EURELECTRIC Flexibility Report

Flexible generation:Backing up renewables

This report is part of the EURELECTRIC Renewables Action Plan (RESAP).

The electricity industry is an important investor in renewable energy sources (RES) in Europe. For instance, it is responsible for 40% of all wind onshore investments. RES generation already represents a substantial share in the power mix and will continue to increase in the coming years.

EURELECTRIC’s Renewables Action Plan (RESAP) was launched in spring 2010 to develop a comprehensive industry strategy on renewables development in Europe.

RESAP addresses the following key challenges in promoting RES generation: • the need for a system approach to flexibility and back-up, • the need for a market-driven approach, • the need for a European approach to RES development.

RESAP consists of 14 dedicated task forces, including demand side management, market design, load and storage. The purpose of RESAP is to develop, through a series of reports and a final synopsis report, sound analysis with key recommendations for policymakers and industry experts.

For additional information on RESAP please contact:

John Scowcroft Susanne Nies [email protected] [email protected]

Dépôt légal: D/2011/12.105/47October 2011

Flexible generation: Backing up renewables 1

Flexible generation: Backing up renewables

TF Requirements for Flexible and Back-up Capacity

Chair: Inge PIERRE (SE) WG Energy Policy, WG Gas, SG CHP, WG Nuclear

Franz BAUER (DE) VGB PowerTech e.V.; Ronald BLASKO (BE) Foratom; Niklas DAHLBACK (SE) WG Hydro; Matthias DUMPELMANN (DE) WG Gas; Kaija KAINURINNE (FI) WG Nuclear; Sascha LUEDGE (DE) TF Regulatory Issues for Carbon Capture and Storage; Philippe OPDENACKER (BE) SG CHP, WG Prospective, TF Regulatory Issues for Carbon Capture and Storage, WG Climate Change; Isidro PESCADOR CHAMORRO (ES) WG Thermal; Dominik ROMANO (CH) WG Wholesale Markets & Trading; Frank SCHOONACKER (BE) WG Thermal; Ghislain WEISROCK (FR) WG Hydro

Contact:

Giuseppe Lorubio – [email protected]


ExECuTivE SummaRy 4

1. inTRoduCTion 6 1.1 EURELECTRIC’s Renewable Action Plan and the flexibility challenge 7

2. THE nEEd FoR GREaTER FLExiBiLiTy: WHERE do THE CHaLLEnGES LiE? HoW To TaCKLE THEm? 8 2.1 The current generation mix 9 2.2 The EU transmission system: getting smarter and wider 10 2.3 Developments with the electricity markets 11 2.4 A brief analysis of the National Renewable Energy Action Plans (NREAPs) 11 2.5 Comparing the NREAPs with EURELECTRIC’s statistics 12 2.6 How‘firm’arev-RES? 13

3. HandLinG FLExiBiLiTy: THE RoLE oF FLExiBLE and BaCK-uP CaPaCiTy 15 3.1 Different type of needs: current market reality and requirements for the future 16 3.2 Technical flexibility of different power plants: results of the enquiry 19 3.3 Impactofload-followingonpowerplantefficiencyandemissions 20 3.4 Lifetimemanagementofpowerplantsinabaseloadandload-followingmode 21

4. vaRiaBiLiTy and FLExiBiLiTy in THE Eu mEmBER STaTES 22 4.1 ThecaseofGermany:amulti-prongedapproach 23 4.2 Spain: where future happens today 25 4.3 The Nordic system: the power of water and cables 28 5. THE FLExiBiLiTy CHaLLEnGE and iTS imPaCTS 33 5.1 Economic viability of dispatchable power plants and the impact of flexibility on the levelised costs of electricity 34 5.2 The impact of negative prices 35 5.3 Theimpactofincreasingv-RESonthefunctioningandoperationofgasmarkets 35

6. ConCLuSionS & RECommEndaTionS 39

annExES 43 I The flexibility requirements: a critical overview of existing publications 44 II Cycling operations of nuclear power plants: the Neckarwestheim case 47 III The role of gas storage in enhancing flexibility in the power sector 47

table of contents

4

The European electricity sector is striving to reach a carbon-neutral power supply by 2050. Strongly supported by EURELECTRIC and its membership, renewable energy sources (RES), especially variable RES like wind and solar, are entering the European electricity mix. But many challenges lie ahead on the road to 2050. In fact, the renewables take-off brings about far-reaching consequences that affect the way electricity systems are operated.

How can the electricity system balance variable RES? How flexible is the existing generation park? Are there enough incentives to maintain generation adequacy? What, if any, are the consequences for the functioning of other commodity markets like the gas market?

Variable RES pose numerous challenges, including reduced operating hours – and hence profitability – of other generators and the need for adequate infrastructure to integrate the varying output of variable RES. More importantly for this report, they put stress on system stability and heighten the need for more flexibility and back-up resources in other parts of the power system.

Traditionally, power generation followed the load, i.e. the sum of the requirements of all consumers connected to the power grid, plus losses throughout the grid itself. Although the load varied throughout the year (summer vs. winter), the week (working day vs. weekend) and the day (night vs. daytime), such variations were largely foreseeable. Power plants were dispatched (i.e. called upon to generate electricity) following the merit order according to their (short run) marginal cost.

executive summary

Variable RES introduces a new layer of complexity. Wind farms and photovoltaic systems generate electricity only when wind speeds are high enough and the sunlight strong enough. It goes without saying that no operator can control such factors (although curtailment of e.g. wind farms does happen).

As long as the share of variable RES in a given market/power system is low the system can operate as usual. Yet as RES start to be deployed on a large scale, a new challenge emerges. This is precisely the situation that Europe is facing today.

When the wind stops blowing or the sun stops shining the remainder of the installed capacity has to make up for the loss of variable RES1. Such sudden and massive requests for power, so-called power ramps, create new requirements for conventional generators, including fossil-fired, nuclear and dispatchable RES. Whilst traditional variability of demand or load has always required a certain amount of flexibility, power ramps will introduce a step change in the way the electrical systems are operated.

This paper assesses whether power plants across Europe are technically flexible enough to compensate for such power ramps. While avoiding prescriptive models to assess whether a given system is capable of handling large shares of variable RES, it clearly shows that a system approach is needed to get the flexibility story right.

1 Several other tools to cope with the integration of v-RES are discussed in Chapter 2


Building on a joint VGB-EURELECTRIC enquiry based on operational practice, the report shows that hydropower plants are the most responsive plants and can be called upon to generate electricity within very short timescales2. Gas-fired, combined cycle turbines are also fairly easily able to adjust their generation to provide power when most needed. Contrary to common wisdom, coal-fired power plants (both hard-coal and lignite) have a role to play in providing flexibility. Even more surprisingly, nuclear power plants are only surpassed by pumped storage in terms of load changes, although they do require more start-up time and their suitability to perform load-following depends on design and business case.

