Risks and Solutions for Integrating Large-Scale Intermittent Renewable Sources into the EU Electricity System by 2020

By Marcel Cailliau, Marco Foresti,and César Martínez Villar

Digital Object Identifi er 10.1109/MPE.2010.937596© PHOTODISC

AAMBITIOUS TARGETS HAVE BEEN SET BY the recently adopted European renewables Direc-tive 2009/28/EC, which aims to promote the use of energy from renewable sources by establishing an overall quota of a 20% share of renewables in gross fi nal consumption of energy by 2020.

In terms of electricity generation, it is generally expected that the share of renewables will be much higher than the 20% target (reaching 30–35% of overall European Union (EU) generation sources, according to most estimates) and that the increased production of renewables will be to a large extent based on intermittent and unpredictable sources such as wind and solar power. Of all generation from renewable energy sources (RES) in 2020, wind power (42%) and photovoltaic (PV) power (4%) are expected to represent almost 50% of the installed capacity. Compared with hydro and bio-mass generation (estimated at around 31% and 22% of total RES installed capacity in 2020, respec-tively), which are fl exible and relatively controllable energy sources, wind and solar generation will be far more challenging to integrate into the system. It is therefore these two forms of renewable energy

september/october 2010 IEEE power & energy magazine 531540-7977/10/$26.00©2010 IEEE

54 IEEE power & energy magazine september/october 2010

that will have the greatest infl uence in reshaping electricity markets and grids over the next decade.

The resulting increased amounts of intermittent produc-tion will have signifi cant and far-reaching effects on both the electricity market and transmission grids. The purpose of this article is to analyze these impacts and recommend appropriate responses to policy makers.

As was originally intended, the increase in the amount of renewable energy will lower the need for generation from fossil-fueled power plants. It will also dramatically affect the way the remaining conventional power plants are operated, however. Base load plants, including those utilizing low-carbon technologies such as nuclear plants and fossil-fueled plants with CCS, may have to be operated intermittently if the European transmission system has not been suitably adapted. While fl exible conventional power plants will still be required well into the future, these will be operating for fewer hours than similar plants in today’s market, and there will be greater requirements for ancillary services to balance the system and redispatch services to deal with transmission congestion.

Considering all of these impacts and the subsequent need to integrate larger market areas to minimize ineffi ciency, there is an urgent requirement to expand and reinforce the transmission system and integrate markets. This article describes the possible adverse consequences to markets should the required investments not be made in time.

Security of supply may also be affected in a number of ways. Increased amounts of renewables will result in a reduction of fossil fuel imports and reduced profi tability for remaining conventional power plants. This in turn can lead to insuffi cient investment and the failure to develop a secure system that delivers low-carbon emissions (particularly if electricity markets are not allowed to function effectively as a result of inappropriate regulatory interventions, for exam-ple). It is also expected that short-term volatility will increase due to the very different merit curves that can be produced by weather-dependent RES (e.g., on a windy, sunny day and on a cloudy day without wind).

Most important, this article highlights how market inte-gration, a policy goal per se set by the EU, becomes even more urgent and indispensable to ensure a sustainable and secure power system in the face of increasing levels of intermittent generation. Renewables targets and security of supply standards should not supersede the creation of a single EU market but rather be part of the same strategy: we believe none of the three EU energy policy objectives can be reached without the other two.

Some Basic Assumptions The main result of this article’s analysis is that the devel-opment and accommodation of renewable energy is only possible with the speedy introduction and effective imple-mentation of market integration.

To focus on the key issues related to the integration of high levels of intermittent RES by 2020, we fi rst set out the following fundamental assumptions that formed the basis of this work:

The EU 2020 targets for renewable energy should and ✔

will be met, and consequently the share of RES for elec-tricity generation will grow to 30–35% of the total.For generating installations using RES, priority of ✔

dispatch—included in Renewables Directive 2001/77 and subject to secure network operation—will bring as a consequence that other generation sources (nucle-ar, coal, gas, and oil) will at times have to be regulated downwards to keep the system in balance. In addition, they must also be available to satisfy electricity de-mand in the event that intermittent renewables are not available as expected.In terms of total capacity, as reported by EWEA ✔

