are in the range $32–60 kW−1 yr−1 onshore and $90–150 kW−1

offshore

Not all utilities charge for reactive power – and not all machines need it Land rent may be an explicit cost if a developer builds on land he does not own, but may not appear if the wind farm operator owns the land In the latter case, the cost of the land may be included in the overall capital cost, or the owner may simply receive remuneration from the overall profit

2.15.3.3 Size of Wind Farm

The size of a wind farm influences its cost, as large developments

• οften attract discounts from wind turbine manufacturers

• enable site infrastructure costs to be spread over a number of machines, reducing the unit cost

• enable more effective use of maintenance staff

2.15.3.4 Installed Costs and Wind Speeds

The attraction of hilly sites onshore and remote sites offshore is the higher wind speeds Developers can afford higher costs, if they get a higher yield Increasing the wind speed, for example, from 8 to 9 m s−1 at hub height will typically increase output from a wind turbine by 10% However, remote hilltop sites generally cost more to develop than flat, low sites The link between onshore installed costs and winds has been examined [5, 6] and it was found that installed costs in Britain increased by between 16% and 25% as the site wind speed increased from 7.5 to 9 m s−1 Another factor that influences this correlation is that tall towers are often used in places such as Germany to obtain higher wind speeds, but at increased turbine cost

2.15.4 Onshore Wind

2.15.4.1 Historical Cost and Performance Trends

The cost of wind energy plant fell substantially during the period from 1980 to 2004 Figure 2 shows the average worldwide selling price of wind turbines from the early days (1980) in California to around 1998 (when worldwide capacity was around 10 GW) [5]

Figure 2 Average price of wind turbines, as a function of worldwide capacity

Figure 3 Productivity of wind turbines in Denmark, 2005 Source of data: Danish Energy Agency (1999)

Presentation of the data in this way enables the ‘learning curve’ reduction to be derived (this is the reduction in cost that is achieved for every doubling of capacity) The data that are plotted suggest this ratio is about 15%, which is consistent with estimates derived

by other analyses

Prices in the 1980s were around $3000 kW−1, or more, and by 1998 they had come down by a factor of 3 During that period, the size of machines increased significantly – from around 55 kW to 1 MW or more – and manufacturers increased productivity substantially In 1992, for example, one of the major manufacturers employed over seven people per megawatt of capacity sold, but by 2001, only two people per megawatt were needed The energy productivity of wind turbines also increased during this period This was partly due to improved efficiency and availability, but also due to the fact that the larger machines were taller and so intercepted higher wind speeds This is illustrated in Figure 3, using data from the Danish Environment Ministry The small machines in 2005 delivered around 500 kWh m−2 of rotor area, or less, whereas the largest machines delivered over twice that amount A further factor that led to a rapid decline in electricity production costs was the lower operation and maintenance costs

With capital costs halving between 1985 and the end of the century, and productivity doubling, it may be expected that electricity production costs might fall by a factor of 4 This general trend has been confirmed by the Danish Energy Agency; they suggest that generation costs fell from 1.2 DKK kWh−1 in 1982 to around 0.3 DKK kWh−1 in 1998 (1 DKK1998 = $0.144) [7]

Shortly after the turn of the century, the downward trend in wind turbine and wind farm prices halted and prices moved upward,

as shown in Figure 4 This was partly due to significant increases in commodity prices and partly due to shortages of wind turbines Prices appear to have peaked in 2008, with wind farms averaging just under $2200 kW−1 and wind turbines at just under

$1600 kW−1 Although the prices may now be falling, based on data available to the autumn of 2009, it should be noted that a complete data set was not available for 2009 at the time the graph was compiled