We would like to stress that this report addresses technical feasibility, but not the business cases for such operation. The suitability of a specific power plant technology to operate flexibly and to back up variable RES depends on a number of factors, including its technical design, the requirements it has to fulfil (e.g. primary control, black start capability, etc.), the costs associated with changing operational patterns (from baseload and mid-merit operations to more flexible ones), and the associated environmental aspects (e.g. effects of part-loading on plant efficiency and hence on carbon dioxide and other emissions). Depending on national specificities and business models, member states and power companies will select the technology that best provides the necessary flexibility.

What then does this imply for policy- and decision-makers?

Although the EU member states retain their role in setting the fuel mix that best matches their reality, history and policy, non-technical considerations should not prevent the different technologies from coming into play and contributing to increased flexibility. On the contrary, a strong push for more research, development & deployment (RD&D) is urgently needed if the European energy and climate targets are to be achieved in a timely and efficient manner. The 20% renewable target has created a favou-rable environment for renewables. It now needs to be accompanied by actions that make sure that the system as a whole can withstand the changes brought on by the massive deployment of variable RES.

Because building power plants is a long-term business, which makes it difficult to plan for appropriate flexible and back-up capacity, policymakers should speed up and simplify permitting procedures. This applies not only to power stations but also to the grid infrastructure that will be needed to support the EU’s energy and climate policy objectives.

Finally, if natural gas is to contribute to integrating variable RES, gas-based generators have to rely on a more flexible supply of gas. This implies the completion of the internal gas market on the one hand and the necessary investment to enhance the flexibility of the physical system (e.g. storage, LNG) on the other.

2 For a thorough presentation of hydropower, its role, characteristics and potential see EURELECTRIC, Hydro in Europe: Powering Renewables (in the framework of the RESAP).

1introduction


In the last three decades, electricity demand in the European Union increased by more than 70%. The generating fleet which supported this expansion was mainly composed of fossil-fired plants (mostly coal and oil and increasingly natural gas), hydro plants and (unevenly across Europe) nuclear power plants.

Although renewable energy sources (RES) have always been exploited in Europe, this primarily occurred through developing Europe’s important hydrological potential. However, fostered by national support programmes and EU legislation, new RES sources started to increase steeply since the early nineties. RES electricity has continued to grow, reaching about 597.6 TWh or 19% of total electricity generation in 20093.

In the framework of its wider energy and climate package, in 2009 the European Union decided that by 2020 member states should source 20% of their (gross) final energy consumption in the electricity, transport and heating/cooling sectors through RES. This translates into a RES share of 30-35% of all electricity generation.

To reach such level of RES penetration, member states had to detail their respective pathways towards the 2020 deadline in so-called National Renewable Energy Action Plans (NREAPs). The analysis of the NREAPs, as well as of current trends, suggests that member states will mostly meet their RES electricity (RES-E) target through biomass, wind and solar power.

The last two, however, are inherently variable (or non-dispatchable), challenging to accurately forecast for more than two days ahead, and unevenly geographically distributed. This implies far-reaching consequences on how electricity is generated, transmitted and distributed to end customers.

The higher the share of generating capacity which is intrinsically non-dispatchable – i.e. which cannot be regulated to match changes in demand and/or system requirements and which cannot be turned on and off based on their economic attractiveness – the greater the need for the remainder of the power generation capacity to flexibly complement such variable output. This is the essential challenge facing the electric systems and companies in the future.

1.1 eurelectric’s renewables action plan & the flexibility challenge

Faced with a substantial increase of RES – which EURELECTRIC fully supports as a great share of this increase actually results from its own membership (e.g. wind offshore) – EURELECTRIC has decided to undertake a comprehensive project, the Renewables Action Plan (RESAP), which thoroughly analyses the challenges associated with the RES increase across the whole electricity chain: generation, networks, markets, and competitive and sustainable renewables. It aims to propose ways of tackling those issues through a comprehensive, holistic industry view and strategy.

The present paper is part of a broader list of reports that EURELECTRIC’s structure of expertise has prepared under RESAP. As such, it deals with the impact of growing shares of renewables – particularly variable renewables (v-RES4) – on the “conventional” generation in terms of requirements for greater flexibility and back-up capacity, the impact on underlying gas markets and the surrounding economic consequences/market design issues. Where appropriate, it refers to pieces of work being undertaken by other groups within EURELECTRIC and has to be assessed in this larger context.

3 EURELECTRIC, Power Statistics 2010, December 2010.

4 This report uses the term “variable renewables” (v-RES) to refer to renewable sources which are non-dispatchable. For more details of the dispute between supporters of variable RES vs. intermittent RES, see the Appendix I.

2the need for greater flexibility: where do thechallengeslie? howtotacklethem?


Because electricity cannot be stored on a large-scale, affordable basis, traditional power systems have been designed so that generation closely follows the load (i.e. demand) pattern. In other words input and off-take of electricity in a given system correspond at any point in time. This is commonly referred to as the “generation follows demand” paradigm. Variable renewables (v-RES) challenge this traditional way.

Several options exist for managing the variability of non-dispatchable RES and ensuring stability of grid operation and security of supply:1. Dispatchable flexible and back-up generation2. Demand-side participation and storage3. Interconnections4. Market tools (e.g. market coupling or capacity

remuneration mechanisms)

Demand-side participation and/or (affordable and sufficiently large) storage systems are expected to contribute to system stability and to integrating larger amounts of RES in the long run, by either managing electricity demand or by removing electricity from the system and storing it for subsequent use. The introduction of smart grids (including smart metering) will also help to optimise the overall available resources by making use of price signals and dynamic customer behaviour to shift demand and consumption. Again though, this will only occur in the longer run provided that necessary incentives and frameworks are put in place. The remaining options to cope with sudden swings in v-RES output are either to adapt the remaining part of the generation fleet in a given system or to optimise the utilisation and foster the development of grid interconnections between different systems.

This paper aims to develop an understanding of the first point above: dispatchable flexible and back-up generation. This chapter analyses the current generation situation in Europe, as well as ongoing developments in both grids and markets. It then tries to assess how much RES capacity will come on-stream in the present decade, as well as how much of it will be non-dispatchable.

2.1 the current generation mix

Fossil fuels still represent a major share of the current electricity supply. In 2009, out of a total of about 840 GW of installed power plants in the EU, roughly 54% (457 GW) was made of thermal power plants composed primarily of hard coal- and natural gas-fired units – but also of lignite, where it is widely available, and oil-fired generators for isolated systems and for peaking units. The carbon-free share of conventional generation accounted for the remaining 46% of the installed capacity, with hydro and non-hydro RES totalling 250 GW (30%) and nuclear power accounting for the remaining 132 GW (16%).

Although the RES share is substantially greater than that of nuclear with regards to installed capacity, the RES share of electricity generation is actually lower. In fact, nuclear generation stood at 893 TWh in 2008, whilst combined RES output was 579.5 TWh (hydro accounted for 353.5 TWh and other RES added another 226 TWh).

