The potential for wind energy in Britain

The potential for wind energy in Britain Michael J. Grubb This paper discusses the prospects for the large-scale use of wind power for electricity supply in Britain. Recent economic advances in wind energy are outlined, and # is shown that on windy sites, currently-available machines are among the cheapest generating options. The results from detailed studies of wind energy resources, and of the long-term integration of wind power on the UK supply system, are then summarized. These studies are applied together in probabilistic projections of wind energy and power system costs. Results suggest that, siting permitting, the economic long-term contribution of wind energy in Britain is likely to lie in the range of 20-50% of system demand. The most critical questions for wind development now relate to institutional issues and the desirability of the source on such scales. Keywords:Wind

energy; Economics; Uncertainty

The belief that renewable sources of electricity cannot be taken seriously as major supply options is widely held among energy specialists in the UK. It stems from three deeply held assumptions: that the exploitable resources are too small to be significant; that renewable sources are too expensive to consider seriously; and that electricity supply systems cannot extract much of their energy from them because of the intermittent nature of renewable sources, most Michael Grubb is with the Department of Electrical Engineering, Imperial College, London SW7 2BT, UK. The work described was carried out during four years at the University of Cambridge Energy Research Group. Technical support from the University, and financial support from the Science and Engineering Research Council, are gratefully acknowledged. The author would like to thank Nigel Evans (Caminus) and Jim Halliday (Rutherford-Appleton Energy Research Group) for extensive help and discussion; and the following for their helpful comments and access to relevant data: Bob Lowe (formerly Open University); Dr Page, Dr Birch, Dr Taylor (Energy Technology Support Unit, Harwell); David Moore, John Holt, David Milborrow and Toby Manning (CEGB); Dr Jean Palutikof (University of East Anglia Climatic Research Unit).

594

of which fluctuate with the natural cycles of wind, wave, tide or sun. This paper reports detailed studies on each of these aspects, as applied in particular to assessing the economic prospects for onshore wind energy in Britain. The results reinforce the conclusions of other recent work in suggesting that for this source at least, all three common assumptions are open to serious question. Recent developments in wind energy technology are summarized first, as it is rapid technological change which has led to such interest. The paper then discusses the size and characteristics of the wind energy resource, and examines the value of wind power in the supply system using the results of detailed modelling studies. For the body of the paper, the resource and system modelling work are drawn together in a probabilistic analysis of the economic prospects for wind energy. The final section discusses the policy implications of the results.

Recent progress in wind energy In the last few years, the technology for converting wind energy to electricity has developed at a remarkable pace. At the beginning of the decade, it showed no particular promise as a generating option. Yet it now forms a substantial part of generating plans in some areas I and already supports an industry with a turnover of several hundred million dollars a year. Within the last three years, over 1 100 MW of wind capacity has been installed. 2 The recent evolution of wind energy has occurred in three distinct phases. The period 1976-81 saw a range of government programmes aimed at developing very large turbines and understanding the underlying technology. While much was learnt, results proved somewhat disappointing, with most projects running into substantial technical problems and high costs. The second phase, from 1982-85, was dominated by the development of a market for small and

0301-4215/88/060594-14503.00 O 1988 Butterworth & Co (Publishers) Ltd

Wind energy in Britain

medium sized machines in the USA. The 1978 Public Utilities Regulation and Pricing Act ( P U R P A ) required utilities to buy privately-generated electricity at a rate reflecting its real worth to the utility. Together with generous Federal and State tax incentives in the early 1980s, this made wind energy in some areas - particularly California - an attractive private investment even at the then high costs. Windpower installation rates in California rose from 10 MW in 1981 to 60 MW in 1982, and trebled in 1983 and again in 1984 to a level of 400 MW/year. The cumulative investment in Californian wind energy totals about $2 000 million, and the value of the energy generated is put at $100 million/year. With this market base, several companies invested heavily in wind energy technology and gained rapid experience. The results have been: 4 •

•

•

doubling in the mean size of commercial units, from 52 MW to 108 MW and units of 200-300 MW are now common; major improvements in machine performance, resulting in greatly increased energy capture and reliability; and rapid fall in capital costs, from an average of US$3 100/kW in 1981 to an estimated US$1 250/ kW average in 1986.

The third phase, from late 1985, is witnessing two parallel developments. First, the technological lessons are being applied to larger d e v e l o p m e n t machines of 1--2 MW, often with state or utility backing, as utilities become increasingly aware of recent progress. Second, the removal of tax credits and the fall in oil prices greatly tightened the market at a time when several large companies have put substantial capital into new machines. The resulting pressure nearly bankrupt some new companies as further cost and price cuts ensued, this time driven by market pressure as much as technological change. A recent review of 13 machines in the range 150-30(I kW showed an average machine price of UK£501/ kW (1986 prices). 5 Installation costs would typically add 10-40% to the machine cost, and larger machines have not yet come down to such low levels. Yet two U K companies now estimate that they could meet a large order for 1 MW-size turbines for around £800/kW, fully installed, an estimate which now seems very plausible .6 The cost of energy from such machines depends on siting and a range of other uncertain factors. If placed at a reasonably windy site, as might be found near much of the west coast of the U K , modern wind turbines should produce at least 3 MWh/year/kW of

ENERGY POLICY December 1988

capacity. 7 On fairly central assumptions, s £800/kW then corresponds to an energy cost of 3.0p/kWh. Siting at the most windy sites, such as hills near the cost, could easily reduce this by 20-40%. This compares with C E G B estimates of about 3p/kWh for new nuclear stations and 3-4p/kWh for coal (depending on coal price projections). On a c o s t - o f - e n e r g y c o m p a r i s o n , t h e r e f o r e , wind machines placed at good sites offer probably the cheapest generating plant available in the UK; and the technology is continuing to improve rapidly. Yet how valid is a simple cost-of-energy comparison? How valuable is wind energy to the power system? And how much wind energy is available at a reasonably attractive cost? It is the answers to these questions that will determine the real significance or otherwise of the developments in wind energy technology, and it is to this that we now turn.