2.15.4.2 Current Plant Costs

The price of modern turbines around 55–65 m in diameter, for onshore installations, is around $1500 kW−1 The ‘most economic size’ of machine has changed over the years and is still moving upward The larger the machines, the fewer are required for a given capacity This brings savings in site costs and in operation and maintenance costs, as noted earlier Overall, site costs add between 15% and 40% to wind turbine costs, depending on the number and size of machines in the wind farm, and the location Figure 5 shows a typical cost breakdown for a complete wind farm [8], which now (late 2009) costs around $2150 kW−1

An analysis of published data from about 30 wind farms around the world, which were completed between January and October 2009 with a total capacity of over 3000 MW, suggests that the average installed cost was $2150 kW−1, with a standard deviation of $466 kW−1 [9] An analysis by the Lawrence Berkeley Laboratory in the United States reached a very similar result – $2120 kW−1 [10]

Figure 4 Wind farm and turbine prices, 2004–09

Site mean wind at hub height (m s−1)

Consultancy Financial costs 1.2%

Turbine (ex works) 75.6%

Figure 5 Cost breakdown for an onshore wind farm

2.15.4.3 Current Electricity Generation Costs

Using estimates
1 standard deviation from the average installed cost, quoted in the previous paragraph, and rounding slightly, suggests that generation costs based on installed costs between $1700 and $2600 kW−1 should have a wide relevance

These estimates, which are shown in Figure 6, were derived using an 8% discount rate and a 20-year amortization period; operating costs have been set at $32 kW−1 yr−1 for the lower capital cost and $60 kW−1 yr−1 for the higher capital cost The link between wind speed and energy productivity has been established by examining the performance characteristics of a number of large wind turbines that are currently available Although there is not a unique link between wind speed and capacity factor, the spread is quite small All wind speeds refer to hub height The estimates suggest that generation costs at $2600 kW−1 range from just under $200 MWh−1 at 6 m s−1, falling to $87 MWh−1 at 9.5 m s−1 At $1700 kW−1, the corresponding range is $125 to $55 MWh−1, respectively

2.15.4.4 Small Wind Turbines

The discussion and analysis so far has related to wind turbines of 1 MW size and above, and to wind farms of greater capacity As with most technologies, economies of scale yield significant savings of installed costs, but these effects become progressively smaller

at the larger scales Conversely, below 1 MW (roughly), installed costs rise Although these higher costs (and lower energy yields) translate to higher electricity-generating costs, that is not necessarily a drawback as the price comparator is likely to be different Large wind farms compete with gas and coal-fired power stations, but small- and medium-sized wind turbines may be competing with expensive electricity from diesel generators on remote islands or perhaps on remote farms in the developed world There is such

a wide variety of applications for small wind systems that it is difficult to lay down guidelines as to what are the target electricity-generating costs

Figure 7 suggests that fully installed costs for small wind turbines range from around $8000 kW−1, for machines with a rating of around 1 kW, around $5500 kW−1 for a 10 kW machine, down to around $4000 kW−1 for a 100 kW machine [11] These data come from a recent generalized analysis, but the trends are similar to those from an earlier analysis for turbines, only, rather than installed costs shown in Figure 8 A very similar trend is evident in the earlier data, with prices for very small machines straddling around

$8000 kW−1, falling to around $2050 kW−1 at 10 kW size and $1560 kW−1 at 100 kW rating [12] At that time (1999), much more information on selling prices was available than at the present time; there are not enough data at the present time to enable the

Figure 6 Estimates of electricity generation costs from onshore wind turbines

Turbine rating (kW)

Figure 7 Small wind turbines: fully installed costs

Figure 8 Wind turbine prices, 1999

information to be updated The original turbine prices were in ECU, and in 1999, 1 ECU was roughly equal to $1.04 Figure 7 – for installed costs – and Figure 8 – for turbine prices only – both clearly illustrate that economies of scale are significant

2.15.4.4.1 Offshore wind

Offshore wind has the potential to deliver substantial quantities of energy, but it is more expensive than onshore wind Cost reductions may be expected as the technology is further developed

A number of factors combine to increase the cost of offshore wind farms above onshore costs:

• The need to ‘marinize’ the wind turbines, to protect them from the corrosive influence of salt spray These measures may add up to 20% to turbine costs

• The cost of the cable connection from the wind farm to the shore; this increases with the distance from the shore, and accounts for between 17% and 34% of the total cost

• More expensive foundations The cost increases with water depth and can account for up to 30% of the total cost

• Increased operation and maintenance costs, with a risk of lower availability due to reduced access to the wind turbines during bad weather

Foundation and grid connection costs are substantially more expensive when compared with onshore wind energy In the budgets for the first batch of large Danish offshore wind farms, from which Figure 9 is drawn, these items together account for around a third of the total cost (Onshore foundations are typically less than half this amount, whilst grid connection costs are frequently even lower.) This observation underscores the reasons for the interest in larger wind turbines and also for the enthusiasm for larger numbers of machines

2.15.4.5 Historical Price Trends

Table 5 summarizes the principal operational data for the early Danish wind farms at Vindeby and Tuno Knob [13], together with the pilot Dutch farm in the Ijsselmeer [14], and a later Swedish wind farm

Although the cost of the Vindeby wind farm was 85% higher than the cost of an onshore installation, the anticipated energy yield was 20% higher Concerns about low availability offshore – due to problems of access – have not generally been realized The costs of the early wind farms were significantly higher than those of the later installation, at Bockstigen in Sweden Just as with onshore wind farms, prices vary depending on the exact location, with distance from shore, seabed conditions, and water depth being key factors Another key determinant in offshore wind farm costs is likely to be the number of machines There is a trend toward larger wind farms than onshore, to spread the cost of offshore transport, cable connection, and operation and maintenance costs

Figure 9

Table 5

Cost Turbines Capacity Wind Output Location Date No./kW MW m s −1 GWh MECU ECU kW−1 Vindeby, DK 1991 11/450 4.95 7.9a 11.2 9.6 1939 Comparable onshore farm at that time 7.2a 10 5.3 1071

Foundations 19.8%

Electrics 6.9%

Grid to land 15.8%

Design, etc 7.9%

2.15.4.6 Current Installed Costs

The energy costs from offshore wind farms cannot be established with the same precision as those of onshore installations; fewer wind farms are being commissioned, and there is a wide spread of costs Whereas the installed costs for onshore wind farms fell steadily for many years as the industry matured, precisely the opposite has happened offshore The early offshore wind farms were built for around $1800–2250 kW−1, but some of the latest developments – under construction or planned – will cost over

$5000 kW−1, which is over twice the current price of onshore wind farms The higher cost is partially offset by higher energy yields,

as offshore winds are generally higher than those onshore, but generating costs are about twice those of onshore wind farms Generating costs are very sensitive to interest rates and capital repayment periods, however, and the high capital costs offshore mean that offshore wind farms are more ‘capital intensive’ than onshore wind farms Capital repayments offshore account for around 80% of generating costs

The costs of offshore wind farms rose sharply after the turn of the century, partly due to increases in commodity prices Figure 10 shows how prices have risen from $1600 kW−1 in 2000 to around $4000 kW−1 in 2009 The same graph also shows that the gap between offshore and onshore installed costs has widened in absolute terms; in relative terms, the ratio is still between 1.5 and 1.75,

although there are wide variations in current estimates of offshore installed costs Figure 10 also shows projected prices up to 2015, with prices remaining at roughly the same level

2.15.5 Analysis of Offshore Costs

In order to examine the reasons why offshore costs have increased so dramatically, it is instructive to compare current costs with those of the earlier wind farms The European Wind Energy Association’s ‘Wind Energy, the Facts’ includes a cost breakdown for the Danish wind farm at Horns Rev (completed in 2002), and this can be compared with the figures quoted in a recent British study by Ernst and Young (E&Y) [15] and with data for the Rodsand II project – see Table 6