The above example illustrates a phenomenon which lies at the very heart of this analysis: the role of a technology’s capacity factor5. Each and every power generation plant has a capacity factor which is influenced by the fuel used, the technology, the purpose of the plant (i.e. its business case to a certain extent) and by climatic features for RES6. Typically, RES plants operate with capacity factors ranging from 30-80% for hydro, 20-40% for wind farms and 10-20% for photovoltaic (PV)7. Only biomass is substantially different because it is burnt in conventional boilers which can be fully controlled and dispatched. Moreover, part of the biomass is actually burnt simultaneously with fossil fuels in a process known as co-firing.

5 The capacity factor of a power plant is the ratio of the actual electricity produced in a given period to the hypothetical maximum possible, i.e. if the plant had operated at full nameplate capacity around the clock, throughout the whole year”. Definition in Power Statistics, see footnote 1 above.

6 Renewable Energy Research Laboratory (University of Massachusetts), Wind, Intermittency, Capacity Factor.

7 Depending on the different type of plants, i.e. their technology, geographical location, business case or asset optimisation strategy.

Source: EURELECTRIC, Power Statistics 2010, December 2010

Figure 1: Development of the Installed capacity in the EU in the latest years

2007 2008 2009

Nuclear 132,855 132,882 132,876

Conventional Thermal 436,464 446,936 456,967

Hydro 140,894 141,788 142,617

Other RES 77,983 93,342 107,491

of which Wind 55,394 63,611 74,335

Total 791,233 815,515 841,732

10

2.2 the eu transmission system: getting smarter and wider

The development of the European power grid has revolved around the above-mentioned “generation follows demand” paradigm. It has been based on main high voltage transmission lines which connected the big power generation units to the main distribution lines, towards the end customers. In other words, grid development was driven by generation investment, proximity to consumption centres and network constraints.

Variable RES challenge this approach. Three main consequences for power grids arise:

First and foremost, the grid should become more intelligent, enabling multi-directional flows of electricity and allowing customers to play an active role in the electricity markets.

Secondly, offshore wind is seen as a prominent contributor towards the 20% RES target as it can be sited in areas of stronger, constant wind (implying higher capacity factors) and where public opposition is lower. European governments and companies have thus started to develop projects such as the North Offshore Super Grid. Such projects need to be connected to the main European electricity grids to serve loads located at the heart of the EU.

Thirdly, cross-border connections were mostly seen as ensuring grid stability and back-up to adjacent transmission systems, and not as supply routes. However, exploiting v-RES potential in zones far from consumption centres requires important investments in grid development. Whether such grids would also be able to gather and send through the output from the necessary flexible and back-up power plants has to be assessed. If existing and future flexible and back-up units cannot be located close to v-RES and use the same transmission grid, the need for more lines and/or smarter grid management will increase.

Regulation (EC) 714/2009 tasks the European Network of Transmission System Operators for Electricity (ENTSO-E) with elaborating a Ten Year Network Development Plan (TYNDP) every two years, depicting the evolution of the transmission network for the following ten years. While the present report was under preparation, ENTSO-E started work on their second TYNDP by publishing the Scenario Outlook and Generation Adequacy Forecast 2011-2025 report, which should provide a sound basis for the development of the TYNDP.

EURELECTRIC does not represent TSOs, and network expansion, refurbishment and actual use is not the subject of this paper. However we mention the issue because it is commonly acknowledged that “increased control of transmission and distribution assets to increase transmission capacity and reduce congestion during key periods and over critical line lengths” will play a role in integrating a larger share of non-dispatchable RES electricity, as ascertained by the International Energy Agency (IEA) in its latest projection of electricity costs8. Figure 3 shows the trading within the Nordic market in December 2003, when consistent shares of wind and hydro-based electricity were traded between Western Denmark and Norway/Sweden. When wind power (the blue line) was stronger, more export (the yellow bars) from Western Denmark took place and vice versa − note, in particular, the spikes occurring between 8 and 10 December.

8 International Energy Agency (IEA), Projected Costs of Generating Electricity, 2010 Edition.

Source: EURELECTRIC, Power Statistics 2010, December 2010

Figure 2: Installed capacity and generated electricity in the EU in 2008

Hydro11%

Hydro17%

Electricity Generation in 2008

Nuclear28%

Fossil Fuel Fired53%


Other Renewables7%

Not Specified1%

Installed Capacity in 2008

Nuclear16%

Other Renewables11%

Not Specified0%

Hydro11%

Hydro17%

Electricity Generation in 2008

Nuclear28%



Other Renewables7%

Not Specified1%

Installed Capacity in 2008

Nuclear16%

Other Renewables11%

Not Specified0%


In a more recent study the IEA has assessed the balancing requirements of power systems with increasing shares of v-RES through its Flexibility Assessment Method (FAST). One of the main results concerns the Danish case: the country has the highest flexibility index – a measure of the existing flexibility resources – thanks to “its strong interconnections to adjacent areas, with which it is balanced as part of one market”9.

2.3 developments with the electricity markets

The development of transmission lines, particularly of cross-border lines, is not simply good per se, but has a beneficial effect on market integration as more electricity can flow from lower-priced to higher-priced markets, hence leading to price convergence and ultimately to market integration.

The European institutions have recently agreed on a new series of legislative acts to open up even further today’s nationally restricted markets, and integrate them into one internal electricity market. The development of new market tools can be particularly beneficial to the cause of renewables because trading arrangements and functioning wholesale markets (day-ahead, intraday and balancing) would help to smooth the variability of v-RES:

the variable reserves could be pooled in larger markets so that sudden drops of wind output could be compensated by the conventional or even renewable fleet located in adjacent markets. Hence, the development of such “software”, coupled with “hardware” like investment in transmission and distribution lines, is of the utmost importance10.

Therefore, the way the market is designed will contribute to ease the variability challenge. According to Pöyry consultants the “capacity that essentially operates as a back-up to the wind becomes more valuable for its capacity than its energy output”; they affirm that “unless market designs change, the investment case for thermal plant is challenging – and this holds even for a significant shortfall against targets of renewables deployment”11. Contrary to the IEA work presented above, Pöyry claims that reinforcing the interconnections “doesn’t appear to offset the need for very much back-up plant” and that “while greater interconnection has some economic benefits, they are asymmetric and therefore there are significant barriers to their deployment.”

2.4 a brief analysis of the national renewable energy action plans (nreaps)

Now let us turn towards the increase of RES generation that member states foresee in their NREAPs to meet the 20% RES target12.

According to the NREAPs, RES electricity (RES-E) will make up about 35% of final electricity consumption by 2020, with wind accounting for 14%, hydro for 10%, biomass for 7%, and solar for 3%. Wind power undoubtedly emerges as the winner. Installed capacity of wind turbines across Europe in 2010 is forecast to be 85 GW, with corresponding electricity generation of 164 TWh (hence with a capacity factor of 22%). It rises to 214 GW by 2020 – a spectacular 150% increase, partially driven by booming offshore capacity –, which will generate about 496 TWh of electricity (capacity factor of 26%13). Solar capacity and generation are also due to expand rapidly between the two reference years: whilst in 2010 26 GW are generating 21 TWh (capacity factor of 9%), by 2020 installed capacity would stand at 91 GW, producing 107 TWh (capacity factor of 13%)14.

