Study on flexibility in the Dutch and NW European power market in 2020

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1 Study on flexibility in the Dutch and NW European power market in 2020 A REPORT PREPARED FOR ENERGIENED April 2010 Frontier Economics Ltd, London.

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3 April 2010 Frontier Economics i Study on flexibility in the Dutch and NW European power market in 2020 Executive Summary 1 Additional case study: What would be the effect of the COBRA cable?... Error! Bookmark not defined. 2 Introduction 19 Scope of work...19 Organisation of report Our approach 23 Plant and load data for CWE area in Define and agree scenarios...25 Adaptation of CWE system dispatch model...25 Developments in other EU countries...27 Market dynamics Definition of scenarios 29 Wind generation capacity...29 Fuel prices...30 Load forecast...31 Reserve requirements...32 Evolution of the thermal plant park and supply curve...34 Interconnection capacity...38 Summary of scenarios System dispatch simulation for Results for the 6 and 12 GW scenarios...41 Sensitivities Answers to specific questions 67 Can the market handle the fluctuating supply of wind power?...67 What is the impact of wind on system marginal cost?...69 Contents

4 ii Frontier Economics April 2010 What is the role and importance of market integration?...73 Is CHP the perfect partner to wind production?...77 What are the implications for business cases?...78 Is there a need for storage? Market dynamics 81 Markets within the Netherlands...82 Integration of markets in the Netherlands with interconnected countries...84 Other relevant developments Conclusions 91 9 Annexe 1: Case study Effect of the COBRA link between the Netherlands and Denmark West Annexe 2: Data used in simulations Annexe 3: Experience in other EU countries with significant wind and CHP generation 123 Contents

5 April 2010 Frontier Economics iii Study on flexibility in the Dutch and NW European power market in 2020 Figure 1. Key measures for a successful market integration of wind power 3 Figure 2. Contribution of flexibility sources to adapt for higher wind infeed in the 12 GW scenario compared to the 6GW scenario 6 Figure 3. Supply curve 12 GW scenario NL; Figure 4. Monthly real system marginal costs for the 6 and 12 GW scenarios NL; Figure 5. Flexibility options and indicative ranking 12 Figure 6. Our approach 24 Figure 7. Projected cost of power generation from gas and coal, including CO2 prices, in /MWh NL Figure 8. Relationship between manual reserve requirements and wind generation capacity 33 Figure 9. Projected evolution of system adequacy in the Netherlands (12 GW case) 36 Figure 10. Supply curve 12 GW scenario NL; Figure 11. Energy balance in the 6 GW scenario Netherlands; Figure 12. Energy balance in the 12 GW scenario Netherlands; Figure 13. Production profile in a winter week for 6 GW scenario Netherlands; Figure 14. Production profile in a winter week for 12 GW scenario Netherlands; Figure 15. Production profile in a summer week for 6GW scenario Netherlands; Figure 16. Production profile in a summer week for 12 GW scenario Netherlands, Tables & Figures

6 iv Frontier Economics April 2010 Figure 17. Thermal production ordered by the residual load duration curve for 12 GW scenario Netherlands; Figure 18. Changes in system operating costs between the 6 to 12 GW scenarios Figure 19. Level of CO2 Emissions in the 6 and 12 GW case Figure 20. Gross exports from and imports in the 12 GW scenario Netherlands; Figure 21. Heat balance in the 12 GW scenario Netherlands; Figure 22. Net effects of 500 MW additional interconnector capacity on the energy balance Netherlands; Figure 23. Net effects of 500 MW additional interconnector capacity in TWh on net Netherlands imports/exports Figure 24. Net effect of a merit order switch (gas cheaper than coal) on the energy balance Netherlands; Figure 25. Net effect of a merit order switch (gas cheaper than coal) on carbon emissions Figure 26. Net effect of a reduction of IC capacity to Germany and its neighbours on the energy balance Netherlands; Figure 27. Net effect of a reduction of IC capacity to Germany and its neighbours on net imports/exports Figure 28. Net effect of a reduction of interconnector capacity to Germany and from Germany to CEE countries on variable generation costs Figure 29. Net effect of a reduction of interconnector capacity to Germany and from Germany to CEE countries on reserve prices Netherlands; Figure 30. Net effect of inflexible coal on the energy balance Netherlands; Figure 31. Net effect of inflexible coal on variable generation costs Figure 32. Net effect of higher reserve requirements on the energy balance Netherlands; Tables & Figures