The table shows that the increases in wind turbine prices have been one of the major influences that have pushed up total installed costs Current prices of turbines for onshore use are around $1500 kW−1 and the figure for Rodsand II (and other data) suggests that the additional costs of the adaptations needed for offshore use add around 30% or more to this figure There has been a modest increase in foundation costs since 2002, which suggests that more efficient methods of construction have been found that offset the increases in commodity costs It is not clear why the British estimates for machines and foundations, from Ernst and Young (E&Y), are higher than the Danish figure for Rodsand II The total cost of the latter does not include a grid connection cost, but even if an allowance is made for this ($750 kW−1, say), there is still a significant difference between the total installed costs

2.15.5.1 Operation and Maintenance Costs

Offshore operation and maintenance costs are, unsurprisingly, higher than onshore costs, but, as with capital costs, the exact scope

of published figures is not always clear There is less information available on offshore operation and maintenance costs, but Table 7 summarizes recent estimates and data The data include actual costs from the third year of operation at one of the early UK wind farms

With the exception of the last entry in Table 7, all the figures suggest that offshore operation and maintenance costs are in the range €10–21 MWh−1 ($15–31 MWh−1) The European Wind Energy Association’s Analysis includes data from 10 wind farms and all the costs lie within this range The costs are not substantially higher than those for onshore wind, probably due to the fact that offshore wind farms tend to be much larger and can therefore benefit from economies of scale Wind speeds also tend to be higher, which means that the fixed costs are spread over a greater number of electricity units

The report compiled by Ernst and Young for the British government, cited above, contains a detailed breakdown, and is shown in Table 8 It is possible that the discrepancy between these figures and the remainder is due to the fact that some of the other estimates

do not include all the items listed in this table A distinction must be drawn between costs associated with maintenance of the turbines and other costs, such as grid charges, insurance, lease, and decommissioning charges This latter group of costs can, in total, equate to a similar sum as the turbine maintenance costs

Table 6 Cost breakdown data for offshore wind farms

Source EWEA Rodsand II E&Y Component

Nysted (DK) 165 MW wind farm budget 13

European Wind Energy Association [8] 16

UK, Generic (Ernst and Young) [15] 30 100

Scale factor 1.8 1.6

0 20 40 60 80 100 Distance from shore (km)

Table 8 Operation and maintenance cost estimates for UK offshore wind farms

Cost Component (€ kW−1) $ MWh−1

Lease charges 5.5 2.6 Decommissioning 20 9.6

The tentative nature of the estimates should be noted Offshore failure rates are still a somewhat uncertain quantity and the consultant Garrad Hassan [18] has produced data showing that the operating cost estimates are critically sensitive to failure rates If these rise from 5 failures per turbine per year to 10, then operating costs would more than double

The first two British wind farms achieved almost identical availability figures during their first year of operation –84% Of the downtime at North Hoyle, 67% was due to the turbines, 12% due to construction activities, 5% due to scheduled maintenance, and 17% due to accessibility problems The chief sources of downtime were problems with the cable termination, a high voltage fault at the onshore end of the cable, generator faults, and instrumentation and other electrical faults

2.15.5.2 Water Depth and Distance from Shore

Ideally, offshore wind farms should be sited close to the shore and in fairly shallow waters However, this may not always be possible and attractions of going further offshore are usually that the wind speeds are higher However, the expense of building further offshore will inevitably be higher – due to the higher costs of the cable connection to the shore and to the higher transport costs Water depth usually increases with distance from the shore and this also pushes up costs, mainly due to the higher costs of the foundations

The way in which water depth and distance from the shore increases construction costs is illustrated in Figure 11 The reference wind farm is cited in water depths between 10 and 20 m, and not further than 10 km from the shore With the same water depth, the wind farm ‘scale factor’ is 1.18 at distances from the shore between 50 and 100 km – in other words, it will be 18% more expensive