W i n d energy resources in the U K A baseline estimate of physical wind resources can be made without difficulty. The average annual energy available in the wind at the height of large wind turbines is typically about 5 MWh/square metre of swept area. Simulations of large arrays of wind turbines have shown that if standard machines are separated by a distance of about 10 times their rotor diameters, interference between machines in an array is reduced to acceptable levels, '~ with the energy extracted being largely replaced from the upper atmosphere. If arrays at such a 10-diameter spacing could be placed over an area the size of the mainland of the UK, the energy available would then be around 8 600 TWh/year, or some 30 times current U K electricity demand. Only a small fraction of this could ever be tapped. Unfortunately it is impossible to translate this physical resource to any meaningful estimate of useable energy. Such a figure depends not only on the assumed machine height and conversion efficiency, and upon the pattern of machine siting and windspeed profile - which are themselves quite uncertain; m but dominant of these is the assumed availability of sites. Many people, pointing to the size of the larger wind turbines (typically 30-50 m in height with blades of a similar diameter), and the intricacies of local planning procedures, believe that local objections to siting will limit the practical resource to a small fraction of national demand. Others express the view that wind turbines are greatly preferable to coal or nuclear generation, and can be made quite attractive. Given the minimum

595

Wind energy in Britain

spacing of at least 250 m, they believe that wind turbines could be placed at many sites, providing that basic first order siting restrictions are met - no machines too close to houses or in national parks, none near T V or radio transmitters, and none in difficult or dangerous locations such as airports - the resource would then be substantial. The E E C study of wind energy resources estimates the U K resource after first order siting restrictions and primary conversion losses to be 1 760 TWh/year, some six times national demand. 11 A n o t h e r study, assuming larger first order restrictions and smaller machines, and including second order losses, suggests a figure of around 700 TWh/year for the mainland UK.~2 There is little objective evidence on which to choose between these extremes. Objections have been raised to some recent windfarms in California, but not such as to significantly impede development. California has much more open space, but then development has been much more chaotic and unsightly than it need have been. Public opinion surveys offer some encouragement. A particularly detailed survey of attitudes in Sweden, based on photographs and film of both actual wind turbines and simulations, found that 70% of those within the energy industries believed that public opposition would be a serious obstacle to windpower development, while only 20% of the general public thought it would be. In further studies, 13% of respondents thought visual impact to be the most serious problem with wind energy more technical issues such as unpredictability and cost were cited more frequently. 14 Of course, opinion surveys on hypothetical developments are of limited value, and attitudes may vary between countries, but in the absence of better evidence such results do caution against assuming that large-scale wind energy would be publicly unacceptable. At present, the question 'how much wind energy is practical?' is thus unanswerable, as it depends entirely on subjective judgements which are known to differ by at least two orders of magnitude between different commentators. A more useful question is 'what would be required to extract a certain amount of wind energy?' In particular, we may ask, for a given contribution: • • •

How many machines of what size would be required? How much area would they be spread over? How much land would be used by them?

To which the answer follows that to supply one third of current U K electricity demand from onshore windpower would require:

596

•

•

•

About 15 000-23 000 machines 60 m in height (to the rotor hub), depending on siting pattern or twice as many, 45 m high. To prevent excessive interference, they would have to be spread over 3-7% of the U K mainland. The land occupied by the machines would be 1-2% of the array area, which makes the total land use comparable with conventional sources.

These figures are discussed in detail and compared with other studies elsewhere. ]5

Characteristics of wind energy Siting permitting, the wind resource is clearly large. Yet how valuable is wind energy to the power system, and how much could reasonably be used? This will depend not only on the system costs and structure, but on the distribution of windpower output, its variability, and its unpredictability. The output from any particular wind turbine may be very variable, frequently at zero or near maximum, and sometimes fluctuating rapidly at intermediate power levels. The presence of gusts at various timescales makes the output very unpredictable. Localized wind energy is thus not an easy source to integrate on small power systems. The geographical diversity available on a larger system can result in very different characteristics. Windspeeds between the east and west coast, and between southern England and northern Scotland, are not well correlated. Distributed wind energy thus tends to be much more reliable. In addition, fluctuations on the timescale of a minute or two are independent between machines 1 km or more apart, and even hourly fluctuations will only be correlated for machines within 50 km or so of each other. Dispersed wind energy is therefore much less variable, and much more predictable, than that from a single site. To analyse the effects of such diversity, nine years of hourly windspeed data from 25 sites throughout the U K were obtained. Using the machine conversion characteristic shown in Figure 1, this was analysed as described elsewhere 17 to simulate the output which would be obtained from wind energy in different regions. The probability of obtaining a given level of power output from diverse wind energy, with turbines distributed equally between different regions in the UK, is shown for winter and summer respectively in Figure 2. The output is well spread across the full power range, especially in winter when the probability of obtaining negligible windpower is slight. In

ENERGY POLICY December 1988

Wind energy in Britain

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summer, the chance o f being without wind energy is higher, but the probability of obtaining nearmaximum output - which might result in excess power - is also much reduced. The corresponding rate of power variation from such distributed wind energy is illustrated in Figure 3, in terms of the frequency with which wind energy varies across a given power level. The average timescale of fluctuation is 1-2 days. Windpower variability is thus comparable to the daily variation of electricity demand itself, suggesting that even substantial capacities should have a fairly modest impact on power system dynamics. The predictability of windpower cannot be treated analytically in the same manner, since it depends on the prediction methods used. The simplest method is the 'persistence' forecast, which just assumes that the current windspeed persists in the future. On this basis, the one hour 'forecast' produces an average (standard deviation) error of 0.07 times the wind capacity; at 10 hours ahead this figure rises to 0.2. In practice, the monitoring of weather patterns, particularly with the aid of satellite observations, should lead to very much better prediction than this. It is

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Figure 2. Distribution of output from nationally-dispersed

wind energy.

E N E R G Y POLICY December 1988

unlikely that dispersed wind energy on hourly timescales will be much more difficult to predict than electricity demand, though prediction for thermal plant scheduling - often required a day in advance may be more difficult.

The value of wind energy on power systems These observations suggest that even high capacities of wind energy should not impose undue operational difficulties on large power systems when the resources are widely distributed. Yet even then, wind power characteristics are very different from those of conventional power plants. To analyse wind energy economics, a detailed probabilistic model of the C E G B power system was therefore developed the probabilistic electricity generation analysis (PEGA) model which is described fully elsewhere.l'~ Features include: • • •

• •

analysis of standard capital and operating costs; a statistical assessment of system reliability; analysis of intermittent sources by geographical region, including an estimate of transmission costs and losses; calculation of thermal plant startup requirements; and estimation of operational uncertainties and the corresponding requirements for system reserve.