Source: International Energy Agency, Projected Costs of Generating Electricity, 2010 Edition

Figure 3: Western Denmark’s electricity trading with Norway and Sweden: wind power for hydropower

9 IEA, Harnessing Variable Renewables, A Guide to the Balancing Challenge, May 2011.

10 The distinction between “hardware” and “software” was developed in EURELECTRIC, Integrating intermittent renewables sources into the EU electricity system by 2020: challenges and solutions, March 2010.

11 Pöyry, “The challenges of intermittency in North West European power markets. The impacts when wind and solar deployment reach their target levels”, March 2011.

12 A forthcoming report under the broader RESAP project will provide a more detailed analysis of the NREAPs, their main features, their plausibility, the cost associated, etc. EURELECTRIC, “National Renewable Energy Action Plans: An Industry Analysis”, November 2011.

13 Capacity factors for offshore farms are typically higher than those for onshore farms because of stronger and more constant wind.

14 The increased capacity factor can be partly explained by the growing shares of concentrated solar power (CSP) over the total solar generation as CSP attains higher capacity factors than PV.

InvestWind power – Western Denmark Trade – Western Denmark/nordic

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What clearly emerges from the NREAPs is that v-RES are going to increase by 2020, achieving a share of 50% of all RES generation, up from the current 29%. The share of v-RES on total RES in terms of installed capacity is set to increase even more, reaching over 60% by 2020. Hydropower, which dominated the beginning of RES development, has been largely exploited and will be increasingly complemented by wind power. Overall, it is likely that the increase of v-RES will put more stress on the system in terms of stability, safe operations and security of supply.

2.5 comparing the nreaps with eurelectric’s statistics

EURELECTRIC’s Power Choices study has detailed the electricity industry’s view on how the power sector can achieve carbon-neutrality by 2050. It shows a spectacular increase of RES power taking place throughout the whole period, reaching 1,900 TWh of total EU generation and becoming the greatest single source of electricity in Europe by 2050. Installed capacity also increases dramatically in the same time span, with RES technology accounting for 54% of EU installed capacity. As a result, carbon intensity of the EU power sector falls to 134 grams of CO

2 emitted per kWh produced.

The tables below compare the Power Choices predictions of RES capacity and production in 2020 against those of the NREAPs and of EURELECTRIC’s Power Statistics 201015.

Source: EURELECTRIC

Source: EURELECTRIC

Table 1: Breakdown of the installed capacity of different RES sources in the NREAPs, EURELECTRIC’s Power Choices and Power Statistics 2010

Table 2: Breakdown of the electricity generation of different RES sources in the NREAPs, EURELECTRIC’s Power Choices and Power Statistics 2010

15 Whilst Power Choices is a scenario derived from the University of Athens’ Primes model, Power Statistics 2010 is based on a bottom-up approach whereby the members of EURELECTRIC’s Network of Experts supervising its publication (NE Statistics & Prospects) provide their best estimates of the developments of the power system in their respective countries.

installed capacity (GW)

member states’ nREaPs (2010)


EuRELECTRiC power choices (2020)

eurelectric power statistics (2020)

Hydro 118 136 114 114

Wind 85 214 216 187

Solar 26 91 41 51

Biomass 22 43 46 30

Total 251 484 417 382

Electricity generation (TWh)



EuRELECTRiC Power Choices (2020)

EuRELECTRiC power statistics (2020)

Hydro 347 371 335 346

Wind 164 496 523 408

Solar 21 107 50 66

Biomass 114 233 188 156

Total 646 1,207 1,096 976


Differences emerge between the NREAPs and Power Choices and Power Statistics 2010. Broadly speaking, the member state estimations are higher than those from industry. Nevertheless, all scenarios predict an increase in non-dispatchable generation.

2.6 how ‘firm’ are v-res?

The expected evolution of RES is only part of the story; RES development has to be placed within the complexity of wider electrical systems. As described above, power plants have different levels of ‘firmness’ – the degree to which output can change and be controlled by generators and/or system operators, “essentially power supply that can be more or less guaranteed”16.

The level of firmness of v-RES is limited by the very nature of the primary source and by the difficulty to accurately predict their output17.

Figure 4 shows some of the main characteristics of wind power. It can be seen that wind output varies quite substantially (from almost 0 GW up to more than 35 GW) within short periods of time. Secondly, such changes are particularly frequent. Thirdly, offshore wind is less subject to seasonal changes than onshore wind.

The data for the last 20 years show how often periods of low wind generation occur (Figure 5). The blue and red rectangles identify periods of 10-12 days or more than 12 days respectively.

It is often said that increasingly precise forecast methods will help dispatch generating units more effectively. However, recent examples demonstrate that deviations from the forecasts continue to exist. Figure 6 on the next page shows the cumulated output of wind farms and photovoltaic installations in the control areas of the four German TSOs in week 23 of 2011. Forecasts errors are still observed throughout the week, with wind being more difficult to predict than solar power. Errors can be both positive (i.e. the forecast is greater than actual generation) or negative (i.e. generation is greater than the forecast). Although forecasts models and the corresponding software tools will evolve, it seems unlikely that they will ever be entirely accurate.

16 IEA, Harnessing variable renewables, op. cit. “Although VRE plants do provide a measure of firm capacity — capacity that can be relied upon most of the time — they provide less of this than conventional power plants”, p. 7.

17 Wind and solar indeed represent energy resources – that is, they generate electricity under certain conditions – but not capacity resources – that is, they can not always be relied upon and deliver capacity on demand.

Figure 4: Wind onshore and offshore generation over a whole calendar year

Source: RWE Power

Figure 5: Days with less than 10% wind power generation in Germany: frequency distribution over the last 20 years

Source: Fraunhofer IWES

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Source: CORESO, private presentation

Figure 6: Cumulated generation of wind and solar power in the control areas of Germany’s four TSOs during the last week of May 2011

18 The extent to which conventional generation has to make up for the missing v-RES generation depends on the load profile at the considered time, the possible trade balance of electricity between adjacent systems, the availability of the generating portfolio, etc.

As discussed more extensively in Annex I, a significant number of studies have shown the typical level of firmness of v-RES to be at around 5-10%, with national variations. For instance, the Spanish TSO claims it is 5% in its control area, while the Swedish TSO ascertains it is 6%, and in Germany it is referred to be around 7%.

Taking into account the ‘smoothing effect’ of better interconnections between power systems, technological development (e.g. wind turbines starting to run at lower wind speed) and the role of storage, we have considered two different scenarios of v-RES firmness, namely 10% and 20%. While the latter might appear optimistic, the purpose is to analyse what kind of impact this assumption could have on flexibility and back-up requirements.

When considering any given v-RES capacity, expressed through its installed capacity, only 10% or 20% of the total capacity can be considered reliable and dispatchable. The remainder is not always available when needed, thus resulting in more pressure on dispatchable generators which have to stand ready to generate the electricity required.