If the distance from the coast does not exceed 10 km, then the scale factor with water depths between 40 and 50 m is 1.396 – in other words, it will be 39.6% more expensive At the extreme limits of the data that are plotted, a wind farm between 50 and 100 km from the shore, in water 40–50 m deep will be 65% more expensive than the reference installation

The ratios quoted come from a study by the European Environment Agency [19] and the UK Carbon Trust [20] has produced similar estimates, although the scale factors are slightly lower

2.15.6 Electricity-Generating Costs

The price range selected for the generation cost estimates shown in Figure 12 is $3800–4600 kW−1 As is the case onshore, the lower price level is likely to apply nearer to the shore, where wind speeds are comparatively modest The electricity price estimates have not been extended beyond 8 m s−1 for that reason and operation and maintenance costs have been set at $90 kW−1 The higher priced wind farms, by contrast, are less likely to be sited in regions with low wind speeds and so the starting point has been set at 7.5 m s−1 The corresponding operation and maintenance costs have been set at $150 kW−1 Based on these assumptions and assuming, as in

Figure 11 ‘Scale factors’ for wind farms at distances up to 100 km from the shore and water depths up to 50 m The scale factor is the ratio of the wind farm cost to the cost of a wind farm no further than 10 km from the shore and water no deeper than 10 m Source: European Environment Agency (2009) Europe’s onshore and offshore wind energy potential EEA Technical Report No 6/2009 http://www.eea.europa.eu/

Site mean wind at hub height (m s−1)

Figure 12 Estimates of offshore electricity-generating costs

the case of onshore wind, an 8% test discount rate and amortization over 20 years, generation costs, at $3800 kW−1 fall from

$296 MWh−1 at 6 m s−1 to $171 MWh−1 at 8 m s−1 With installed costs set at $4600 kW−1, generation costs at 8 m s−1 are around

$221 MWh−1 at 8 m s−1, falling to $156 MWh−1 at 10 m s−1

At the low end of the current range of generation costs, The Danish ‘Rodsand II’ wind farm will receive remuneration at around

$125 MWh−1, but in this case, the developer did not have to pay for the costs of the grid connection and the installed cost was just under $3150 kW−1 A levelized offshore electricity cost of $240 MWh−1 – almost double the Danish figure – was quoted in a study

by Ernst and Young for the UK government This assumed a construction cost of $5336 kW−1 and a rate of return on the project

of 10%

Most offshore wind tariffs pay for electricity at prices within the range of costs that have been discussed above, although there is a wide range of

structures Some tariff payments ‘step down’ after an initial period, others are linked to capital subsidies and others are linked to be market price of

electricity and/or ‘green certificates’

2.15.6.1 Generation Cost Comparisons

2.15.6.1.1 Key issues

It is unrealistic to discuss the price of electricity from wind energy in isolation – it needs to be set in context alongside prices for the conventional thermal sources and for other types of renewable energy This section examines typical performance and cost data for a number of electricity-generating technologies

The electricity generation prices from thermal plants vary widely, and, as with wind, no single figure can quantify the exact costs and performance of any technology There are national differences in the installed costs and, particularly, the case of renewable energy, in the availability of the energy sources There are, for example, no sources of geothermal heat that are sufficiently attractive for commercial electricity generation in the United Kingdom (although there are locations where the heat is used), so no installed costs are relevant In the case of wind and solar energy, the energy productivity – kWh kW−1 of plant – varies significantly Solar installations near to the equator may be expected to be more productive than those in, say, Sweden or New Zealand Wind energy variations are more diverse; the windiest regions of the world are in New Zealand, the British Isles, and Antarctica, while central Europe and many equatorial regions have low wind speeds

Table 9 summarizes the key parameters associated with fossil and renewable energy technologies and includes notes as to how these vary ‘Fuel cost’ is zero for most types of renewable energy but not for energy crops (where it is positive), nor for the waste-burning technologies (where it is negative) ‘Capacity factor’ has the usual definition of the ratio between the average output