7 April 2010 Frontier Economics v Figure 33. How the additional wind generation is absorbed impact of an additional 6 GW Netherlands; Figure 34. Monthly average system marginal cost for 6 and 12 GW wind scenarios baseload period Netherlands; Figure 35. Monthly average system marginal cost for 6 and 12 GW wind scenarios peak period Netherlands; Figure 36. Duration curve of system marginal costs with nominal APX prices in the 12 months to December 2009 superimposed Netherlands; Figure 37. Monthly volatility of real system marginal costs for the 6 and 12 GW scenarios Netherlands; Figure 38. Market coupling in 2020 price convergence between countries 74 Figure 39. System marginal in the 12 GW scenario across the CWE baseload Figure 40. Gross exports and imports by destination and origin in the 12 GW scenario Netherlands to/from other countries; Figure 41. Normalised standard deviation of wind generation forecast error 82 Figure 42. Timeline for different markets in the Netherlands at present 83 Figure 43. Model for cross-border intraday trading 87 Figure 44. Physical flexibility and how to make it accessible to the market 91 Figure 45. Importance of flexibility measures 93 Figure 46. Power plants in Denmark West in Figure 47. The Western Danish system international exchange capacities today 99 Figure 48. Overview nominal capacities of the power plant system in Denmark West in Figure 49. Assumed heat demand covered by district heating in total Denmark 101 Tables & Figures

8 vi Frontier Economics April 2010 Figure 50. Existing and new links around Denmark (brown field show links that are enhanced or new built) 102 Figure 51. Changes in plant dispatch and international exchange due to COBRA base case 103 Figure 52. Changes to international flows induced by COBRA - detailed 104 Figure 53. Seasonal average of hourly flows between Denamrk West and the Netherlands in the base case in Figure 54. Price effect of the COBRA cable in the base case with 12 GW of wind in the Netherlands 106 Figure 55. Effect of 12GW vs. 6 GW wind target on plant operation and exchanges with the COBRA cable 107 Figure 56. Effect of the COBRA cable in the curtailment scenario 108 Figure 57. Evolution of different generation technologies in the Netherlands (derated capacity) 110 Figure 58. Existing plants in the Netherlands 111 Figure 59. Existing plants in the Netherlands - continued 112 Figure 60. CHP plant capacity Netherlands; Figure 61. Installed capacities (derated), by technology in CWE in Figure 62. CHP and HOB capacity and heat demand assumptions by sector 118 Figure 63. Wind infeed assumptions for the Netherlands 120 Figure 64. Interconnection capacity assumptions for Figure 65. Production and consumption data for Denmark West in Figure 66. Frequency of different levels of wind production - Denmark 126 Figure 67. Histogram of residual demand - Denmark 127 Figure 68. Contribution of production and interchanges in July Denmark 127 Figure 69. Load and Residual Load Duration Curve - Denmark 128 Tables & Figures

9 April 2010 Frontier Economics vii Figure 70. Scatter plot of wind generation against net interchange with neighbours (imports are positive) - Denmark 129 Figure 71. Scatter plot of wind generation against Elspot price for DK- W 130 Figure 72. Intraday market volumes - Spain 133 Figure 73. Wind generation and market prices - Spain 134 Figure 74. Development of wind generation - Germany 135 Table 1. Imports from and exports to each CWE country and satellite Table 2. New thermal plant additions (non CHP) - Netherlands 113 Table 3. Plant retirements in Netherlands between 2009 and Table 4. New thermal plant additions (non CHP) - Netherlands 114 Table 5. Key plant characteristics used for conventional thermal plant 117 Table 6. Typical CHP Plant characteristics 119 Table 7. Basic facts about wind generation - Spain 132 Tables & Figures

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11 April 2010 Frontier Economics 1 Executive Summary 1.1 There has been a debate in the Netherlands about the compatibility of new investment by individual utilities in the thermal plant park with Government policy to have 12 GW of on and offshore wind generation capacity installed by the year The key areas of concern are: whether sufficient flexibility will exist in the power system to permit uncertain, intermittent wind generation output to be accommodated; and whether the available sources of flexibility will be accessible by relevant market participants. In this context, EnergieNed asked Frontier Economics to carry out a study of the year 2020 for the Dutch and North West European power system. The requirement was to undertake quantitative modelling and qualitative analysis of the system in the year 2020 under a small number of scenarios in order to answer a series of specific questions. We were also asked to look at experience in Denmark and other countries with high wind and combined heat and power plant (CHP) penetration. The questions, and our answers to them, are presented in this summary. 1.2 In the following paragraphs we set out: a short list of key findings from our quantitative analysis of two primary scenarios one with 6 GW and one with 12 GW of wind generation capacity; the recommendations we derived from those findings; our answers to the specific questions we have been asked by EnergieNed; and a final wrap up of our conclusions derived from all of the work. 1.3 We also provide a short annex to the Executive Summary setting out the modelling approach. Key findings 1.4 From the quantitative modelling and qualitative analysis we find that: 12GW of wind can be accommodated Our modelling results indicate that the integration of 12 GW of wind power is feasible under the assumptions we have used, if the available flexibility in the Netherlands and interconnected countries is used optimally. This integration of 12 GW of wind capacity can happen along side the substantial growth in conventional Executive Summary