(TradeWind/EWEA, 2009), wind generation is ex-pected to grow from 65 GW in 2008 to 140–210 GW in 2020. This means that in the next ten years, the sys-tem will see new wind generation amounting to twice (or three times) what is already connected today.The concentration of suitable sites for wind generation ✔

is located far from the off-take. This will mean that certain regions may not be heavily affected by future wind development while others will experience radical impacts. At the EU-wide level, location of wind and solar generation will also obviously depend on the dif-ferent national allocation plans and on the differences among the various domestic support schemes. While historically (i.e., in vertically integrated companies) generation was built near the load, this is no longer true, especially for offshore wind farms. Increasing levels of wind generation will thus by defi nition exac-erbate the loop fl ows in the system due to the fact that injection does not occur at the site of off-take.

Wholesale Market Price Dynamics

Short-Term Price VolatilityAs known, the marginal generation costs for wind energy are very low. Depending on the amount of expected wind energy,

This article highlights how market integration becomes even more urgent and indispensable to ensure a sustainable and secure power system in the face of increasing levels of intermittent generation.

september/october 2010 IEEE power & energy magazine 55

there will be a different structure of marginal costs in the market and, as a consequence, a shift of the supply curve (see Figure 1). Depending on the wind injection and the actual supply and demand curve of other market participants, prices will change much more from hour to hour compared with a case without wind injection. Thus, short-term price volatility will increase.

While conventional plant oper-ators can make reliable estima-tions as to how long their plants will run in a regime without intermittent injection, this becomes much more diffi cult in situations where the merit order across the hours of the following day is less predict-able. This will by defi nition lead to a less-than-optimal dispatch of their units, and some additional costs and risks (e.g., greater start/stop costs) must be taken into account. These in turn increase the variability of the prices on the supply curve.

Some argue that the hourly variation in wind production is smaller when the wind output (in particular from offshore wind farms) is aggregated over more wind plants, due to the portfolio effect. This is true as long as the market size is large enough to absorb a considerable wind power portfolio. Furthermore, making use of the portfolio effect will require strong interconnections between markets in order to optimize the uptake of intermittent power sources like wind. Only when the different wind farms are pooled or interconnected with each other or when it is possible to share the regional (smoothed) injection from the sum of the wind farms over all market places together (i.e., in a noncongested network) may it be expected that there will be a reduction in price volatility due to the intermittency of the wind.

Negative PricesIncreasing injection of RES will lead to more periods of time (mainly during weekends and especially during night hours) in which there is a combination of a very high injection of wind energy and low demand for electricity.

As a consequence, conventional plants will have to be regulated downwards. These plants cannot operate below a certain technical minimum output, however. The only way to further reduce production below this technical minimum is to shut them down. These plants operate under other con-straints as well, such as minimum permitted downtimes, ramping rates for upward and downward regulation, and so on. In certain situations it could make sense for such gen-erators to keep their plants running by bidding in negative prices, because it would still be cheaper to pay “somebody” for taking the energy than to stop the plant and start it up again shortly thereafter.

To deal with this issue, some power exchanges have already introduced negative price boundaries (e.g., EPEX Spot and Nord Pool Spot). Another reason oversupply occurs is that specifi c plants must often be kept running for system stability, regulating power, and so on: the more intermittent injection occurs, the more such “must-run” plants will be needed, exacerbating the oversupply problem.

The occurrence of negative prices may result in negative societal consequences. From a social perspective, it would make more sense to curtail wind generation than to keep it online with negative prices—sometimes very extreme ones—as a result. Support schemes should be designed or adjusted so that wind generators have the incentive to dis-connect or reduce their output when it is not economical for the society to keep it online.

Strategies for Mitigating Negative Prices

Support SchemesThe individual EU member states have their own renew-able energy targets. Support for renewables is necessary to achieve these objectives, and each member state decides how best to design its national support scheme.

Having the appropriate support scheme in place could create incentives for fi nding the right balance between creat-ing negative social consequences and facilitating the desired amount of wind generation investments. Indeed, if some portion of wind generators’ revenue depends on the market price of the energy produced, wind generation investments may be delayed due to higher market risks.

Differences in support schemes among member states can also result in distortions. Wind generators may not invest at those locations where the renewable production is optimal but rather at locations where they can maximize their ben-efi ts. This would lead to a concentration of low-marginal-cost generation in certain member states that would sooner or later run into a lack of grid capacity, increasing balanc-ing costs and resulting in negative prices. There would then be a need for additional grid, balancing, and backup facil-ity investments. Clearly, it would make more sense to avoid

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figure 1. Shift of the supply curve due to RES in-feed.