Considering these assumptions, and taking into account the figures derived from the NREAPs, we can see that out of the impressive 305 GW of solar and wind parks believed to be installed in the EU in 2020, either 30.5 GW (10%) or 61 GW (20%) can be considered firm capacity. The remaining capacity will either produce electricity or sit idle depending on weather conditions, with a broad range of combinations in between those extremes18.

The other side of the coin is that the operation regime of conventional generators has completely changed; they should be ready to reduce their output and even shut down if and when weather patterns change and wind farms and solar parks return to dispatching their generated electricity to the grids.

This represents a relatively new feature for power systems which have historically been dominated by power plants which were fully dispatchable, with the typical demand-driven swings in generation stemming from the changing consumption during the day (day vs. night), the week (working days vs. weekends/holidays) or the year (winter vs. summer).

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3handling flexibility: the role of flexible andback-upcapacity

16 basic eu scenario assumptions

The analysis of the NREAPs shows that v-RES are set to increase sharply in the present decade. This brings about several changes to the overall electricity system, not least to the existing fleet of power stations and the way they are operated. In particular, harnessing the potential of v-RES implies the capability to react to both demand-side changes, i.e. fluctuations in demand, and to generation-side changes, i.e. losses of active power and power ramps.

Before reporting the results of the targeted analysis undertaken by EURELECTRIC and VGB PowerTech, an introduction to the different needs of the modern power systems today and tomorrow is provided.

3.1 different type of needs: current market reality and requirements for the future

An electrical power system has to be in constant balance, with a perfect continuous match between electricity consumption and generation. While very minor dif-ferences are acceptable, they affect system frequency and stability. Possibilities to balance the system exist both on the generation and consumption sides and can also be handled via import and export. Traditionally, however, balancing has been provided by generation adapting to demand.

Variations in the power system demand, both fore-seeable and non-foreseeable, are quite large. A major introduction of v-RES will also result in greater variation on the generation side.

The services needed to keep the system in balance may be procured on a market place in the same way as the volume of electricity. However, such markets are still not uniformly developed throughout Europe and may indeed restrict the possibilities to import/export. Furthermore, lack of transmission capabilities may restrict choices of balancing in a certain part of the power system.

Different timescales are involved in the variations of demand and generation, which also affects balancing capability. As a result, the discussion on flexibility and balancing has to reflect all involved timescales.

The following paragraphs use a typical example from a wind farm to explain the different types of balancing needs (in different timescales) that arise from variable generation, wind power in this case. A typical wind generation statistic curve from a large wind farm – the 150 MW Horns Rev in the North Sea – is presented below. The example shows the recorded generation during one month (pink curve), as well as the day ahead forecast (blue curve).

forward planning

Since wind is both variable and uncontrollable, generation cannot be scheduled according to demand. Sometimes there will be no wind generation at all, whilst at other times there will be excess generation. Integrating generation into the figure above and comparing it to a monthly mean value allows us to show the deficit and excess generation (see Figure 8), which reflects the electrical storage volume needed to offset wind generation variability (dotted line). A rough estimate of this storage volume in Horns Rev shows a variation of about 5 GWh for the 150 MW wind farm, with a typical duration of 3-5 days for peaks.

Source: ELFORSK, “A Massive Introduction of Wind Power”, report 2008:41

Figure 7: Hourly production (pink) and forecast (blue) at Horns Rev offshore wind farm during September 2006

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Note that the power system also has to fulfil demand for capacity; hence back-up capacity also has to be established. The back-up capacity may vary depending on the importance of wind generation in the power system.

If we extrapolated from the example and assumed that wind capacity stood at 100 GW in the whole North Sea that would correspond to a storage need of 3 TWh with input/output in a few days. This is only a small portion of the total seasonal storage capacity attainable with hydro in Europe, but indeed several magnitudes larger than the sole pumped storage volume.

Examples of power system action:

Existing dispatchable generators follow demand and plan generation through market signals. With higher wind penetration, thermal baseload generators will see plummeting operation hours throughout the year (see the case of Spain presented in the following chapter).

The ability to react and provide the needed services will determine which technology will primarily act as back-up to v-RES. In some markets this will be done by natural gas-fired generators, whilst in others hydropower with large storage capacities will be the preferred choice. Hydro (non-pumping) storage will have large volume capability to handle excess wind generation; pumped storage will have smaller storage volumes but still a high power capacity.

intraday actions

The accuracy of wind generation forecasts increases at shorter time ahead. The electricity market is usually based on day-ahead bidding, with resources planned and dispatched according to the bid results and the emerging merit-order. From gate closure to electricity dispatch there is still a significant deviation between wind forecast and actual wind generation. The difference between forecast and generation in one case is shown below.

The figure shows that the maximum amplitude is not far away from full wind capacity and that the cumulative error of every hour will reach a deviation in the order of 40% of the generation.

These deviations have to be corrected through balancing services bought on the market when forecasts are corrected in a shorter time perspective than a day, or afterwards when TSOs have used their tools to keep the system in balance.


Dispatchable generators can offer capacity on the balancing market for upwards or downwards regulation. Note that this means a replacement of bidding on the spot market. Thus the price for balancing will be related to the spot price.

Pumped storage is responsive to variations in the spot prices and thus provides a contribution to the balancing market. The typical storage time (i.e. the number of hours it can generate electricity before running out of water) for a pumped storage plant is between 4 to 10 hours.

Cascaded river systems with hydro storage may also act on the balancing market in the same way.

Source: ELFORSK, report 2008:41

Figure 8: Hourly production and forecast at Horns Rev in September 2006. Monthly mean value (red straight dashed line) and integrated deviation (i.e. storage need) from this mean value (red dotted line)

Figure 9: Difference between real production and day ahead forecasted at every hour at Horns rev during September 2006


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generation ramps

Wind speed can widely fluctuate in a rather short time period. This causes the need to quickly compensate for large amounts of increased or decreased generation with other sources.

Figure 10 shows a wind generation change from maximum to zero within a few hours (green field) as well as a change in the opposite direction a day later (yellow field). These sudden changes appear several times per month.


Pumped storage and hydro storage have quick ramp possibilities with relatively large energy volume capa-bilities. Open cycle gas turbines can also quickly start and make up for the losses in generation as they do not need to pre-heat water (contrary to both combined cycle gas turbine and steam plants). CCGTs take longer to ramp up their output, whilst steam units are even less reactive. Contrary to common belief, nuclear power plants may perform in a rather flexible mode if the appropriate (technical) design has been implemented (as witnessed in countries like Germany and France).

All sources act together to handle a change that requires a large volume.

These findings represent the core of the analysis and are explained more thoroughly in the following chapter.

irregular generation

As seen in Figure 10, generation from wind is irregular most of the time, both on an hourly scale, but also in shorter timescales due to bursts of wind. TSOs have to balance these irregularities through automatic primary regulation and by adjusting secondary generation regulation so as to keep frequency and voltage within a stable range.