With such a model it is possible to address the question 'how valuable is wind energy to the power system?' Naturally the answer depends upon system costs and conditions. In the following discussion the values used are the central (modal) values of the probabilistic analysis described later in the paper (see Tables 1, 2 and 3). Short-run value

The short-run value of wind energy is easily calculated in terms of simple operational savings. For wind energy (from 16 sites dispersed over England and Wales) added to the current C E G B system 597

Wind energy in Britain Table 1. Input data assumptions for uncertain variables.

Total WECS cost at reference site, £/kW a Total restrictions on WECS siting (% physical sites excluded) Windspeed prediction error in given region (relative to persistence forecast)~ Electric demand change (× 71-79 levels) Thermal nuclear fuel cost, p/kWh Thermal nuclear capital cost, £/kW Thermal nuclear average availability c Coal fuel cost, £/TJ Coal capital cost, £/kW Coal plant average availability c Peaking turbine fuel cost, £/TJ Peaking turbine capital cost, £/kW Thermal turbine startup (× capcst× 10 o)

Minimum

Mode

Maximum

450 72 0.0 0.65 0.5 1100 0.55 1100 850 0.64 3500 150 5

700 86 0.5 1.15 0.9 1600 0.70 2100 1050 0.72 5500 300 20

950 100 1.0 2.00 2.0 2500 0.82 5000 1400 0.82 7500 450 50

Notes: aWECS = wind energy conversion systems. For a discussion of WECS costs see main text. Machine conversion characteristics are as shown in Figure 1. Average machine hub-height is assumed to be 60 m, with a reference site mean speed of 8 m/seconds at this height. The stated costs are broken down evenly between power-related and rotor-related components in estimating costs at other sites (see text). bStandard deviation of windspeed prediction errors, relative to persistence forecasting (in which the current value is used as the prediction speed). Prediction errors are assumed to be only partially correlated between regions (see Table 6). ~Outage of thermal units is assumed to divide equally between forced and planned causes.

Table 2. Regionally-specified wind and transmission data.

OEM costs, %capital/year Technical availability Transmission efficiency (tel. thermal) Power sunk locally (× national demand) Transmission line requirements for remaining power, km

Region Ia

2b

3~

4d

5e

6f

1.7 0.88 0.96 0.04 600

1.4 0.90 0.98 0.07 400

1.2 0.91 0.99 0.16 300

1.2 0.91 0.99 0.18 250

1.0 0.93 1.01 0.30 80

1.0 0.93 1.01 0.15 250

al = north Scotland; b2 = south Scotland; c3 = north England; d4 = Wales and west Midlands; ~5 = south-east and Midlands; f6 = south-west Engl.-"nd.

structure, the savings are shown in Figure 4 as a function of installed wind capacity together with the corresponding marginal value of the wind energy. It may be seen that the marginal value declines slowly with increasing penetration up to levels at which the wind is supplying about 35% of demand, after which it falls more sharply. The decline in marginal value is due to many factors. As the wind input grows, it displaces increasingly lower fuel-cost plant - more efficient coal units, and then nuclear-generated electricity. In addition the system penalties associated with windpower fluctuations and unpredictability increase. These dynamic costs can total over £500 million/ year, but this is still small relative to total system costs: as a fraction of the gross savings from wind energy, the operational penalties rise from zero at small wind capacities, when fluctuations are negligi-

598

0.05 25 18 10 0,2 0.8 0.35 0.25

Capital effects and longer-term savings This discussion ignores any capital savings from wind energy in the longer term. These can arise in several ways: because no generating plant is 100% reliable, there is always a finite risk of system failure, and a large margin of plant capacity over maximum demand needs to be maintained. Wind energy 2000

Marginal fuel savings

years p/kW/krn rotor-diameters (1-hour forecasts) (10-hour forecasts) (nuclear and baseload coal) (cycling coal units)

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Table 3. Other significant input data,

Discount rate WECS lifetime Transmission line capital cost Minimum wind turbing spacing Correlation coefficient of wind prediction errors between regions Thermal part-loading limit (as fraction of capacity)

ble compared with load, to about 5% at 25% (energy) penetration, reaching 10% only at very high wind energy levels, z°

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Figure 4. Fuel savings from wind energy. ENERGY POLICY December 1988

Wind energy in Britain

reduces the risk of failure and allows the margin to be reduced. 2~ In addition, as the wind capacity increases, the optimal thermal plant mix shifts increasingly away from capital-intensive baseload sources: from nuclear to coal and from coal to peaking turbines. This can result in substantial capital savings. It occurs because wind energy reduces the time for which thermal units are required to operate, and thereby makes capitalintensive plant less valuable relative to fuel-intensive investments. It is difficult to quantify the real value of these effects because they depend upon detailed assumptions about system development. However, it is possible to calculate a long-run value as the gross savings available from wind energy, assuming the background thermal system to be fully optimized. 22 Figure 5 shows this long-run value, as a function of the installed wind capacity (in this case, the system includes Scottish demand and wind resources, for reasons addressed below, and all parameters including demand escalation assume the modal values of the probabilistic analysis described later). The corresponding changes in system structure and costs which occur as wind capacity increases are illustrated in Figures 6 and 7. For the costs chosen, nuclear power dominates over coal on the optimal system, but this does not make wind energy worthless, as is often assumed. Rather, the major component of savings arises from the fact that less nuclear plant is required on the optimal system when wind energy is present, and this shows itself as capital rather than fuel savings. For comparison, the marginal value of wind when nuclear power is not available is also shown on Figure 5. On the actual system, the nuclear capacity is likely to be limited by many factors, and the value of windpower would lie between the two curves.

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The impact of the 'capacity credit' at small penetrations is readily apparent: it allows the total thermal capacity to be reduced, and initially makes energy from the wind as valuable as that from any competing baseload source. With this, the long-run value of wind energy is substantially greater than the value of fuel savings alone on the current C E G B system, even when nuclear power is unconstrained. Beyond this region, when all wind energy requires 'backup', the long-run savings can still be substantial. Nevertheless, the marginal value does decline steadily with increasing wind capacity, and it is this decline which may be central to determine the likely economic contribution of wind energy. The oft-cited 'limit' to absorbing wind energy on the system, insofar as it exists, can be measured by the rapid decline in value once substantial amounts of wind energy start to be discarded. This does not occur until wind is contributing 50% or more of the system energy.