56 IEEE power & energy magazine september/october 2010

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figure 2. Day-ahead wind forecast (blue), actual in-feed (green), and day-ahead forecast error (red) in the German electricity system, 11–24 November 2009. (Source: EEX and BDEW.)

such a scenario by ensuring that similar support schemes are applied in neighboring markets, thus guiding the invest-ments to locations where wind production is optimal with respect to local market prices.

Market MechanismsThe market can put in place appropriate mechanisms to cope effi ciently with negative prices, should they become more structural.

With the development and introduction of smart grids, household customers will be able to “see” the negative spot prices and so receive direct signals to respond and adjust their consumption accordingly, depending on the type of supply contract. For these reasons, regulated end-user tariffs should be eliminated, since they do not allow for such sig-nals to be acted upon.

Negative prices will also stimulate investments in various types of “electrical energy storage” facilities, which consume electrical energy when prices are low and deliver it back to the grid at times when prices are high (pumped storage is a good example). They will also stimulate investments in plants able to provide greater fl exibility, via features such as lower mini-mum plant output levels, lower start/stop costs, and the like.

Market DesignWe also note that there are some additional administrative hurdles with regard to negative prices. In some markets negative prices are already implemented, while in others they are prevented (though they maybe introduced in the future). Therefore, when markets are integrated in the day-ahead phase via market coupling, there is no convergence

between the price from the nega-tive price area and a neighboring price area where there is not yet a negative price boundary on the power exchange, despite the avail-able cross-border capacity that is not being fully used. For these reasons, the development of com-mon market rules that prevent the introduction of distortions when joining offers and interchanges of energy is strongly recommended.

Transport CapacityThis brings us to a more struc-tural way to avoid negative prices: regions with abundant low-price injection should be provided with suffi cient grid capacity to “export” low (and especially neg-ative) prices to other price areas. With reference to the actual RES impact considered from a Euro-pean market perspective, it can

be said that in general, negative prices would probably not occur if there were no grid constraints.

Balancing MarketsTraditionally, the amount of balancing energy, or reserve, provided by controllable thermal or hydro generation had to be sized to balance variations in demand or forced outages of the largest production unit. Therefore, the reserve was mainly required for upward regulation. A large penetration of intermittent—in particular, wind—generation introduces additional requirements for balancing products and services. The reasons are twofold:

Wind generation has a limited predictability. In or- ✔

der to cope with forecast error, larger amounts of fl exible sources are necessary. This forecast error can be either negative or positive, thus requiring not only upward but downward regulation. (It should be noted that, in general, there is a portfolio effect that partially reduces the wind forecast error by consid-ering the cumulative output from all wind farms as compared with the forecast error from an individual wind farm.) The predictability of wind generation will improve ✔

over time. But even with perfect forecasting, wind generation will remain intermittent (in other words, noncontrollable) and very variable from one hour to the next. For this reason, additional fl exibility is required.

The consequence for electricity systems with a high penetration of wind generation is a higher exposure to problems related to the grid stability. The availability of

september/october 2010 IEEE power & energy magazine 57

an appropriate amount of reserve power plants and their fl exible dispatch becomes increasingly im -portant to provide the necessary ancillary services.

Some Evidence and Examples The lack of fi rmness of wind generation (i.e., its intermittency) and the lack of forecast precision (with respect to the day ahead) is refl ected in Figure 2, related to the German situation. Between 21 and 23 November 2009, wind injection in the German system in-creased from a few hundred MW to about 20,000 MW. During the same period, it can be observed that day-ahead forecast er-rors of between 22,000 and 13,750 MW occurred. It is also worth noting that on 24 November there was a high level of wind generation during off-peak hours; it was reduced by about 7,000 MW during peak hours.

There are also a small number of instances where the dif-ference between the real and forecast wind production is a result of wind generation being limited by the over-speed protection feature of wind turbines (activated when the wind blows at high speeds). The graph in Figure 3 shows one such instance, where there was a difference of over 6,000 MW between forecast wind generation and actual production in Spain over a two-day period.