12 2 Frontier Economics April 2010 capacity and will make the Netherlands a net exporter of electricity within the CWE area. Even for the favourable wind year which was modelled we found virtually no wind curtailment under the assumption of perfect market integration and strong grids. However, the system will then be at the edge in terms of flexibility. An increase in demand for flexibility (e.g. higher reserve requirements) or a decrease in supply of flexibility (more must run generation, greater build of less flexible technologies, inefficient allocation of flexible resources) could quickly trigger significant wind curtailment, frustrating the policy aims of reducing carbon emissions by displacing generation from fossil fuels. Therefore, creating optimal flexibility conditions in the CWE market is crucial to integrate of the output from 12 GW of wind generation capacity. International power flows play a crucial role for integration Wind integration requires strong grids. International power exchanges between the CWE countries play a crucial role in managing variable and unpredictable wind infeeds in the Netherlands, both from a technical and from a market point of view - especially in times of low load and high wind in-feed. The integration of about 2/3 of the additional wind supply, when going from 6 to 12 GW, is facilitated by changes in import and export balances. This requires flexible and close-to-real-time access to (cross-border) transmission capacity. For our analysis we assumed that by 2020 national grids are strong enough to avoid internal grid congestions within the individual countries of the CWE area. 1 Conventional plants needed to provide flexibility Flexibility from conventional plants is also required to accommodate 12GW of volatile wind infeed. High wind production decreases utilisation rates for thermal power plants. However, due to its volatile character, wind can only substitute secured generation capacity to a limited extent so the thermal capacity is still essential for security of supply. Under the assumptions we have adopted, CHP plants could not efficiently provide significant additional flexibility to the system, even though many have variable heat to power ratios and could switch off power output and serve heat demand from heat only boiler (HOB). However, other sources of flexibility are available at lower cost to provide the additionally required flexibility. 1 Obstacles such as the bottlenecks which exist today (e g for the north-south and east-west transport within Germany) are assumed to be effectively removed. Currently, projects are underway or planned to remove such obstacles; the removal of these bottlenecks in the coming decade is crucial to make optimal use of the wider CWE market. Internal congestions will hamper the integration of wind, also in neighbouring countries. Executive Summary

13 April 2010 Frontier Economics 3 Market design should ensure access to flexibility source Integrating wind requires market rules that allow for an optimal use of projected interconnector capacity. As the contribution of wind grows, the integration of short term markets, such as intra-day or balancing power markets, across borders increases in importance. Recommendations for future system development 1.5 Our recommendations for future system development are: successful market integration of wind power will require that: physical flexibility is available in the system; and the flexibility is accessible to those who need it via efficient markets. 1.6 Figure 1 sets out the key measures that flow from these requirements. Figure 1. Key measures for a successful market integration of wind power We need to make sure that physical flexibility is in the system Thermal plants needed on system and able adjust their output AND make sure that this flexibility is accessible to those who need it! Liquid markets close to delivery (Intraday) CHP Plants need to become more flexible CWE market coupling allows for better interconnector usage Nuclear should be able provide manual reserve Harmonize day ahead markets with GB and Norway Interconnectors are important International balancing markets Source: Frontier 1.7 The main actions that are likely to increase flexibility in the system are: Allow for strong national and international grids this requires an adequate regulation of the networks as well as efficient approval procedures for planning and construction of new lines at national and cross border level; and Executive Summary

14 4 Frontier Economics April 2010 Efficient market designs Provide for efficient allocation of available flexibilities both within the Netherlands and in the neighbouring CWE countries. This includes an efficient integration of short term markets (day ahead, intraday, balancing) within the CWE; and close to real time gate closures to allow market players to react to latest information gains (e.g. better wind forecasts). Must run generation to be kept at low level Wind curtailment is most likely to occur during high wind and low demand hours. High volumes of inflexible must run generation (e.g. from heat driven CHP or from plants providing downward reserve to the TSO) will increase the chance of curtailment. Plants which have not been operated very flexibly in the past (e.g. nuclear, CHP) will need to contribute to flexibility in future. This may require greater incentives than in the past (e.g. low or negative prices at times of energy surplus). 1.8 From our analysis we rank the importance of actions to increase physical flexibility options as follows: ensure strong national and international grids; enhance flexibility of CHP and nuclear (to keep thermal must run low as low as possible); and harmonize market rules to allow for efficient access to flexibility within and outside the Netherlands. 1.9 Power storage is a further flexibility option under discussion. However, our calculations suggest that, under scenario assumptions, it would be little used. It is possible that it would gain in importance if required grid extensions were delayed. Questions and Answers 1.10 In the following section we present our answers to the specific questions put by EnergieNed. What is flexibility? 1.11 We consider flexibility to be the availability of resources, from the day ahead of delivery to the time of delivery, that can change their level of production or demand by defined amounts and sustain this position for a period of at least one hour in a reliable manner. Executive Summary