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Figure 5. Long-run marginal value of wind power, ENERGY POLICY December 1988

Figure 7. Optimal plant mix and savings for increasing wind capacity on system with no nuclear power. 599

Wind energy in Britain Understanding the role o f wind energy on p o w e r systems

Underlying these results there is one primary theme which must be grasped if the economic role of wind energy on large power systems is to be understood. That is the fact that extreme conditions, which can excite such concern, are of little economic relevance. For example, some wind energy may be discarded as soon as the installed wind capacity (after availability and transmission losses) equals the minimum load less minimum thermal output; this may be just a few GW. But for widely distributed wind energy, occasions with near maximum windpower are very rare, and a combination of this with very low demand is so infrequent as to be economically irrelevant. Wind power spillage is only significant when it occurs for perhaps 5°/'0 to 10% of the time, which requires much higher wind penetrations. At the opposite end of the spectrum, combinations of low windpower and high demand will certainly occur, but they are best met with low capital cost peaking turbinesfl3 Similarly, there certainly can be occasions when the wind input falls sharply while the demand is rising, and if this is not well predicted both storage units and expensive gas turbines may need to be started up rapidly solely for operational reasons. But wind diversity sets limits to how frequently and severely this can occur, and the overall economic impact of such emergency cases is small. Such adverse conditions are only relevant when they occur for a significant fraction of the time. For a given wind capacity, the primary factor which determines the frequency of such conditions is the diversity of the resource, and hence diversity emerges as an important factor. For this reason the discussion of the long-run value of windpower includes the Scottish resource and assumes a strong connection with Scotland. The sensitivity of these results to other assumed system characteristics is examined elsewherefl4 The conclusion that small amounts of wind power may be judged directly against the energy cost of competing options proves to be largely independent of finer details. As the wind capacity increases, the results can become sensitive to detailed assumptions about thermal plant and wind characteristics. However, within the range of likely values for the main system parameters, the broad results described apply fairly generally, given input costs and wind diversity. What consequences does this have for practical power system investment decisions? While wind capacity remains small there is direct comparison between wind energy and other baseload sources.

600

Given the wind energy costs outlined earlier, this implies that wind energy at very good sites is probably the most economic generating plant currently available. As the capacity of wind increases, the choice is increasingly complex: some backup plant will be required, and the value of marginal fuel savings is reduced. These factors steadily reduce the value of wind energy, so that cheaper machines will be required to make higher penetrations economic. Yet for a system on the scale of the CEGB, more fundamental limits to the integration of wind energy only become significant when wind is already contributing perhaps half the energy on the system.

Probabilistic futures analysis Method and assumptions

From the preceding discussion, it is clear that wind energy conversion systems (WECS) at good sites may be a competitive power source. If costs are low enough, substantial capacities could be accommodated. To investigate how important wind energy may be, the resource analysis can be brought together with power system modelling to find the least-cost mix for a given set of cost conditions. Though any such analysis of the possible long-term contribution is subject to enormous uncertainty, all projections of power system investments are concerned with timescales of 40 years or more, and it is important to know the possible place of wind energy. The rest of this paper therefore describes a probabilistic futures analysis (PFA) of wind energy on the UK supply system. PFA, as used in previous studies of electricity economics by Evans, 25 aims to incorporate future uncertainties explicitly. To achieve this, important but uncertain input parameters arc described as uncertain ranges - probability distributions of possible values. The analysis proceeds by repeatedly running the model with different input values selected from the ranges given, as in a Monte Carlo analysis. 26 In effect, the model is used to scan a wide range of possible 'sampled futures' obtained from different combinations of possible inputs. A picture of possible outcomes is thus built up. In this application, all uncertain variables were described by triangular probability distributions, defined by a minimum value A, mode B and m a x i m u m C; this may be simply d e n o t e d . In a real power system, many noneconomic factors constrain system development, but attempting to guess at such constraints in the long term can lead to hopelessly complex and subjective

ENERGY POLICY December 1988

Wind energy in Britain

limitations on model operation. Full optimization was therefore adopted as a modelling ideal which is the most free from arbitrary assumptions about constraints, and which gives the clearest indication of the direction in which a least-cost system should develop; results need to be interpreted in this light. The analysis was carried out for systems with and without nuclear power available. Broadly, input costs and characteristics were estimated as mean values over the period 2010--2030: thermal plant capital costs are assumed to remain around current levels, but in the majority of cases fuel costs rise slightly and wind energy costs fall a little further. The uncertain ranges specified are shown in Table 1, with other data shown in Tables 2 and 3. Wind energy costs may vary substantially between sites, according to windspeed and location. A range of data was used to estimate the profile of wind energy resources by region and by site energy density, in a study reported elsewhere. 27 Even given the resource profile, there are significant analytic problems. The lower energy density of less windy sites will be partially offset by the fact that machines can be given a lower rated power for the same swept area, saving on many components; it should also be possible to lighten and enlarge the rotor at little cost, as compared with more stormy sites. T h e r e f o r e wind costs across different sites will be neither fixed £/kW nor fixed £/m 2, but somewhere between the two. This fact can be captured by dividing total costs between notional 'rotor-arearelated' and 'power-related' components. A 50:50 breakdown at the reference site (8 m/second mean windspeed at 60 In height) was assumed. 2~ In addition, transmission costs and losses, maintenance costs and machine reliability will depend on the area of construction (remote areas lose more power, and breakdowns take longer and cost more

,s

10

Table 4. Mean results of probabilistic futures analysis. Nuclear unconstrained M e a n W E C S capacity, G W M e a n d e l i v e r e d wind energy, % demand M e a n benefit, £million/year

Without nuclear

33.1

46.7

29.7 924

40.1 1884

to repair) and are therefore defined by region (Table

3).29

Second order siting restrictions, arising principally from objections to visual intrusion of windpower, were assumed to exclude < 3 0 , 6 5 , 1 0 0 > % of the sites left after first order constraints, giving the total restrictions shown in Table 3. They were applied equally to all regions and site types (for siting purposes, the lower population density of remote areas may be offset by greater scenic value). The assumed minimum WECS spacing of 10 rotor diameters was retained. Results General economic results. Figure 8 shows the results of the probabilistic analysis when nuclear power is unconstrained. The histograms show the distribution over the 50 sampled futures of: the installed (optimal) WECS capacity; the wind energy penetration, and the net yearly benefit from the WECS (defined as the difference between minimum system costs with and without WECS available). Figure 9 shows the corresponding results for the non-nuclear case (mean values are shown in Table 4). Even in the presence of unconstrained nuclear power, wind energy on average contributes nearly 30% of energy on the optimum system, while the mean contribution over the 50 non-nuclear futures is 40%. The results thus suggest that wind energy is likely to be a major economic source. The distribution of results shown in Figures 8 and 9 suggest that although the uncertainties do strongly