Wind generators commonly do not have the same abilities (synchronised rotating mass and frequency dependent generation) to contribute to primary regulation of the power system. This explains why the relative work of other generators has to increase if there is large wind penetration.

It is generally accepted nowadays that TSOs are es pon sible for both frequency and voltage control. Nevertheless, because of the unbundling regime created by the EU liberalisation packages, TSOs have to procure such services in a market-based fashion and should not be allowed to operate generation units themselves.

Example of Power system action:

Primary control of frequency is done automatically by many power plants. An increased frequency (excess generation) delivers a feedback signal to generators to reduce their output. A corresponding automatic control exists when there is generation deficit that causes frequency to drop.

Voltage control may be performed by special devices in the power system or by some of the existing generators.

Figure 10: Hourly production at Horns Rev, during September2006.Greenshadedfield:exampleoffastdecreaseand increase of generation, between maximum and zero. Yellowshadedfield:exampleofirregulargeneration


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3.2 technical flexibility of different power plants: results of the enquiry

EURELECTRIC and VGB PowerTech have undertaken an analysis with their membership to identify the flexibility of the existing fleet, including an outlook for the coming generation of power plants. Its results are set out in Table 3 below.

From a methodological viewpoint, it is of the utmost importance to clearly state that:

The table does not contain all information related to the operation of power plants, but only information that matters in terms of flexibility. Therefore it contains data on cold and warm start-up times, the rapidity of load change in both regulating directions (that is upwards and downwards), the minimum load level and, where relevant, the necessary shutdown time;

The investigation covers nuclear power plants (‘NPP’ in the table below), hard coal-fired power plants (‘HC’), lignite-fired power plants (‘Lign’), combined cycle gas-fired power plants (‘CCG’) and pumped storage power plants (‘PS’). As such, it does not rule

out using other technologies such as single-cycle gas turbines or combustion engines as flexible and back-up sources;

Figures come from generators’ daily business and are to be understood as samples of the flexibility of different power plant technologies employed by the electricity industry. In other words, extreme values – even if technically possible as claimed by equipment suppliers – have not been taken into consideration due to their lack of representativeness;

Technological progress was taken into account, that is data has been recorded for both old and new power plants;

Slight differences between upwards and downwards load changes have been neglected; this fact is valid in principle referring the shutdown times;

Only pumped storage plants require a complete shutdown because it takes time to refill the reservoirs, i.e. to pump the water up from the lower to the upper reservoir. If one would use other storage technologies such as compressed adiabatic air or simply batteries the time constant would be even longer.

19 Depending on plants’ (technical) design; limitations at the ends of fuel cycle; limitations by number of power ramps cycles; etc.

The first conclusion that can be drawn is that pumped storage is the most responsive technology. Pumped storage schemes can be called upon to generate electricity almost instantaneously. They also have the fastest load gradient, i.e. the rate of change of nominal output in a given timeframe, as they can ramp up and down by more than 40% of the nominal output per minute. For example, a pumped storage scheme of 100 MW operating at a minimum load of 15% can go up to full load in only two minutes.

Nuclear power plants come second with regards to load gradients19 (5% per minute on average) which make them technically suitable to perform load-following operations if they are already operational. However, they cannot be brought online from cold and warm conditions in timeframes similar to those of the other technologies.

CCGTs are also particularly suitable for load-following operation as they have both fast load gradients (4%/min) and can be brought online fairly quickly (less then 1.5 hours from warm conditions).

Table 3: Flexibility of conventional power generation technologies

Source: EURELECTRIC/VGB enquiry

nPP HC Lign CCG PS

Start-up Time “cold” ~ 40h ~ 6h ~ 10h < 2h ~ 0,1h

Start-up Time “warm” ~ 40h ~ 3h ~ 6h < 1,5h ~ 0,1h

Load Gradient “nominal Output” ~ 5%/m ~ 2%/m ~ 2%/m ~ 4%/m > 40%/m

Load Gradient “nominal Output” ~ 5%/m ~ 2%/m ~ 2%/m ~ 4%/m > 40%/m

Minimal Shutdown Time ~ 10h

Minimal possible Load 50% 40% 40% <50% ~ 15%

no

20

Coal-fired plants are less responsive than the other technologies, although newer plants are more flexible than older units. Hard coal-fired and lignite-fired plants have similar load gradients, but the former are faster to respond to load changes from both warm and cold start-up conditions.

It can also be seen that the minimum load falls within a range of 40-50% of nominal power for all technologies but pumped storage. This is primarily due to technical reasons. Indeed, new power plants or retro-fitted installations can go as low as 25-30% of nominal power.

Two decisive facts emerge from analysing these values of power plant flexibility and comparing them with the characteristics of variable generation.

Firstly, one has to distinguish between demand-driven fluctuations and generation-driven fluctuations. Demand-driven fluctuations are made up of the sum of the behaviour of individual consumers and determine the load curve. The roll-out of smart grids and demand-side participation can lead to peak-shaving, whereby load curves progressively flatten and differences between days and nights are minimised to the point of disappearing in the longer run. As a consequence, the demand for balancing the requested load changes will become less relevant.

But for the generation-driven fluctuations, or power ramps, a completely new type of flexibility is developing. The change velocity of these power ramps is very high, much higher than the load change rates of old and even new power plants. Only storage facilities such as pumped storage and hydro storage schemes with peak generation are able to cope with these high power ramps and can provide active power within a short period of time. However, that does not prevent other technologies (such as gas-fired plants) from playing an important role in meeting the flexibility challenge.

3.3 impact of load-following on power plant efficiency and emissions

Another issue arising from increased v-RES generation is the existence of trade-offs associated with the use of conventional plants to back up v-RES. When the wind is not blowing or the sun is not shining, gas-, coal-, and oil-fired plants20 are dispatched to supply the needed electricity and to maintain the safety requirements of the electrical grids. This releases both carbon dioxide and atmospheric pollutants such as NO

x, SO

2 and dust which

would not be emitted by RES plants if they had operated.

While this effect is well understood, the effect of part-loading21 on the efficiency – and hence emissions – of conventional thermal power plants is often neglected.

Even the most efficient fossil-based power plant – a combined cycle gas turbine plant –will see efficiency drop significantly below its ‘normal’ efficiency when it is not used at its rated full power. Whilst CCGTs usually operate at an efficiency level of about 55%, the efficiency drops as low as 35% when its load is reduced to 50% or less of the rated power output – an efficiency reduction of 20 percentage points! Part-loading of coal-fired plants and nuclear plants reduces efficiency by about (maximum) 10 percentage points. Reciprocating engines (or piston-engine-based plants) such as gas-fired spark-ignition engines also have efficiency reductions in the order of 5-10 percentage points when operated at 50% load (state-of-the-art engines are more efficient than older engines), whilst diesel engines perform better, with output barely changing when load drops from 100% to 50%22. The lower the efficiency, the smaller the power produced with a given fuel input – and vice versa.