15 April 2010 Frontier Economics 5 Will the Dutch system be able to handle a fluctuating supply of significant amounts of wind power? 1.12 Under our assumptions, the CWE system has sufficient flexible resources to integrate the 12 GW of wind generation output, even with production at slightly higher than average levels. Under our base scenario 2 we observe only limited wind curtailment, even in low load hours, and no load shedding 3 ( uncovered electricity demand ). However, the sensitivity analysis indicates that the system is close to the edge ; an increase in the manual reserve requirement and stricter assumptions on plant flexibilities (minimum load conditions, ramping constraints to provide manual reserve) can lead to about 10% of wind generation being curtailed in the Netherlands in Although the simulation models wind as a free resource, for physical and economic reasons, curtialment is sometimes the best or the only solution (although wind curtailment would put to question whether it is economic to build wind capacity to a level of 12GW). For a sensitivity run we assumed higher reserve requirements to be provided from the generation side (2200MW rather than 1300MW) and less flexible hard coal plants. We then observed wind curtailment volumes to be necessary in the range of 4 TWh pa (this corresponds to about 20% of the additional wind infeed when moving from 6GW to 12 GW of wind capacity) The main sources of flexibility are: the ability to vary the level of interchange with interconnected countries, especially Germany and Belgium/France; and changing ouput from conventional coal-fired plant and CCGT plant Our analysis suggests that interchange with other countries within the CWE region is the key source of flexibility. The integration of about 2/3 of the additional wind supply when moving from 6 to 12 GW finds is accommodated by changes in imports and exports. Flexibility from conventional thermal plants provides the remaining third. The CWE market plays a crucial role in handling wind power in the Netherlands, especially in times of low load and high wind infeed Heat following CHP plants exhibit little response to the significant changes in residual demand (load less wind and other renewable energy generation) as their options to adapt are restricted by local heat demand. Uncoupling power and heat production is limited by technical (local heat capacities from HOBs) and economical constraints (higher efficiency losses). 2 For our quantitative analysis we always looked at the year 2020 applying a 6 GW wind scenario and a 12 GW wind case for the Netherlands for various scenarios. 3 As we assume perfect foresight and an adequate capacity balance in the model the only reason for load shedding could be steep ramping between consecutive hours due to very volatile wind in-feed. Executive Summary

16 6 Frontier Economics April Figure 2 shows how the 21 TWh of additional wind in-feed are accommodated into the Dutch power system. The extra wind leads to about 6.8 TWh higher exports; imports are reduced by 7.2 TWh. The output from conventional thermal generation decreases by about 7 TWh. Figure 2. Contribution of flexibility sources to adapt for higher wind in-feed in the 12 GW scenario compared to the 6GW scenario Difference in TWh/a Wind Exports Coal CCGT Imports Extra power prod from He at adjustme nts Flexibility s ource Source: Frontier 1.17 Our review of international experience also indicates that interchange with interconnected countries is a critical factor in successful integration of wind generation output elsewhere, for example in Denmark and Germany. What role do the CWE market and market coupling play? 1.18 For the reasons given above, market integration - not only coupling at the day ahead stage but also in subsequent hours down to the hour of delivery - plays a crucial role. This supports the idea of coupling the CWE day ahead markets, as envisioned by May 2010 and in due course moving to integrate shorter term markets such as the intraday and the balancing markets The Nordic area has already successfully integrated these different markets and we see no reason why it cannot be achieved in the CWE area by Data for the existing TLC area show a significant coupling with strong price convergence between countries The results also indicate that increases in interconnection capacity will be critical to wind integration. Flow-based coupling will help to make more effective use of the physical capacity which exists and there are a number of projects in hand or Executive Summary

17 April 2010 Frontier Economics 7 under study to increase both synchronous and HVDC interconnections. Interconnection allows each country to take advantage of the geographical dispersion of the wind resource to share the management of the fluctuations in any single country Note that our analysis assumes that there are no internal grid congestions within the individual countries of the CWE area in The bottlenecks which exist for the north-south and west-east transport within Germany (or in The Netherlands around Eemshaven and Maasvlakte) are assumed to be effectively removed by Currently, projects are underway or planned to remove such obstacles; their removal in the coming decade is crucial to make optimal use of the wider CWE market. Internal congestion will hamper the integration of wind substantially. What is the impact of fluctuating wind power on required reserve capacity? 1.22 Based on a review of studies in Germany 4 and the UK, it is clear that at some level of wind penetration additional manual or short-term operating reserve is needed. The precise level at which this requirement is triggered and the rate of increase of reserve required as wind capacity increases above this level is subject to some uncertainty. The assumptions we have adopted are an increase of reserve requirement by 1MW for every additional 10MW of wind capacity above 6 GW of wind generation capacity; however, we are aware that additional engineering studies are being done on this subject 5. The requirements are also sensitive to improvements in the ability to forecast wind generation output in the hours immediately preceding delivery and to the size and structure of the thermal power plant park (e.g. existence of large generation units or interconnector infeeds). What is the impact of fluctuating wind power on power prices? 1.23 The fact that wind generation is unreliable means that significant thermal capacity must be maintained on the system to provide security of supply. Wind generation output then shifts the supply curve, shown in Figure 2, to the right reducing price at which it intersects with demand. 4 Compare dena grid study (2005) 5 Additional studies have been carried out by Ummels (2009) or Holttinen et al (2007) Executive Summary