In the future, wind generators clearly need to be sub-jected to similar levels of technical requirements as con-ventional plants in order to prevent risks to system security and to meet qualitative standards of supply (with respect to voltage, frequency, and so on). This includes the mandatory implementation in wind turbines of devices to support the resistance to voltage dips and prevent situations in which small (local) disturbances in the network entail a large loss of wind generation.

Higher Reserves and Adequate Cost AllocationOne important point is that TSOs will need to procure higher amounts of reserve as compared with a system of similar size but without intermittent (wind) generation. In their 2009 report, Frontier and Consentec indicate that based on experi-ences in Germany, Spain, and Portugal about 0.25–0.3 GW of additional reserve per GW of wind capacity added to the system is required. Evidence from Germany shows that at present, 7.5 GW of upward reserve and 6 GW of downward reserve are contracted, while the largest conventional pro-duction unit has a capacity of about 1.5 GW.

These additional requirements imply an increasing amount of mandatory dispatching of thermal units. This reduces the capability of generators to manage their portfolio (trading

with these units is limited) and thus reduces the offers on the commodity market.

Costs to reserve the band of secondary regulation and the additional spinning reserve for tertiary purposes are social-ized in most markets through system tariffs, which means that there is no price signal to the intermittent generators that refl ects the higher requirements of fl exibility in the system. In order to keep the fl exibility necessary—regulation up and down—it will be necessary to place some specifi c (peak) plants in a must-run position, although they are out of the money. The must-run costs have to be covered by system charges. Therefore, higher wind penetration may not only affect the costs for balancing the system (as indicated in the previous paragraph), but depending on the location of the wind generation, higher congestion management costs via redispatching could also be incurred.

Review of the procurement of all required ancillary ser-vices is highly recommended in order to preserve an adequate cost allocation. Otherwise, the costs of new requirements could well be hidden in existing services.

Applying the Same Rules for All GeneratorsThe experience in Spain shows that making wind generators subject to the same balancing and scheduling obligations as conventional power plants does not signifi cantly jeopardize the development of this technology. On the contrary, this seems to be the best way to stimulate improvements in fore-casting methods. As a result, system balancing requirements can be reduced, and costs are fairly allocated.

Priority of dispatch and guaranteed network access for RES generation as required by the new RES directive should not exempt these generators from their schedul-ing and balancing obligations. Otherwise, full integration of wind generation in the market and competition with other types of generation will never occur. Wind genera-tion development should be promoted through the “regu-lar” support schemes and not through specifi c grid and

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figure 3. Wind forecast at system level (green), wind schedule based on generator s bids, and actual wind in-feed in the Spanish electricity system, 23–24 January 2009. (Source: Red Eléctrica de España.)

58 IEEE power & energy magazine september/october 2010

market arrangements (including congestion management arrangements) that could generate adverse effects and market distortions.

Best practices reveal certain measures to ensure a proper integration of wind generation in the markets. These include the adscription of wind farms to centralized control centers, which allows the system operator (SO) to monitor and control RES power and to collate real-time measure-ments of its production in order to perform real-time secu-rity analysis and enable the coordination of all associated balancing actions.

Errors in the forecasting of day-ahead wind generation have decreased in the last few years, but the error rate is still much higher than when the forecast is made a few hours ahead. Figure 4 gives an idea of the level of error in wind generation prediction when forecasts are made 48 hours in advance. The fi gure also shows the improvement of forecast techniques over the years.

As a general principle, increasing trading possibilities via continuous intraday trading after the day-ahead session of the market allows the market to benefi t from more up-to-date and accurate forecasts. As a consequence, the amount of ancillary services needed to balance the system is less and the cost for society lower. Integrating cross-border intraday markets with continuous trading can contribute greatly to a more effi cient integration of wind energy.

Impact on New and Existing Generation InvestmentsThe purpose of this section is to mention the main impacts and system requirements that the introduction of high levels of RES might imply on the electricity generation activity and point out some paths that will defi nitely contribute to security of supply and electric system effi ciency.