Table 9 Indicative cost and performance data for large-scale renewable energy and thermal plant [21–24]

Capital cost O&M costs O&M Load factor Fuel price Technology ($ kW−1) ($ kW−1 yr −1) ($MWh) (%) ($ MWh−1)

Wind onshore Wind offshore Hydro large Solar thermal Solar PV Geothermal Coal FGD CCGT

0 50 100 150 200 250 300 Generation cost ($/MWh)

of the plant and the rated power (both in kW or MW) It must be emphasized that the costs quoted are intended to give an appreciation of possible range of levels, but do not attempt to encompass all possible projects Fuel prices in the table are based on average levels in the United States and the United Kingdom during 2008

With the renewable technologies listed (with the possible exception of geothermal), there is also a wide range of load factors and this means that there is a wide spread of electricity-generating costs In the particular case of wind energy, high installed costs, as noted earlier, tend to be linked with high load factors The windiest sites tend to be located in hilly, often remote, regions and this means that access can be difficult, which pushes up costs

2.15.6.2 Cost Comparisons – Wind and Other Plant

The data in Table 9 have been used as a guide to derive estimates of electricity-generating costs using common financing parameters (20-year life and 8% discount rate) Other sources, particularly Reference 24, have also been used and the data are compared in Figure 13 Appropriate allowances have been made for interest charges incurred during the construction period This varies from a low of 1 year for onshore wind to 6 years for nuclear

The cost comparisons suggest that large hydro and geothermal plants offer the cheapest renewable energy generation costs – about $50 MWh−1 – although there is a wide range of estimates in each case, taking the upper end of the range to $72 MWh−1 in the case of geothermal and $92 MWh−1 in the case of hydro The available resources in each case, however, are very site-specific and there are many regions of the world where neither can be exploited to any great extent Onshore wind energy, with a price range of

$60–110 MWh−1, can compete with both coal and gas at the upper end of their price ranges (around $100 MWh−1) This assumes a modest carbon cost of €30 tonne−1 of carbon dioxide; the competitive position of wind would clearly improve with higher carbon prices, even at the lower end of the price range

The solar technologies are both considerably more expensive than wind Solar thermal has an estimated price range of

$200 MWh−1(
$25 MWh−1) and for solar PV there is a very wide range of prices The California Energy Commission suggests a range of $138–639 MWh−1 [24] with an average of $262 MWh−1 Both these technologies are likely to be more attractive in remote off-grid areas where there is no competition from cheap fossil fuels and/or where the delivered costs of these fuels are much higher than the levels quoted here

Nuclear generation costs are still somewhat uncertain, but a number of analyses have appeared recently, suggesting generation costs in the range $79–99 MWh−1 This encompasses the range of estimates for wind but it can be argued that the latter technology involves less risk

2.15.6.3 Cost Comparisons on a Level Playing Field

Although generation costs are used to compare renewable energy and fossil generation, that process is not precise A ‘level playing field’ demands that allowances are made for various factors, some of which add value to renewables, some add cost to the fossil sources of generation, or to variable renewables The key issues that add or reduce the value of renewable energy, relative to the fossil sources of generation are:

• External costs These are costs attributable to an activity that are not borne by the party involved in that activity All electricity-generating technologies come with external costs, and those of the fossil sources of generation are due to the pollution that arises from their use, and from the impacts of global warming due to their CO2 emissions Economists argue that these costs should be added to the generating costs, and this is the thinking behind the proposals for carbon taxes The early thinking on this issue was that carbon taxes would add unacceptable increases to the price of electricity and so most governments give renewable energy sources a ‘bonus’ instead More recently, however, Emissions Trading Schemes have had a similar effect to a carbon tax although the ‘cost of carbon’ is generally less than the estimates that have come from detailed analyses of the external costs of the fossil sources of generation