18 8 Frontier Economics April 2010 Figure 3. Supply curve 12 GW scenario NL; Min. load Max. load OCGT /MWh CHP Flex Nuclear New coal and IGCC CHP Inflex Greenhouse motor Old coal CCGT 20 0 Wind, Other Re Potential Range of Wind Input 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 MWe Source: Frontier Economics 1.24 Our model produces data on system marginal cost; this is a reasonable indicator of market price in a competitive market but includes no premium for scarcity which can arise if there is limited supply to meet demand in peak periods 6. The impact of increased wind on system marginal cost is clearly seen in the comparison between our 6 GW and 12 GW scenarios. The additional wind infeed lowers the average baseload price level by about 5 per MWh (Figure 3). In the 12 GW scenario, there are over 160 off-peak hours when the system marginal cost is zero. 7 There is also a marked increase in price volatility, especially in winter when moving from 6GW to 12 GW of wind capacity. 6 We agreed to base our analysis on cost based power prices using short run marginal generation costs as price estimator for wholesale power prices in For this system flexibility analysis, we agreed not to apply additional price mark ups in times with high demand and scarce power plant capacities in our modelling (e g mark ups based on long run marginal cost analysis for new entry) as this would have required additional assumptions on price building mechanisms. 7 The model also allows for negative prices, but as we assume that by 2020 wind can be curtailed without any penalty this is not likely to occur. Today negative prices can occur on day ahead markets due to regulatory rules (e. g. German TSOs are obliged to sell all wind energy on the spot market. Wind park operators feeding in under the German renewable act do not receive any incentives to curtail their in-feed.) Executive Summary

19 April 2010 Frontier Economics 9 Figure 4. Monthly real 8 system marginal costs for the 6 and 12 GW scenarios NL; Monthly average wholesale power price in /MWh NL - base - 6 GW NL - base - 12 GW 50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source: Frontier Economics Is there a reason for saying CHP is the perfect partner to wind generation? 1.25 Our view is that CHP is not incompatible with 12 GW of wind generation capacity, but it is far from being the perfect partner. When moving from 6 to 12 GW of wind capacity, CHP shows little change in its market position. This is due to the technological constraints inherent in this technology of needing to track heat demand, limited heat-only-boiler (HOB) capacity and the high cost of running CHP more flexibly which would require running it at part load 9 or ramping down electricity output entirely and serving heat load from HOBs A feature of a wind/chp system is that high wind in-feeds are mainly expected in winter times when CHP s also run at high capacity to produce heat and power, resulting at an excess of electricity being offered to the market (this holds even if we account for the fact that electricity demand in winter is also higher than in other seasons). The compatibility of CHP with wind shown in our analysis could 8 Concerning prices: As we depart from prices in the year 2009 and do not incorporate an inflation forecast, the prices can be interpreted as real prices in 2009 price levels. 9 We did not include heat buffers in greenhouses in our model but considered heat only boilers there as well. Executive Summary

20 10 Frontier Economics April 2010 change if the market share of CHP were to increase and CHP capacity were to remain as inflexible as it currently appears to be Since, under our assumptions, CHP plants show only very limited flexibility, the impact of extra wind on CHP fuel use or emissions is limited. In a standard CHP operation mode CHP plants show a very high overall fuel efficiency of around 90%). When power is not needed (e.g. due to high wind infeed) the CHP plants can either reduce both their power and heat output; or decouple heat and power output to keep heat delivery high while reducing the power delivery (by using a HOB or by changing power-toheat ratio, if this is technically possible) In both cases the benefit of combined heat and power production is lost (heat will be generated from a HOB with 90% efficiency, power will be produced at an efficiency level which is below modern conventional plants (CCGT 58%, coal 47%) In general a high heat output tends to increase the overall CHP plant efficiency, higher power output (leading to lower heat output) decreases its overall efficiency. However, local heat demand is restricted and thus restricts the potential adaptations in the operation mode of the CHP plants It is noteworthy that Denmark has done much to make its CHP park more flexible by requiring power exchange market participation of CHP. The introduction of electric boilers that allow CHP generation to be decreased while meeting heat demand from electricity in high wind periods with low load has been encouraged. However, the characteristic of CHP plants in Denmark and the Netherlands is different: While Danish CHP plants are mostly district heating plants coming with low steam temperatures the Dutch CHP plants are mostly industrial CHP plants with high temperature steam supply and only very limited heat store options To limit the probability of wind curtailment, CHP plants need to become flexible enough to contribute to manual reserve provision thus avoiding the need to start other thermal plants for this purpose. Is there a need for storage? 1.32 The Compressed Air Energy Storage (CAES) plant we have included in the two scenarios has a very low load factor. At this level of wind penetration and given our other assumptions (especially regarding the capital cost of storage plant we assume specific investment costs for a CAES plant of 610 per kw), storage does Executive Summary