System Requirements for a Large Share of Intermittent Generation

The Need for Investment in Backup Capacity It is commonly accepted that wind is primarily an energy resource and not a capacity resource, with its key value

being the offsetting of fuel con-sumption and thus a reduction in emissions. To support this state-ment, Figure 5 shows the load fac-tor duration curves, on an hourly basis, for the Spanish and German electricity systems during 2008. Load factor should be understood as the ratio between actual pro-duction and installed capacity on an hourly basis. These examples cannot, of course, be generalized to all European markets, and they also depend on the actual yearly

wind production. For purposes of comparison, installed wind capacity reached 16.4 GW in Spain and 23.46 GW in Germany in 2008.

The fi gure shows great similarities between both sys-tems as far as the behavior of the load factor of wind production is concerned, which permits us to draw some general conclusions:

On average, only 3.9% (2.5% in Spain and 5.5% in ✔

Germany) of the total installed wind capacity has a level of fi rmness of 95%, the reliability of convention-al power plants. Only a small share of wind capacity can thus be considered “fi rm.” Therefore a consider-able amount of conventional capacity is needed as fl exible backup generation.Around 55% of installed wind capacity (50% in Spain ✔

and 60% in Germany) has a level of fi rmness of less than 5%. In fact, the level of injection of wind gen-eration never exceeds 77% of installed capacity (this limit is higher in Germany but lower in Spain), so 23% of installed wind capacity can be considered as fully unavailable.On average, the expected working rate of wind capac- ✔

ity has a 90% probability of oscillating between 3.9% and 55%, with an average load factor of 21.74%.

Practically speaking, every MW of wind capacity requires 1 MW of backup fi rm capacity in order to ensure 90% avail-ability. This leads to another important conclusion: invest-ments in wind generation reduce fuel expenses but it does not prevent investments in fi rm backup capacity.

The backup capacity could be provided either via life-time prolongation of existing plants or by investment in new plants. The prolongation of existing plants may however require substantial investment in cases where plants are not compliant with Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large com-bustion plants.

The Need for Market Design Rule ChangesThe reduction of load factor, due to priority of dispatch of RES plants, will weaken the ability of existing conven-tional plants to recover fi xed costs and may lead to earlier

Wind Forecasts Evolution, 2005–2008 (Data from Red Electrica Espana)4035302520151050

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figure 4. Wind forecast errors. (Source: Red Eléctrica de España.)

september/october 2010 IEEE power & energy magazine 59

decommissioning decisions. Simi-larly, prospective investors in new conventional generation ca-pacity will be facing increasing uncertainty, which, all else being equal, will naturally weaken their appetite for investments in these technologies.

Markets should work and fi nd the equilibrium market price, pro-vided that prices are allowed to change freely, that policy mak-ers’ interventions do not affect market equilibrium, and that authorities that regulate compe-tition accept the “price spikes” that will emerge. Nevertheless, in some cases, the uncertainty faced by investors about the magnitude and frequency of “price spikes” may hinder the evolution of the conventional gen-eration park. In this case, market design rules may need to be reviewed.

The Need to Adapt the Generation MixVarious studies show that the amount of base load produc-tion that provides an economical equilibrium on invest-ment steadily declines as wind penetration increases, increasing at the same time the reliance on low-capital-cost technologies. If this proves to be true, more fl exible plants—using technologies such as hydroelectric, pumped storage, open-cycle gas turbine (OCGT), and combined-cycle gas turbine (CCGT)—will be required. While it may be technically possible to provide some of the required future fl exibility through modifi cations to existing plants, investors will again be faced with the uncertainties already mentioned, which might prevent the investments from being made.

The need for fl exibility may be satisfi ed in many ways, most of them embodying technological developments. For instance, investments might be made to allow for a quicker response (faster ramping speed) from conventional plants to provide support to the system or to reduce the plants’ mini-mum operating levels from the usual values. Other ways of providing increased fl exibility to the system include invest-ing in variable-speed pump turbines.

There are other technological solutions that can provide the needed fl exibility to the system but that fall outside the

scope of generation activity, e.g., “smart” domestic appli-ances or other demand-side management (DSM) instru-ments. These can also be adopted and incentivized.

The Need for StorageWith the introduction of large amounts of RES into the gen-eration mix, storage should play an important dual role. It will be a source of effi ciency, as it allows the capture and storage of RES for later use, thus preserving resources. It can also be a valuable instrument for providing the fl exibil-ity discussed above.