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Figure 8. Optimal wind energy contribution and net savings with unconstrained nuclear power: distribution over 50 sampled futures. E N E R G Y P O L I C Y December 1988

0

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40

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Wind energy (% systemdemand)

0

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3

4

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Net yearly benefit (£O00m/year)

Figure 9. Optimal wind energy contribution and net savigns with no nuclear power: distribution over 50 sampled futures. 601

Wind energy in Britain

affect the amount of economic wind energy, this overall conclusion is robust against a wide range of uncertainties. Naturally, the results reflect the assumptions and limitations of the study, but it is very difficult to escape the conclusion that wind energy is a resource of great importance, likely to be worth at least several hundred million pounds a year.

Sensitivity analysis. Figures 8 and 9 show that, despite the wide range of uncertainties, the optimal wind energy contributions cluster in the range 15-40% on the nuclear system, and 25-55% on the non-nuclear system. A significant amount of windpower is economic in all cases. This is because, unless siting restrictions are extremely severe, such amounts can be deployed at high windspeed sites and so combine low costs with a relatively high value to the system (with some capacity credit and negligible operating penalty). Under these conditions, as noted, current machines are economic or close to it, and in the study the economic position of windpower is not envisaged to worsen. The conclusion that at least 10-20% wind contributions will be economic is thus not sensitive to the uncertainties in future costs. In addition, the partial ranked correlation coefficient of outputs with respect to the uncertain inputs were derived. 3° These indicate the relative importance of the uncertain variables in determining the result. Those significant at the 95% confidence level are shown in Table 5. Measured against net benefit, the most important uncertainties emerge as plant capital costs (especially nuclear), baseload fuel costs (nuclear or coal respectively) and WECS siting restrictions. Electricity demand escalation and WECS costs feature, but not so prominently. The fact that WECS cost uncertainties are not so prominent is due in part to the fact that powerrelated and rotor-related costs are treated independently, but the results do suggest that wind energy has already passed the stage at which technological uncertainties dominate other issues. In a generally uncertain world, the long-term economic value of

wind energy may not be any more uncertain than that of many other energy technologies.

Utilization of the wind resource. Another output available is the rated output energy density of wind turbines a t the marginal site used. Across the different sampled runs, this ranged over 110-630 W/m 2 (rotor power at rated output), the lowest figures only appearing in non-nuclear futures. The figure 630 W/m 2 corresponds to a 60 m mean of 8.6 m/second; this indicates that only the peak of the wind resource is being exploited. The lower bound corresponds to a mean speed of 4.8 m/second under these circumstances, virtually all the national resource is economic. Table 6 shows how on average the optimal WECS capacity was distributed between the regions. The large and high-windspeed Scottish resources remains of great importance, despite the many penalties associated with operating in such regions. The value of the high windspeed regimes all along the west coast is also readily apparent. Of course, these results reflect certain simplifications. It is assumed that siting restrictions apply equally to all terrain types. Moreover, the capacities involved, if all onshore, would mean that around 5-10% of the UK mainland would have wind turbines as a major feature in the landscape: many people hold the view that this would be totally unacceptable. Such issues can probably only be resolved through experience with siting large wind turbines. Net present values. The benefits from major energy investments are usually presented in terms of net present values, and it is of interest to estimate results in this form. To do this, a simplifying assumption needs to be made about the development of benefits as the technology is introduced. Early investments in WECS have a greater system value than those later, and better sites could be used; but initial growth may be slow and machine costs higher. Assuming quite simply that wind energy is introduced from 1990 to

Table 6. Distribution of installed WECS capacities. Table 5. Uncertainties significant in determining result (95% confidence level), in declining order of importance. Nuclear unconstrained

No nuclear

Nuclear capital cost WECS siting restrictions Nuclear fuel cost Nuclear average availability WECS rotor-related costs Electricity demand escalation

WECS siting restrictions Coal fuel cost Coal capital cost Electricity demand escalation WECS rotor-related costs

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% distribution of capacity Unconstrained Without nuclear nuclear

Region N Scotland S Scotland N England Wales and west Midlands Midlands and SE England SW England

Total

32 15 tO 17 11 t5

31 16 11 17 12 13

1O0

1O0

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the optimal state in 2020 and that associated benefits rise linearly, discounting at 5%/year to 1986 gives the results that: Present value, with nuclear £ 9 530 million Present value, without nuclear £19 600 million A more detailed system expansion analysis would be likely to give a higher with-nuclear figure, as wind energy could only conflict with nuclear at a fairly late stage. With due caution, such results can be interpreted as an upper limit to the amount of development expenditure which might be economically justifiable. In fact, current public R&D expenditure on wind energy in the UK, if maintained at current levels, would have a present value of just under £100 million. It does not automatically follow that wind energy is under-funded; but such results certainly suggest that an economic case for greatly increased levels of R&D funding may exist, and deserves close attention.

Comparison with other studies The principal conclusions from the probabilistic study are that: •

•

onshore wind energy is almost certain to be an economic source on the British supply system; and the economic contribution is likely to lie in the range 20-50% of delivered energy (towards the lower end against a strong nuclear input, towards the upper if nuclear power is heavily constrained).