21 April 2010 Frontier Economics 11 not appear to be needed 10. However, in a situation with significant local grid congestion (and constraints on extending the grid in time), power storage can become an option if it could benefit from extra grid related revenues from solving congestion or from avoiding grid related wind curtailment 11. When combined with wholesale power arbitrage and reserve power revenues, this could make individual storage projects more attractive if they are located at the right place within the grid. Conclusions from the questions and answers 1.33 Significant changes in the Dutch generation mix are expected in the next decade: there is likely to be a strong increase in new conventional generation alongside substantial volumes of additional wind power. Estimates show that these developments, to the extent envisioned in our scenarios, can take place simultaneously without any significant wind curtailment, even in low load hours. However, the system appears to be close to the edge. Therefore, creating optimal flexibility conditions in the CWE market is crucial to integrating wind power further The most important sources for flexibility are shown in Figure Please note that we used price estimators based on short run marginal costs for this study. This tends to underestimate peak prices and thus tends to underestimate the value of storage. We also used cost based prices for reserve capacity which also tend to be lower than ancillary service prices in reality. 11 Here also regulatory rules are important. Executive Summary

22 12 Frontier Economics April 2010 Figure 5. Flexibility options and indicative ranking Action points Importance Integration with CWE Increase usable exchange capacities Physical (international) interconnectors Strong internal grids (NL, DE) Efficient allocation of capacities close to delivery Very high Flexibilize conventional system Reduce must run Nukes and CHP contribute to ancillary services Flexibilize CHP plants Conventional coal needs to contribute High Storages Storages become attractive if points above are not used weak grids (extra revenues from grid congestion), high downward reserve prices Secondary Option DSM Demand side should contribute We account for 300 MW manual reserve from DSM, We did not model DSM but from our experience the practical potential is limited. Not analysed in detail here Source: Frontier 1.35 In this study we did not model demand side flexibility options. However, if end users are entitled to contribute to system flexibility, they will need adequate technical means and appropriate price signals (e.g. using smart metering and a innovative tariff structures) In addition, the flexibility that can be provided from renewable generation sources should be used. In terms of wind power this includes incentives for improved forecast quality and grid orientated location of wind plants (provide incentives to take into account potential grid extension costs when choosing the best wind sites). Wind should also be incentivized to provide ancillary services as far as they are technically able to do so 12. Other renewables which can be dispatched (biomass, geothermal) should receive price signals from the power market. However, those sources will not play a key role in the Netherlands in terms of generation quantities The challenge of wind integration lies in making the power system as flexible as possible. This needs to done in combination with market integration and optimal use of interconnection capacity to handle fluctuating wind power in the CWE electricity market (see Figure 2) Firstly, it is important that the cross border power exchange capacity is used optimally and is made available to market players. This includes, for example, a sound understanding of international load flows (requires high degree of 12 Providing downward reserve or reactive power from wind units can be valuable particularly in times where only a limited number of thermal plants is producing. Executive Summary

23 April 2010 Frontier Economics 13 coordination between TSOs) which may allow for more efficient grid utilisation than a standard approach assuming typical load situations. However, grid security requirements should, of course, always be taken into account International market integration will require policy backing so that those who need access to flexibility can obtain it from those who have more than they need. This can involve the following: new interconnection capacity projects based on regional planning and inter TSO co-operation, as envisaged in the third energy package (but only helpful if internal congestions is also resolved); the realisation of the planned day ahead coupled market in CWE and the introduction of flow based market coupling to make best use of existing interconnection capacity; the development of day ahead market coupling between the Netherlands and countries linked by HVDC links (GB and Norway) 13 ; the development of an integrated and continuous intra-day market to manage short term variations in intermittent output and pool flexibility sources in the CWE region (make flexibility sources available to the whole CWE market through improved usage of cross border capacity) 14 ; and the development of arrangements to permit international participation in balancing markets to help keep the costs of exposure to imbalances as low as possible Secondly, maximizing flexibility of conventional supply is required. A broad portfolio of technologies has to contribute to this: conventional thermal power plants (coal/gas) need to adapt to start/stop and partload operation; new nuclear generation can also contribute to system flexibility by providing tertiary reserve; and CHP plant will need to become more flexible by shifting heat production to alternative sources (e.g. heat-only-boilers, heat buffers) in order to decouple electricity output and heat demand to a greater extent than is now possible. 13 Only helpful if the HVDC links can change flows within their full technical capability. 14 If high volumes of wind capacity limit price convergence in the coupled day- ahead market, it may be necessary to review the proportion of cross-border capacity that is allocated through implicit auctions at the day ahead stage and that which is allocated on a monthly and annual basis. Executive Summary