The increase in storage capacity is possible with the help of various technologies, for instance, through pump-ing plants, gas storage, district heating systems, and elec-tric-vehicle-to-grid systems. The market price differentials that may come with increased RES penetration are the primary market signal for the need for storage. Therefore, constraining caps (and fl oors) limiting price variations should be lifted.

In particular, the occurrence of negative prices is a signal that additional storage is welcome, as storage actually results in “consuming” additional electricity at negative prices. This avoids the social welfare loss by saving the electricity until it again has value.

The investment decision to build new or expand exist-ing pumped storage plants not only faces cost recovery risk (like any other investment decision) but could also be further jeopardized by problems related to construction permits, however.

Load Factor Duration Curve of Wind Generation (Germany and Spain, 2008)9080806050403020100

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figure 5. Load factor duration curve of wind generation in the German (blue) and Spanish (pink) systems in 2008.

The main goal is to reduce the complexity of the authorization procedures for building both new internal and cross-border connections in order to speed up grid investments.

60 IEEE power & energy magazine september/october 2010

Security of Supply and System Efficiency

Need to Remove Price Caps and FloorsAs illustrated above, in order to preserve system backup capacity, adapt existing plants so they are more fl exible or build new plants, and keep suffi cient fl exibility in the system (with more fl exible plants or storage), investments will be necessary. But with more volatile prices and lower power load factors, investment decisions become more and more uncertain.

Most European markets nowadays are “energy-only” markets. Some are complemented by capacity reservations on behalf of the TSOs, while others have capacity incentive schemes in place.

Under the energy-only market design, investors in new generation (especially peaking generation) must be able to fully anticipate and receive the actual level of scarcity rents over time if they are to correctly match the level of new investment with system requirements. These scarcity condi-tions by their very nature are hard to predict, as they depend on the frequency and length of very short-term supply-de-mand imbalances caused by weather, intermittent genera-tion, plant outages, and other uncertain events.

Policy makers are generally uneasy about allowing investment decisions critical for system reliability and pub-lic economic welfare to be driven solely by expectations of scarcity rents. Therefore, price and bid caps have been intro-duced in some markets. These artifi cial limits often elimi-nate the scarcity pricing signals and rents on which energy-only market design is based. With these caps in place, the long-term investment prospects of an energy-only model might be insuffi cient. One conclusion seems to be clear: in energy-only markets, price spikes must be allowed to occur freely, both in magnitude and frequency.

CCGT plants, roughly speaking, need a market spread of about :10/MWh to cover their fi xed costs if they run 5,000 hours per year. Intermittent renewables growth could reduce the number of running hours to somewhere around 2,500 hours or less. This would require that during the peak hours about :10/MWh of additional market price be created; if not, such CCGT plants would no longer be built. It should however be noted that this fi gure gives only a very rough indication. Individual investors will conduct more in-depth analyses, taking into account their portfolios, the markets where plants are located, and so on. Governments, competi-tion authorities, and consumers will have to accept the need for the increased market spread. Only in this way will the

conditions for the effi ciency of the energy-only market design be met and its benefi cial results achieved, especially where the need for backup and fl exible capacity is concerned.

The level of acceptance of price peaks that could incen-tivize investments in peak capacity varies greatly within Europe. As one example, the Swedish regulator, together with the national TSO and energy agency, has declared that price peaks show that the market is functioning and provide incen-tives for large consumers to lower consumption and genera-tors to invest in peak load capacity. In other parts of Europe, there is a very low acceptance of price peaks.

Plant investment will only occur if investors expect market prices to reach appropriate levels with sufficient frequency, however. This may not happen if tight caps are implemented.

The Role of Capacity Investment IncentivesIf suffi cient revenues cannot be recovered in the energy mar-ket to support needed investment or keep existing capacity running, a fallback solution may be required. Such mecha-nisms are generally based on the concept of two-part pric-ing, with one set of revenues paying for energy on a :/MWh basis and another rewarding capacity on a :/MW basis. In theory, these mechanisms allow the primary energy mar-ket to operate undisturbed while recovering the “missing money” needed to support new investments through capac-ity payments made outside the energy market (these may assume the form of competitive capacity mechanisms or auctions). Such mechanisms should be designed so that the payment amount is directly linked to the need the system has for capacity or fl exibility and valued by the market at the time of the investment.

Moreover, the existence of capacity payment mecha-nisms may mitigate price spikes. As has been noted, spikes are usually a source of worry for governments and competi-tion authorities.