The drop in efficiency has (limited) effects on plant emissions: the higher the efficiency, the smaller the quantities of CO

2 and atmospheric pollutants produced

per unit of electricity23. Consequently, a power plant operated in part-load actually emits more CO

2 and

atmospheric pollutants per kWh produced than if operated at full nameplate capacity24.

20 Alongside other dispatchable renewables and nuclear.

21 Part-loading refers to the operation of a power plant at a power output level lower than the nominal rated power, where the latter stands for the maximum technical capability of the (used) machinery as certified by the responsible licensing authority. The capability to run power plants in part-loading is a fundamental characteristic of dispatchable generation technologies because their output is controllable in real time by the plant operator.

22 Paul Breeze, Power Generation Technologies, 2005, page 78.

23 Ibid, page 48.

24 Indeed such considerations do not apply to nuclear power plant operated in part-load as they do not emit any CO2 in any cases.


This represents a sort of a paradox. Conventional thermal units that are dispatched at part-load because of the growing share of v-RES – to maintain safety and stability by varying their output according to v-RES behaviour – are penalised by the laws of thermodynamics and become less efficient, more polluting machines.

A sound (technical) understanding of such peculiarities – coupled with a better understanding of the links between the multiple policies enforced at EU level – by policymakers would be desirable. At the very least, the importance of technical features should be acknowledged when considering strict efficiency requirements on generating plants. The more restrictions are placed on such plants, the less suitable they become to perform the essential role of back-up needed to favour v-RES penetration, to the detriment of overall EU energy and climate policy.

Although not at the core of this report, the relationship between the efficiency of power plants and the related emissions needs careful consideration and clarification. The EU has progressively enforced an environmental policy whereby industrial installations including power stations are granted permits to operate only if they emit regulated quantities of local pollutants, including inter alia nitrogen oxides (NO

X) and sulphur dioxide (SO

2).

Those molecules are the inevitable result of fossil fuel combustion, as they are either contained in the fuel or are created by oxidation while burning.

The main piece of EU legislation that applies is the Large Combustion Plan Directive (LCPD), which will eventually be replaced by provisions contained in the Industrial Emission Directive (IED) adopted in November 2010. In addition the National Emission Ceiling Directive – which limits the emissions on the basis of areas, e.g. member states or regions – is in place. Pursuant to these directives, power plants have to comply with certain emission limit values. Operators thus use a wide range of techniques to remove particular compounds from the flue gases emitted at the power station’s stack(s)25. Such processes are energy-intensive, resulting in an efficiency penalty to the plant. A clear trade-off emerges: justified environmental policies negatively affect power plants’ energy efficiency.

3.4 lifetime management of power plants in a baseload and load-following mode

Another important issue worth exploring is the conse-quence of a more flexible operation mode on the lifetime of the plant, particularly with respect to some of its components. The embrittlement of material used in any technical machinery entails a certain fatigue mechanism; i.e. the designed lifetime for a specific component decreases.

Increased flexibility requirements for the conventional fleet and the resulting load following imply higher operation and maintenance costs. Components will have to be replaced and maintained more frequently. However, the impact may vary greatly across generation techno-logies and could be mitigated through more sophisticated and smarter lifetime management processes.

25 To mention only some of them, Flue Gas Desulphurisation (FGD) units clean up flue gases before those reach the stacks by using a mixture of limestone, which results in production of gypsum and removal of up to 90% of the sulphur dioxide. Other techniques include electrostatic precipitators, which are meant to remove particulate matters and dust from flue gases using electric charges, and Selective Catalytic Reactors (SCR) to reduce NO

x emissions.

variability and flexibility in the eu member states

4


This chapter analyses three different European expe-riences to better understand the dimension of the v-RES challenge.

The three cases are Germany, Spain and the Nordic system. The first two countries were chosen because they have been among the countries that have most strongly pushed the development of v-RES over the last few years. Spain, in particular, is a showcase for the effects that more v-RES can have on the electrical systems of today. Scandinavia was chosen as possibly the best example in Europe of a growing share of v-RES in a system that has moved towards full merging of national markets. It thus gives the reader a better idea of how regional cooperation (as a step towards a broader, EU-wide system) would help integrate v-RES.

4.1 the case of Germany: a multi-pronged approach26

In 2010, BDEW, the German Association of Energy and Water Industries, examined possible structures of energy generation in 2020 and 2030. The study focused on the systemic prerequisites to integrating RES, especially volatile wind and solar. It takes into account the obligation set out in German law of reaching a target of at least 35% of RES-e in the system by 2020 (supplemented by a CHP share of 25%).

RES were considered to be the leading system which means that a new energy system is supposed to be built in accordance to the characteristics of RES. This meant that all flexibility sources (i.e. high and steep load ramps, back-up and storage facilities) were to be assessed in terms of their ability to integrate RES volatility and optimise the energy system as regards security of supply and affordability. The chosen approach covered supply, demand, and systemic issues. It will be assessed more thoroughly during 2011.

the issue

An increasing generation from v-RES is a major challenge to the conventional system. The main problem is coping with sudden load ramps, for instance increasing wind generation and reduced demand at the beginning of a weekend, and the opposite at the beginning of the week. Figure 11 (top graph) shows just such a situation that occurred in Germany in 2009. The main challenge then was to cope with a load ramp of 30 GW within a few hours. A projection of the same weather pattern for 2020 with almost double the wind capacity would imply a load ramp of 50 GW (bottom graph).

26 The present report was being finalised when the Tohoku earthquake struck off the costs of Japan and caused the tsunami that led to the Fukushima accident. The known reaction of the German government to reverse the previous extension of and phase-out nuclear power came in the aftermath of Fukushima and is logically not embedded in the case scenario described in this paragraph.

Source: BDEW

Figure 11: Currentandfutureflexibilityandback-upcapacityrequirements in Germany

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Figure 11 thus demonstrates that some additional 20 GW of flexibility is needed in the German energy system by 2020. Therefore, solutions need to be found regarding how to deal with (1) the amount of flexibility needed and (2) the gradient of the load ramp.

flexibility sources in germany

The amount of flexibility in nuclear generation is estimated at around 8-10 GW, based on an installed capacity of 20 GW, half of it being available for flexibility service at a load gradient of about 5% per minute27. Operating costs of nuclear power plants are low, though a reduced load factor reduces their cost-effectiveness.

The amount of flexibility in the field of coal-fired power plants is estimated at around 1.5 GW from hard coal, based on an installed capacity of 30 GW (including CHP), and 2 GW from lignite, based on 22 GW installed capacity. 5% of both is available for flexibility service, with a load gradient of 2-3%/min. Operating costs vary from low to medium-sized, however the reduced load factor will again affect cost-effectiveness.

Biomass could count for 3 GW of flexibility: 6 GW of installed capacity are estimated for 2020 and half of this could be available for flexibility services at 5-10%/min. In addition, RES – including wind – could help to reduce (or balance) load gradients depending on its geographical allocation.