24 14 Frontier Economics April We think that, for the most part, price incentives will be sufficient to achieve these changes but some measures may be needed to ensure that CHP plant participate in the market so that the owners can respond to these incentives. This includes also negative prices for hours when supply exceeds demand. Negative prices can be an important incentive for plant operators to adapt their production mode to low demand Market developments should be observed carefully to ensure that unintended effects from existing policy measures do not disturb an adequate capacity balance of the system A key point will be to address the problem of economic viability of new conventional generation which runs the risk of operating at low load factors due to the increase in wind capacity. To some extent, this can be addressed by building more peaking plant. However, under the prevailing market model in which both energy and capacity are remunerated through payments for energy production, plants need sufficient operating hours to receive their required revenues. Further research will be needed to analyze those effects and to develop an adequate incentive scheme (Could capacity markets be an option? Do ancillary service markets provide enough incentives? Or do wholesale prices already provide sufficient incentive for new investments?) 1.44 To sum up, with regard to the existence of flexible resources, we do not see any direct need for new policy measures in the Netherlands to mandate specific actions, with the possible exception of taking additional steps to encourage market participation by CHP plant. However, existing policies in support of stronger interconnection with neighbouring countries will need to be pursued strongly at national and regional level. Annex to the Executive Summary: Details on our modelling Approach General approach 1.45 We considered two basic scenarios: a base scenario with 12 GW of wind generation capacity, split 50:50 onshore and offshore; and a low wind 6 GW scenario (4 GW onshore and 2 GW offshore) in order to study the impact of a significant increment of wind capacity We used a system dispatch tool to simulate operation of the Dutch, German, Belgian and French power systems (the Central West Europe or CWE region) in We also took account of interconnection with satellite regions such as Scandinavia, Poland, Alpine countries and Spain, although these were not modelled in detail. The model uses a linear/mixed integer program solver to find Executive Summary

25 April 2010 Frontier Economics 15 the least cost dispatch of the system subject to a number of constraints. The focus of scenario definition was on fuel, carbon emissions and other variable costs of generation. We did not consider fixed operating and maintenance (O&M) or investment costs With help from EnergieNed and Nuon, we collected detailed data about the Dutch plant park, including conventional and CHP units. We identified those CHP plants which appeared to have flexible power to heat ratios and captured this flexibility in the logic of the dispatch tool. Each CHP plant was modelled to have some associated Heat Only Boiler (HOB) capacity that optionally can be used to cover parts of local heat demand We used a recent load forecast prepared by the Dutch transmission operator TenneT to the year 2016 and extrapolated it to The model optimises dispatch for the CWE region in one hour time steps, subject to interconnection capacity constraints, taking account of randomised wind generation output. In this sense the model has perfect foresight and assumed perfect market integration within the assumed cross border limits All modelling and analysis was carried out at constant 2009 prices. We did not consider the effect of inflation We separately gave consideration to the market dynamics required to ensure that the rights to the available flexibility could be reallocated efficiently to those needing flexibility from those with surplus flexibility. Assumptions on power plant system 1.52 We projected the non-wind plant park in the Netherlands on the following basis: we took data on the capacity and commissioning date of existing plants on the system; we projected plant retirement using standard lifetimes for different technologies; we added plants under construction at the expected commissioning date but assumed that by 2020 two of the coal plants would be deployed as IGCC, one with CCS; we added a nuclear plant of 1000 MW to reflect the impact of a possible extension of nuclear capacity; and we added a 100 MW Compressed Air Energy Storage (CAES) plant in order to evaluate to what extent it would be economic to operate We assessed the adequacy of the projected capacity using a UCTE type methodology that compared capacity after derating for outages and planned unavailability (90% of nameplate capacity for thermal plant and 10% for wind Executive Summary

26 16 Frontier Economics April 2010 plant) with forecast demand plus reserve requirements 15. On this basis the above projections imply a small surplus in capacity over what would be considered adequate by 2020 to meet demand and allow for sufficient flexible reserve capacity to ensure stable supply of electricity. Owing to the use of a 90% derating factor for wind generation and the assumption that 10% additional reserve is needed for wind capacity in excess of 6 GW, the plant park has the same level of adequacy under both scenarios Capacity development in the other countries in the CWE area was assumed similar for both scenarios and follows market estimates by Frontier based on national energy policies (in particular for renewables and nuclear), standard plant life times and filtered announcements of new built plants. The scenario includes further growth in wind in NW Europe (both onshore and offshore) as well as life-time extension of existing nuclear capacity in Germany and Belgium. Assumptions concerning CHP 1.55 We derive CHP capacities in 2020 by applying standard lifetimes for existing CHP plants and analysing new built capacities. Total CHP capacities are slightly lower than today. This is consistent with decreasing heat demand in the Netherlands as a result of improved energy efficiency We distinguish between flexible CHP plants with variable power-to-heat ratio and CHP plants with a fixed power-to-heat ratio. We assume typical heat demand profile for industrial CHP plants, district heating plants and greenhouse CHP. CHP plants can provide flexibility by decoupling power and heat demand using heat only boilers (HOBS); or changing the power-to-heat ratio (flexible CHP plants only). Details on assumptions for power plant parameters can be found in the annexes to the full report. Assumptions concerning reserve requirements (ancillary services) 1.57 Based on our understanding of current TenneT policies on reserve and thinking of how they might evolve, we assumed that with wind capacity of up to 6 GW the manual reserve requirement would be dictated by the largest single infeed that could be lost. For incremental wind generation above 6 GW, we assumed with reference to studies for Germany and the UK - that additional manual reserve 15 The derating methodology accounts for the fact that at time of highest annual demand not all installed plant capacity will be there to cover this peak demand. Some thermal plants will be unavailable due to revisions or outages. Generation source relying on volatile weather conditions like wind, solar radiation or water levels can not be accounted as guaranteed wind plants for example are derated down to 10% of installed capacity being accounted as guaranteed available. This methodology is in line with various system adequacy studies (e g the dena grid study calculated the capacity credit for wind to be around 5-15 %depending on wind penetration levels). Executive Summary