Different capacity incentive models could be considered. Careful analysis is required to assess in which cases, under which conditions, and at what geographical scale it may be advisable to introduce such models. This is in particular true in the European market, where the electricity system is strongly meshed and where the interference between the national markets is very high.

Market Integration: The SoftwareAs can be concluded from the so-called third package (see Directive 2009/72/EC of the European Parliament and of

The market can put in place appropriate mechanisms to cope efficiently with negative prices, should they become more structural.

september/october 2010 IEEE power & energy magazine 61

the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC), market integration—in particular integration stimulated via cross-border competition—is one of the main goals, ultimately leading to price convergence.

Some concrete solutions have already been proposed for a pan-European electricity market. There are already target models proposed for the different time frames of congestion management: long-term rights combined with the use-it-or-sell-it mechanism, day-ahead allocation via a market price coupling algorithm, cross-border intraday allocation via continuous trading, and integrated balancing markets based on a TSO-TSO approach with a common merit order. These target models have been proposed and agreed to in the pro-cess driven by the Florence Forum, and there is clear agree-ment on the goal of implementing them by 2015 throughout Europe. The huge amount of additional intermittent genera-tion sources will to a large extent challenge the process of market integration, making it more diffi cult but at the same time even more necessary. Without the market integration tools mentioned above (the “software”) in place in a timely manner, all three key EU policy goals—the 2020 targets to tackle climate change, the internally integrated market for electricity, and security of supply—will encounter addi-tional problems.

Market Integration and FlexibilityBased on existing scenarios, wind energy injection will be mainly concentrated in the north of Europe, whereas fl exible generation is dispersed throughout Europe. Should large deviations occur in the day-ahead, intraday, or balanc-ing phase, all fl exible sources will be required to address such deviations.

To achieve this, three market integration tools—market coupling, cross-border intraday allocation, and cross-border balancing—are indispensable in ensuring and facilitating the contribution (on a competitive basis) of all available fl exible sources throughout Europe. Though in the day-ahead phase wind prognosis might still be rather inaccurate, market coupling is the best tool for allocating cross-border capacity, at least compared with explicit auctions, which by defi nition may not lead to the optimal outcome in the day-ahead phase. Continuous intraday trade organized via a cen-tral order book for the whole of Europe will facilitate the necessary coordination of all fl exible sources, in addition to their upward and downward management up to one hour before delivery (subject to available remaining cross-border

capacity). And fi nally, TSO-TSO integrated balancing sys-tems with a common merit order will fi ne-tune the position in the most effi cient way.

It can be concluded that these market integration tools urgently need to be put in place on a harmonized basis throughout Europe in order to coordinate and optimize the response from fl exible sources to compensate for the effects of intermittent RES energy.

Grid Investments: The Hardware

The Need for a Regional ApproachIn earlier times, grid investments were mainly driven by generation, load centers, and network constraints. The RES directive, however, has created a completely different situa-tion: there is a clear commitment from the EU member states to reach an ambitious target for renewable electricity produc-tion, and it is clear that this target cannot be met without an important additional amount of wind energy. Wind maps are not secret data, and in the meantime, the member states have already identifi ed many locations where new wind farms can be built. We believe that TSOs are no longer in a position to wait until the wind farms are in the construction process before they start developing their plans or building the required grids. This is largely due to the fact that licens-ing for transmission is much more time-consuming than for a wind farm.

There are important roles for the three key stakeholders: TSOs must develop procedures for prioritizing the ar- ✔

eas most in need of reinforcement in order to facilitate the most urgently required wind farms and launch in-vestment plans.Regulators should not refuse such investment propos- ✔

als, even if they are in an early phase. Member states should be requested to facilitate proce- ✔

dures for permitting the new grids because the grids are inherently linked to the ambitious goals the states have set out.

The third package requires all TSOs to submit to the national regulatory authorities each year a ten-year network development plan, based on existing and forecast supply and demand. This plan should indicate the main transmission infrastructure elements that need to be built or upgraded over the next ten years. To identify investment gaps, especially in cross-border capacities, every two years ENTSO-E will pub-lish a nonbinding, EU-wide, ten-year network development plan, based on the national network development plans.

If sufficient revenues cannot be recovered in the energy market to support needed investment or keep existing capacity running, a fallback solution may be required.