This section discusses the results in relation to other recent studies. The UK Department of Energy has used the Harwell Electricity Planning Model to investigate the benefits from wind energy deployed in the period 2001-2010. 31 The Department estimated that the energy cost of large, series-ordered machines in this period would probably lie in the range 2.5-3.2p/ kWh, and concluded that 'wind power may be competitive over a large range of sites in the UK'. Several studies investigated in detail the economics of the US MOD-2 machine, based on early production-level projections corresponding to about £800/kW in 1986 prices. Bossanyi,32 using the Reading/RAL Simulation model of the CEGB system, optimized the mix of wind, coal-fired and peaking plant against a background of 8.17 GW inflexible nuclear plant, and concluded that at the then current fuel prices, about 17 GW of such

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machines would be optimal, supplying 23% of d e m a n d . Using similar costs, M a r t i n and Diesendorf33 applied a probabilistic load duration model to optimize the thermal mix of nuclear, coal and oil plant for small wind penetrations, and derived breakeven costs for MOD-2 machines of about £850/kW in 1986 prices. Finally, a CEGB study34 examined the economic requirements for the MOD-2 machine to be economic at the Richborough site. Adjusting for inflation and improved wind data for the site, 35 the breakeven cost calculated against the Sizewell station is equivalent to about £800/kW (1986 prices) for intermediate penetrations, and up to £1 000/kW for first deployments. The MOD-2 machine itself failed to meet the ambitious targets set for it, but medium-scale commercial machines have now reached such cost levels, which all these studies have concluded to be economic. They are still developing rapidly and as yet are produced in relatively small quantities. Against this background, the economic results presented in this paper are of no great surprise. The scale of contribution, however, appears more contentious. The wind contribution obtained in analyses depends upon both the wind resource analysis and the system modelling technique used. Martin and Diesendorf36 did not speculate on the possible scale of contributions, and nor did Talbot and Taylor, 37 though other CEGB studies confirm that no major system penalties are e x p e c t e d below 20% penetration. 3s Bevan, Derwent and Beford 39 assume a maximum wind input of 7.5 GW due to siting restriction; the study here uses an uncertain range of restrictions in which the modal value excludes 86% of physically available sites, which with the minimum WECS spacing of 10 rotor diameters gives a maximum of about 90 GW of wind power. In Bossanyi's study, 4° the optimum is determined by the declining system value of windpower calculated from the Rutherford model; the reasons why the PEGA results differ are addressed elsewhere. 41

Policy implications For many years, generation planning has been based on the conclusion that the only serious contenders for large-scale supply were the thermal sources of coal, oil, and later nuclear and gas, together with hydropower in those areas endowed with adequate resources. The recent rapid development of wind energy suggests that it may be joining those ranks. The UK is fortunate in being exceptionally well endowed with wind energy resources, and has a

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supply system which could absorb large amounts of energy from the wind even in the absence of electricity storage. All the supply options suffer from increasingly significant limitations and drawbacks. Coal is abundant but suffers from environmental problems: SO2 and NOx abatement adds significantly to generation costs (and creates a large amount of slag), and the CO2 problem appears insoluble, with the main debate being over when it will become significant. In addition, the drawbacks of being dependent upon one source are well appreciated. Nuclear power has its own environmental problems, and the worldwide slowdown of nuclear orders - which occurred prior to the Chernobyl accident - reflects the great technical, political and logistic problems associated with nuclear power. In the UK, political opposition may remove it as an option, and a system which relied heavily on nuclear could be in severe trouble if there were a major accident at one plant. The arrival of a new generating option is indeed to be welcomed. Nevertheless, the steps which should be taken are not obvious, partly because there are many uncertainties which need to be resolved. Though the most recent commercial wind machines are economic on paper, their real long-term performance and reliability is unproven; also, they are smaller than would appear desirable for power production on a major scale. Development seems certain to bring about further improvements in machine performance and an increase in unit size, so there are strong grounds for waiting before placing any large orders. On the other hand, operating experience is a major necessity at present, and the development process itself will be much hastened by large orders early on. Furthermore, one of the major uncertainties lies in the practical extent of large wind arrays on land, and early experience is again very important. Given the overall scale of supply investments, there is therefore a good case for placing orders now for several arrays of medium-sized machines from a range of the leading companies in the field. An additional measure, which would help to stabilize the market and give companies the confidence for continued development, would be for UK utilities to commit themselves to a minimum level of ordering over the coming years. Such an approach has been taken in Denmark, where the utilities have agreed to buy a minimum of 100 MW wind capacity over 1986-91. For the development of larger machines, if desired, experience suggests that 'diving in at the deep end' is not a very effective approach, at least unless

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the funds provided are adequate for a sustained development programme: this would imply a commitment of £100 million or more. Barring such a commitment, the approach of encouraging companies to push at the limits of current technology seems likely to be more cost-effective. An alternative approach to wind energy development - and the one which has really been responsible for the rapid developments since 1980 - is to encourage private electricity production. This could be achieved through various incentive schemes and, more importantly, through the removal of market barriers. Despite the 1983 Energy Act, there are three major sources of market inequality in the UK: •

•

•

The private sector tends to use much higher discount rates than the public sector: capital intensive projects which are economic as public investments are often unattractive to private industry. When both sectors are involved in the same market, the anomaly can, if desired, be removed by subsidizing private projects to bring the effective rate into line with the public rate. Wind turbines are currently subject to local authority rate payments at the standard capitalbased charge for industrial plant, which typically adds 1.0-2.0 p/kWh to generation costs. This is many times the rateable value used for CEGB investments, and in itself is sufficient to make private generation uneconomic. 42 The electricity buyback tariff offered by the Area Boards is generally rather less than the marginal cost of system production; this marginal cost would naturally apply for investments considered centrally.

If the UK is to follow the Californian route to wind power development, such anomalies will have to be removed. Privatization of electricity supply could achieve this - depending very much upon the details of implementation. However, simply attempting to 'free' the generation market also has clear drawbacks in this context, not least because it would tend to result in a haphazard development of wind technology and sites. It could lead to many small or poorly-designed machines being placed early on in some of the best sites, perhaps with little regard for aesthetics or the overall development of technology and system. Nevertheless, suitable regulations, standards and guidelines might well mitigate the drawbacks while preserving the benefits of this route. Concern over the visual impact of onshore windpower has led to great interest in going offshore, where stronger winds help to offset the additional capital costs. Economic studies have tended to

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assume very large machines, because of the large fixed cost of foundations, and though machines designed for offshore use are under development there has been no operating experience of this much harsher environment. Cost estimates are thus inevitably speculative, as well as somewhat dated by the developments onshore. The view that siting restrictions will severely limit the onshore contribution of windpower is widely expounded: the corollary of this view should be an early commitment of funds for a serious offshore development programme. Finally, what implications does the probable growth of wind energy have for other system investments? The introduction of windpower will tend to reverse the current trend towards an increased thermal load factor, and the possible requirements for part-loading or occasional cycling may have some minor implications for baseload plant design. In addition, such sources will tend to increase the value of load management and of more flexible power pricing, which can reduce the impact of load peaks and troughs. In the longer term, windpower will tend to reduce the requirement for baseload units and increase the need for more mid-range and peaking plants and/or electricity storage. In itself this scarcely impacts on the economic case for current baseload investment, but given the great lifetime of generating plant there may be a case for moderating the current heavy emphasis on developing still more efficient but capital intensive and inflexible baseload units.