Figure 13 Generation cost comparisons

• Embedded generation benefits acknowledge that many renewable energy sources are small-scale and connect into low-voltage distribution networks This means that losses in the electricity network may be reduced and, possibly, transmission and/or distribution network reinforcements deferred The calculation of these benefits is a complex issue and they vary both regionally and locally It is important to recognize, however, that concentrations of embedded generation can increase distribution losses in rural areas where demand is low and so should be avoided

• Extra balancing costs for variable generation apply especially to wind and wave energy and account needs to be taken of these 2.15.7 External Costs

Although there is general agreement as to the broad definition of external costs – costs attributable to an activity that are not borne

by the party involved in that activity – there are widespread variations in defining the boundaries There is an argument, for example, that a substantial proportion of Western defense budgets should be regarded as an ‘external cost’ of oil – for fairly obvious reasons External costs – or at least some elements – may be difficult to quantify, but they are real If the enormous costs of the cleanup operation after the Chernobyl nuclear disaster had been taken into account when the plant was constructed, it is unlikely it would have been built External costs – in the form of carbon prices under Emission Trading Schemes – seem set to play an increasing role in shaping future energy policy Governments around the world are recognizing the high costs to society of pollution and of global warming – and the electricity industry is a major contributor to these costs The task facing energy policy makers is how best to go about the job of reducing pollution in electricity generation when in most countries external costs are not reflected in the market price of the end product

If they were, fossil fuel technology and nuclear prices would rise, making renewable energy sources more competitive

2.15.7.1 Types of External Cost

Before looking more closely at the procedures available, a brief analysis of the makeup of external costs illustrates why there is such controversy about how to quantify them For simplification, they can be divided into three broad categories:

• Hidden costs borne by governments

• Costs of damage caused to health and the environment by emissions other than CO2

• The costs of global warming attributable to CO2 emissions

The first category includes the cost of regulatory bodies and pollution inspectorates (generally small) and the cost of energy industry subsidies and research and development programs These are larger In one of the first analyses of external costs, published by the European Commission in 1988, Hohmeyer [27] calculated that support to the German coal industry added DEM 0.002 kWh−1 ($0.0012 kWh−1) to the price of electricity He also assigned a cost of DEM 0.0235 kWh−1 ($0.014 kWh−1) for nuclear R&D, compared to around DEM 0.004 kWh−1 ($0.0024 kWh−1) for wind

The second category is costs due to emissions that cause damage to the environment or to people These make up a significant proportion of the external costs of power generation and include a wide variety of effects, including damage from acid rain and health damage from oxides of sulfide and nitrogen emitted from coal-fired power stations In a European Commission-funded study, ExterneE [28], the costs of damage to health were estimated by calculating the loss of earnings and costs of hospitalization of people susceptible to respiratory diseases That study considered the following issues:

• Smut deposition (local), acid rain damage (national)

• Obscuration of the sun by plumes, causing local nuisance and harm to trees and crops

• Noise – due to plant, coal handling, and so on

• Noise due to fuel delivery effects on human health

• Discharges into watercourses and to fisheries

• Plant accidents and their human cost

• Smells, oil spillages – cleanup costs

• Dust and fumes, ash disposal accidents

• Heavy metal depositions

• Upkeep of emergency evacuation measures (nuclear)

• Leakage from waste (nuclear)

Other costs included in the damage and health category are power industry accidents, whether they occur in coal mines, on offshore oil or gas rigs, or in nuclear plant The probability of a nuclear accident in Western Europe might be extremely low, but should a catastrophic failure occur, the costs would be undeniably huge Multiplication of a number close to zero (the probability of a nuclear accident) by a number close to infinity (the cost of such an accident) does not necessarily give a meaningful result

The third category is by far the largest: external costs due to greenhouse gas emissions that cause global warming – with all its associated effects This category accounts for some 40–90% of the hidden costs of electricity generation It is also the most contentious area of the external costs debate The range of estimates for the possible economic implications of global warming is