27 April 2010 Frontier Economics 17 equal to 10% of the additional wind capacity would be needed. This gave us a requirement for manual reserve to be provided by the power plant system of 1300MW by 2020 (compared to 700MW today) 16. Assumptions concerning the grid 1.58 Concerning the capacities available for physical power exchanges to and from the Netherlands by 2020 we assume for our base case that: the net transfer capacity between the Netherlands and Germany available to market players will be 3700MW. This means that existing lines can be used to a more efficient extent than today as bottlenecks close to the border will be removed and market design allows for a more efficient use; and a new link Wesel- Doetinchem will be available from 2013; the net transfer capacity between the Netherlands and Belgium available to market players will be 2300MW; and there will be no internal grid constraints within Germany or the Netherlands by Sensitivity runs In addition to both scenarios, we also analysed a number of sensitivity runs on the 12GW scenario to explore the impact of changing key variables. We looked at an increase in manual reserve requirements; less interconnector capacity with Germany and from Germany to the Alpine countries and to Eastern Europe; an increase in the interconnector capacity to France via Belgium; higher coal prices sufficient to make most combined cycle gas turbines (CCGT) plant a cheaper source of electricity in most months of the year; and a constraint that prevented coal-fired generation from operation below minimum stable generation i.e. no stops and starts. 16 For both cases we assume that demand side continues to contribute 300 MW of manual reserve to TenneT as it does today. Executive Summary

28 18 Frontier Economics April We derived fuel price assumptions from recent international projections of crude oil prices and typical relationships between oil, coal and gas prices.. Executive Summary

29 April 2010 Frontier Economics 19 2 Introduction 2.1 In the context of the adoption of the EU climate change package, the Dutch government is aiming at the introduction of some 12 GW of wind generation capacity by 2020 as a key measure towards meeting the requirement to have renewable energy in all sectors (electricity, heat and transport) equal to 14% of final energy consumption. The wind capacity will be located onshore and, increasingly, offshore. The plan implies a very rapid increase on the current installed capacity base of 2.1 GW in December While this policy has been in development, the power sector has attracted substantial new investment in thermal generation capacity, making it increasingly likely that the Netherlands will evolve from its current status as a net importer to a net exporter of energy. The projects that are under construction or proposed include new coal and gas fired plants and a new nuclear plant. These investments, when combined with the aim for wind generation capacity, would lead to a significant surplus in power generation capacity beyond what is needed to meet Dutch demand securely unless some of the investments are deferred or older plant retired before the end of their standard lives. 2.3 These developments have led to debate about the compatibility of the planned development of the thermal park, based on investment plans by individual utilities, with the policy decisions taken in relation to wind generation. The key areas of concern relate to: the issue of whether sufficient flexibility will exist in the power market to permit the intermittent and uncertain wind infeeds to be accommodated without load shedding or expensive wind curtailment; and what will be the impact on power prices and thus on the business cases for new investment. Scope of work 2.4 In order to gain more insight into these issues, EnergieNed, on behalf of its member firms, has appointed Frontier to carry out a study of the year 2020 in order to explore the ability of the Dutch and North West European power markets (corresponding to the region known as Central West Europe (CWE)) to handle fluctuating wind power and its implications. By simulating the operation of the power market in 2020 under a small number of scenarios, and conducting related analysis, the study is intended to answer the following questions: Introduction

30 20 Frontier Economics April 2010 What is flexibility can it be defined or quantified? Will the Dutch and/or CWE market be able to handle fluctuating supply of significant amounts of wind power through market dynamics? Which role do the CWE market and market coupling play? What will be the impact of fluctuating wind power on electricity prices in peak and off-peak hours? How might this affect the case for investing in new plants? What will be the impact of fluctuating wind power on required reserve capacity? Is there an impact on energy saving from CHP (negative or positive)? If so, can this be quantified? Is there any ground for arguments such as CHP as perfect partner, the need of storage, only IGCC in case of new coal? Are there any other policy relevant implications which have to be addressed? Is there a need for additional policy measures and which? 2.5 The modelling and analysis presented in this report attempts to answer all of these questions. 2.6 The terms of reference also asked us to review experience in other EU countries with high rates of wind integration and CHP, especially Denmark. We have in addition considered Spain and Germany. 2.7 The study is also closely related to two other, currently ongoing 17, studies which are being conducted in parallel. These are: the KEMA study of the need for Large Scale Energy Storage in the Netherlands; and the Ministry of Economic Affairs study on fuel mix in the generation sector by The study is also of interest to the Ministry of Environment which is responsible for meeting the 2020 objectives aimed at limiting climate change. 17 There is no full citation of this study available yet. Introduction

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