Conclusions The paper has outlined methods designed to analyse the long-term role of intermittent sources on large supply systems, and applied them in a detailed study of the long-term prospects for wind energy in the UK. The principal conclusions from these studies may be summarized as follows: •

•

Wind resources in the UK are significant on a national scale unless there are very severe (>99%) restrictions on site availability. To supply one third of current national demand from onshore wind energy, wind turbines would have to be sited in about 5% of the UK mainland, and 0.1-0.2% of land area would then be occupied by the machines and support facilities. If the energy was derived from machines 60 m high, perhaps 15 000 would be required, at a minimum spacing of half a mile or more. Beyond small capacities, intermittent sources such as wind energy cannot be analysed by

ENERGY POLICY December 1988

•

•

simple methods. The issues of capital displacement, changes in marginal fuel savings and the inhomogeneity of the resources are all important. Great care needs to be taken especially in the treatment of wind diversity and predictability, and in certain system operating characteristics. The marginal value of wind energy to the system declines steadily as the capacity increases, but the practical limit is high. If desired, an integrated UK system could probably absorb 50% of its energy from distributed wind power alone, even in the absence of storage. In the absence of other new electricity sources, onshore wind energy is likely to be a prominent economic supply source for the UK. Siting permitting, the economically optimal contribution will probably lie in the range 20-50% of system demand.

In short, wind energy has great potential as a national energy source. It should be treated accordingly.

Postscript: Much has occurred in the time since this article was written. Internationally, the wind power industry is picking up again after the postCalifornian-credit slump of 1986; US installation rates are well below the levels of the tax-credit years, but the European market is steadily expanding, together with growing business in the developing world. On the manufacturing side, Japan has entered the fray in the form of Mitsubishu and Sumitomo, as has Hong Hong. Time shows ever more clearly the poor performance of many of the machines sited in the Californian rush, and European makes have not been immune from the plague. But though the average figures make sorry reading, the best are impressive, with windfarms of some of the newer designs turning in average availabilities of over 95% in the first two years of life. The headlong pursuit of cost reductions has given way to the pursuit of reliability, and an increasing awareness of the importance of attractive appearance and careful siting. In the UK, the government has outlined its plans for privatizing the electricity supply industry. Of particular importance to wind energy is the commitment on Area Boards to buy a particular proportion of 'non-fossil' power, though it is far from clear how this figure will be set and applied in practice. The government has stated clearly that it is opposed to introducing any kind of financial incentives for wind energy (other than any which the non-fossil requirement may imply), but has announced that the 605

Wind energy in Britain

discriminatory rating system for private generators the single most important obstacle to private power generation in the UK - is to be reformed in April 1990. The Department of Energy has, however, stated that 'it is uncertain whether it will be practical to apply it [ie equable rating] to producers (of electricity) regardless of size', and it is also unclear how sources of different capacity factor will be rated. Because of such factors, wind energy's unusual characteristics make its commercial value strongly dependant on the fine print of privatization and rating legislation; the practical competitiveness of wind energy on the privatized system is thus still highly uncertain. Finally, the CEGB has announced plans to build three wind parks of 25 machines each in the 200-500 kW range, at a total cost of £28 million, and a Howden 750 kW machine is to be placed on a tripod 5 km off the East Anglian coast as part of offshore development studies. Local objections have been lodged against one of the parks, in the northern Pennines. The resulting planning enquiry and wind park project as a whole will provide useful insight into the question of public reaction to wind energy, as well as bringing valuable business to the nascent UK wind industry. In all, the field of wind energy has changed beyond recognition in the last six years - but there is still a long way to go, and many uncertainties to be resolved. ~The Californian Energy Commission has a goal of 4 GW wind capacity by the end of the century, about 10% of system peak demand. P. Gipe, 'Maturation of the US wind industry', Public Utilities Fortnightly, 20 February 1986. Holland aims to have 1 GW of windpower by then, a similar proportion. See J.B. Dragt, 'The wind energy scene in the Netherlands and the role of ECN',

Proceedings 9th British Wind Energy Association (BWEA) Wind Energy Conference, Edinburgh, UK, 1-3 April 1987. Other nations are also planning rapid development. See J. Twidell, 'International review of USA, EEC, Denmark, China and Algeria', Proceedings 9th BWEA Wind Energy Conference, Edinburgh, UK, 1-3 April 1987. 2Windirections, Newsletter of the BWEA, April 1987. 31bid. The complete removal of tax credits for machines installed after 1985 has roughly halved the construction rate. 4Data from P. Gipe, op cit, Ref 1. Windirections, op cit, Ref 2. SD. Milborrow, 'Intermittent power sources - status and prospects', Colloquium on the Economic and Operational Assessment of Intermittent Power Generation Sources, Imperial College, London, UK, March 1987. 6BWEA, Wind Power for the UK, BWEA, January 1987. Confirmed, private communication. 7Published conversion characteristics for the Howden HWP-750 machine show it to produce 3 MWh/kW/year at sites with a mean wind speed of 8.0 m/second at the hub height of 35 m (more recent machines may well perform better than this). Such sites may be found at many locations along the west coast, generally the most windy region in the UK. 8Assuming 5% discount rate, O&M charges of 2% capital cost/year, 20% total losses (from unavailability and machine interference) and a 25-year lifetime.