62 IEEE power & energy magazine september/october 2010

The national regulator may require a TSO to amend its ten-year network development plan if it is not in line with the EU-wide plan. Moreover, the directive enables national regulators to take measures to ensure that the investments listed in the national network development plan are physi-cally put in place. In order to make sure that TSOs really make the necessary and agreed-on investments, national regulators must provide incentives—especially for regional investments involving (directly or indirectly) two or more member states. A common incentive scheme for grid invest-ments needs to be put in place.

The main goal is to reduce the complexity of the authori-zation procedures for building both new internal and cross-border connections in order to speed up grid investments. Grid reinforcements are the key enabler to allow markets to cope with large volumes of intermittent RES. The intro-duction of high levels of RES will not only heavily affect both distribution and national transmission networks but also transmission networks in countries both adjacent to and further away from those with the new RES. Therefore the focus on investments should be shifted from a national to a regional and pan-European perspective, so as to accommo-date large RES investments.

Because even within a country it takes at least ten years (mainly for permit reasons) to build a transmission line, such a pan-European grid investment plan is already lagging behind. In ten years—when a line would be ready if work were started right now—it will already be 2020, and most of the new RES will already have been installed.

The Role of Distribution NetworksMoving toward a low-carbon electricity system will require radical changes on both the supply side (a high penetration of intermittent RES at all voltages) and the demand side (energy effi ciency, load shedding, and the potential electri-fi cation of transport). Because the network operator is the common link among all these changing inputs and outputs, there will need to be an evolutionary change in both network design and network operation, a move away from the largely passive (fi t-and-forget) system of today.

Generally, electricity networks have been designed to deliver energy via a mix of high- and low-voltage systems, with a “top-down” direction of power fl ows. Distribution networks originally designed as “passive” networks (to receive electricity from the transmission system) will need to become more “active” as more embedded renewable generation, from domestic microgeneration to larger-scale commercial units, connects. Increasing levels of distrib-uted generation (DG) in distribution networks will initially displace local demand but in certain locations will ulti-mately result in “export” to the transmission system. This process in turn will have implications for the transmission infrastructure.

DG will also pose operational and control challenges for traditionally designed and operated distribution net-

works. Therefore distribution system operators (DSOs) will have to become much more involved in real-time distribution system operation, making use of innova-tive solutions such as smart metering, voltage control, power flow management, dynamic circuit ratings, and energy storage technologies. The key technical issues will be power flow management, voltage control, and fault level management.

This change will need to be managed by both the TSOs and the DSOs. The move toward more active system man-agement at distribution voltages will complement and sup-port the transmission system operator (TSO). A prerequisite of meeting this challenge, however, will be to ensure that two-way communication between the DSOs and the TSOs continues to be effective. Therefore there is an increased need for cooperation between TSOs and DSOs.

This close coordination is especially relevant in two cases:

It is relevant in the case of congestions in the distri- ✔

bution network, which will be more frequent as RES penetration increases. These congestions are problem-atic because DSOs are generally not allowed to curtail generation to solve the constraint and TSOs have no control over this part of the network. It is relevant in the case of the connection of RES ✔

plants in the distribution network, since the short-circuit power in each bus bar is the main electrical characteristic to be considered.

AcknowledgmentsThis article expresses the view of the authors based on the paper they prepared with EURELECTRIC, the association of the European electricity industry.

For Further ReadingEURELECTRIC, “Integrating intermittent renewable sources into the EU electricity system by 2020: Challenges and solutions,” May 2010.

TradeWind/EWEA, “Integrating wind—Developing Eu-rope’s power market for the large-scale integration of wind power,” Feb. 2009.

EWIS, “Towards a successful integration of large scale wind power into European electricity grids,” Mar. 2010.

Frontier Economics, “Blowing in the wind—Measuring and managing the costs of renewable generation in Europe,” Energibedriftenes Landsforening (EBL), Oct. 2009.

J. Bushnell, “Building blocks: Investment in renewable and non-renewable technologies,” Energy Institute at Haas, rep. WP202, Feb. 2010.

BiographiesMarcel Cailliau is with Electrabel (GDF Suez), Belgium.

Marco Foresti is with Eurelectric, Belgium.César Martínez Villar is with Endesa, Spain. p&e