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9P.j.H. Builtjes and D.J. Milborrow, 'Modelling of wind turbine arrays', 3rd International Symposium on Wind Energy Systems, Copenhagen, 1980. The output from turbines placed within an 'infinite' array at 10-diameter spacing is reduced by about 40%, but in likely array sizes the loss would be reduced to 10-20%. 1°Overall conversion efficiency depends on aerodynamic, mechanical conversion, availability and transmission losses, none of which can be very well predicted. The way in which windscales with height varies considerably between sites and data is very poor, introducing another significant unknown. The pattern of siting (isolated machines; small, close clusters; or large, more spaced arrays) will have a major impact on the ability to extract energy from windy areas. I~H. Seizer, 'Wind resources assessment', European Solar Energy R&D, Series G, Vol 2, 1986. ~2M.J. Grubb, 'The integration and assessment of intermittent sources in large electricity supply systems', PhD Thesis, Cambridge University, Cambridge, UK, June 1986. 131. Caiman, 'The views of politicians and decision-makers on planning for the use of windpower in Sweden', European Wind Energy Conference, Hamburg, Germany, 1984. 141.Caiman, 'Public opinion on the use of wind power in Sweden', European Wind Energy Conference, Rome, Italy, 1986. ~SM.J. Grubb, op cit, Ref 12. 16Simple statistical arguments may be used to quantify the effects approximately. For example, if 5 000 2 MW wind turbines were dispersed in the UK, microscale fluctuations (approximately one minute) of the order of 30 MW might be expected, together with typical hourly variations on the order of 600 MW. This is substantially less than corresponding variations in electricity demand. See R. Lowe, 'Windpower statistics in Britain', PhD Thesis, Open University, Milton Keynes, UK, 1984; M.J. Grubb, op cit, Ref 12. 17M.J. Grubb, op cit, Ref 12. ~SM.J. Grubb, Probabilistic Electricity Generation Analysis, Imperial College Power System Report No 112, January 1987. ~gThe capital costs are broadly similar to those on the current system, fuel costs are slightly higher. Because the emphasis at this stage is upon the role of wind energy on the system, the absolute values are not of central importance and discussion is left until later. The fuel savings shown are annual average savings calculated using historic load and wind energy data over the period 1971-9. 2°Many operational aspects of integrating wind energy on power systems have been studied at the Rutherford-Appleton Laboratory. See J. Halliday, N. Lipman, E.A. Bossanyi and P.E. Musgrove, 'Studies of wind energy integration for the UK national grid', Wind Workshop Vl, Minneapolis, USA, June 1983, and elsewhere. Differing classification of component costs make a detailed comparison difficult, but the operational penalties described here appear a little lower than the Rutherford results: slightly greater unit startup costs are assumed, but this is more than offset by the greater wind diversity and predictability used. There is a greater difference in the estimate of discarded wind energy at higher system penetrations, and consequently in the estimate of maximum wind contributions. The reasons for this are discussed in M.J. Grubb, 'The economic limits to windpower capacity on large supply systems: a comparison of models sensitivities and assumptions', Wind Engineering, Vol 12, No 2, June 1988. 21in fact the capacity value of small amounts of windpower is equal to that of other baseload sources with the same mean winter energy output. For the CEGB system this approximation holds well, up to at least 5 GW of windpower. Such capacity credits are discussed in A.P. Rockingham, 'System Economic Theory for WECS', 2nd BWEA Wind Energy Conference, Cranfield, UK, 1980. 22The value is thus defined as the total costs of the power system (including capital annuitized at 5%/year) when fully optimized without wind energy, less the total thermal costs when reoptimized for the specified level of wind energy. 23Large gas turbines, which can operate on a range of light fuel

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Wind energy in Britain

oils as well as natural gas and substitutes, cost in the region of £300/kW. To backup wind energy to the level of an equivalent thermal baseload source, a capacity of about 1/3 the wind capacity is needed (the mean winter wind energy - the relevant quantity for backup - is less than half the installed capacity, and gas turbines are more reliable than thermal baseload plant). As a crude measure, the need for backup therefore adds around £100/kW to the cost of wind energy on large power systems. 24M.J. Grubb, 'The economic value of intermittent power sources on large electricity supply systems', lEE Proceedings, Part C (in preparation). 2SN.L. Evans, 'The Sizewell decision: a sensitivity analysis', Energy Economics, Vol 6, No 1, January 1984, pp 14-20. 28Monte Carlo sampling was not used, however, as it would require too many runs. To ensure full coverage of the ranges in as few runs as possible, the stratified technique of Latin Hypercube Sampling was used. 2ZM.J. Grubb, op cit, Ref 12. 288 m/second mean windspeed at 60 m height is a convenient reference, within the range of sites currently being exploited in the USA and Europe. With machine rating at 1.6 Vm, it gives a rotor output at rated speed (12.8 m/second) of about 500 W/m 2. A lower limit to the power-related component of machine costs is set by the fact that 30-40% of costs in current machines are directly related to the peak power output. See op cit, Ref 1. 29To model transmission issues thoroughly would require an extremely complex network analysis, and techniques for including this in generation analysis do not yet exist. The figures used here reflect an assumption that at high wind energy penetrations, new overhead 400 kV lines would be required for bulk transport of any windpower above local mean demand, at approximately present real costs. Transmission proves to be a fairly minor component of total costs.

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3°N.L. Evans, op cit, Ref 25. 31E.G. Bevan, R.G. Derwent and L.A.W. Beford, 'Wind energy: a promising renewable energy source for the UK', 7th BWEA Wind Energy Conference, Oxford, UK, 1985. 32E. Bossanyi, 'Use of a grid simulation model for long-term analysis of wind energy integration', Wind Engineering, Vol 7, No 4, 1983. 33B. Martin and M. Diesendorf, 'The economics of large-scale windpower in the UK: a model of an optimally mix CEGB electricity grid', Energy Policy, Vol 11, No 3, September 1983, pp 259-266. The apparent omission of seasonal variations means that their results are probably unduly pessimistic. 3"J.R. Talbot and R.H. Taylor, 'Economic assessment of wind turbines in an electricity supply system', Fourth lEE Conference on Energy Options, London, UK, 1984. 3SSubsequent CEGB measurements have shown that the 1/7 power law used for the site underestimated the energy available by nearly 50%. See D.J. MUborrow and P.L. Surman, 'CEGB wind energy research', Fifth lEE Conference on Energy Options, Reading, UK, 7-9 April 1987. A correction of 40% energy capture is here applied to the previous economic calculations. 38Martin and Diesendorf, op cit, Ref 33. 37Talbot and Taylor, op cit, Ref 34. 38E.D. Farmer et al, 'Economic and operational implications of a complex of wind driven generators on a power system', lEE Proceedings, A, Vol 127, June 1980. 39Beven, Derwent and Beford, op cit, Ref 31. 4°Bossanyi, op cit, Ref 32. 41The differences are primarily due to differing assumptions on wind diversity, predictability and the part-loading capabilities of thermal units, in particular nuclear power. See Grubb, op cit, Ref 20. "2Windpower monthly, March t986; Windirections, April 1987.

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