The amount of flexibility of gas-fired power plants is estimated at around 15 GW (7 GW of which newly built), based on 25 GW in 2020 with more than 60% available for flexibility with high quality and quick reaction. Operating costs are low to medium-sized due to low CAPEX and relatively high OPEX. Small plants could easily be combined and dispatched as virtual power plants.

Along with flexibility of power plants, electricity demand can be transferred to periods of high v-RES generation without reducing overall consumption, hence reducing (expensive) load gradients. Markets and regulation would have to be improved to really take advantage of demand-side participation. The possible amount is considered at around 2 GW.

Storage facilities can be provided to decouple supply and demand either within the electricity system (i.e. batteries, pumped storage) or by transforming it into other products (heat, etc.), in either the short or long term. Classic technologies available include pumped storage; however their additional volume is limited, for instance by complex permitting procedures. Compressed air, batteries, or hydrogen/methane-systems are innovative but limited for

the foreseeable future. The potential contribution of these technologies is estimated at around 1.5 GW. Additional potential from existing CHP/district heating-systems can be estimated at around 5 GW by buffering energy in the heating system at considerably lower costs.

the role of export management and grid extension

Fluctuating residual loads can bring forward arbitrage contracts with countries or systems with less fluctuating load. Of course this requires a sufficient infrastructure which mainly depends on the elimination of bottlenecks and the extension of the grids.

Germany’s Energy Agency Dena has pointed out that the German transport system alone has to be extended over 3,600 km (or 10% of the current transmission grids) until 2020 (basic scenario without considering storage facilities). This would require an investment of about 10 billion Euros. Of course the final amount of investment mainly depends on the architecture of the future energy system in Germany. More intelligent generation management will require less grid extension and vice versa, as another study for the German Economic Ministry (Consentec, r2b) pointed out last year.

Over the last months the discussion in Germany has also begun to address the distribution system. Since v-RES are to a large extent connected to the distribution grid, considerable growth of the distribution system is required. BDEW has estimated that about 195,000 km of new distribution grid (or 15% of the current distribution networks) are needed to absorb RES in 2020. This would require an investment of about 10-13 billion Euros (figures in both cases are based on the German Energy Scenarios).

Of course there is no linear relation between the need for more new grids to transport the same amount of planned new RES according to the government targets. Once new transport lines connect new RES centres (e.g. offshore or near offshore) with existing centres of demand, this system as a whole can absorb even more than 35% of RES in 2020. The task of the future will lie in managing the transition between the existing system, which was built to connect large supply facilities with centres of demand, and the new system, which will have to connect a more decentralised generation structure with the same centres of demand.

summary

The additional flexibility required for the German energy system can be provided by existing or feasible new facilities in the next years. Taking into account the

27 This estimate is taken from the mentioned study, i.e. it refers to a pre-Fukushima scenario where nuclear power still played a role in the German energy mix. See note above.


projected increase of renewables to a share of at least 80% by 2050 (mainly v-RES), and given the fact that the load factors of conventional plants will be considerably reduced, new regulatory instruments seem necessary to stimulate new investments.

4.2 spain: where future happens today

Spain has seen a very significant v-RES penetration over the last 10 years, and even more intensely from 2008-2010. This has led to a significant change in the power generation mix and has pushed conventional generators (particularly coal and CCGTs) towards a much more flexible operating regime.

the spanish electricity system

The key figures below illustrate the size of the (mainland) Spanish electricity system:

More than 35,000 km of high-voltage transmission lines, although the country is still barely connected to the rest of Europe, having only limited interconnections with France;

260 TWh of demand (year 2010);

97.4 GW of installed generation capacity (as of 31 December 2010);

44.1 GW of maximum peak load28 in 2010 (recorded on 11 January at 19h00).

The figure below shows the typical power demand curve for a winter day (21 January 2011).

power demand and generation capacity evolution

After almost 25 years of uninterrupted strong demand growth, electricity demand showed signs of weakness in 2008 (with only a very slight increase of 0.8%), then fell sharply in 2009, with a decrease of 5% compared to the previous year. In 2010, demand has recovered somewhat, growing 3.2%.

As regards generation capacity, it has almost doubled in the last ten years, growing from 55.5 GW in 2001 to 97.4 GW at the end of 2010.

The growth of generation capacity can be explained as a combination of:

A true need for significant amounts of new capacity. Between 1995 and 2000 no capacity had been added to the system, resulting in a falling reserve margin that reached a minimum in 2001 (1.07 GW). All incumbent operators and some newcomers therefore embarked on a “dash for gas” to develop new combined cycle plants.

A very favourable regulatory scheme to support renewable energy sources, in particular wind power and, after 2007, solar energy.

Source: Red Eléctrica de España

Figure 12: Typical shape of the Spanish load curve in wintertime

28 The highest peak demand in the Spanish system – 45.5 GW – was registered on 17 December 2007.


Figure 13: Evolution of the electricity demand in Spain in the last decade (GWh)

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26

As a consequence, RES and CCGT generation capacity boomed during the last decade, as shown in Figure 14. In 2010 RES and CCGTs became the two largest sources of generation in terms of installed capacity. On the other hand, two thirds of old conventional oil/gas-fired units have been decommissioned (from 8.2 GW to 2.8 GW)29.

res penetration, wind generation and variability30

As displayed in Figure 14 above, RES installed capacity has increased from 2.4 GW in 2000 to almost 25 GW, representing today one fourth of total capacity in main-land Spain. Wind farms are by far the greatest RES con-tributors, with capacity reaching the 20 GW milestone in 2010. Solar PV has also grown significantly in the last three years, with 2,600 MW connected to the grid in 2008 alone.

Wind energy output has been constantly achieving new records in the last few years. On 9 November 2010 wind farms generated 315 GWh or 43% of the electricity consumed that day. At 3h35 of the same day, wind output covered 54% of demand31.

Of course, Spain is not exempt from wind variability. Figure 15 shows how wind output and its contribution to demand coverage can vary for two winter days with similar demand (total demand of about 760 GWh and peak demand of about 38.5 GW).

On 25 February 2010, wind capacity operating at a load factor of 50-70% covered 30-40% of total daily demand. On 10 December 2009, the load factor was as low as 10%, with a contribution to the generation mix of well below 10%.

As shown earlier in the paper, wind energy is quite difficult to predict accurately, although forecasts continue to improve. The mean difference between forecast (30 hours ahead) and generation was above 25% in 2005. In 2008 this error had decreased to 17%. However, Figure 16 shows that errors still occur. On 2 November 2008, at 0h00, the forecasted wind output for 7h00 was 5 GW, but actual output was 50% higher.


Figure 14: Evolution and structure of the Spanish generation fleet in the last decade

29 This remaining 2.8 GW is expected to be closed within the next five years.

30 It is worth mentioning that the wind industry in Spain has also contributed to integrating its variable output through stringent operational and technical requirements, for instance voltage dip requirements or connection to renewable control centres.

31 At the time of writing, the mentioned figures are the highest daily and instant wind generation shares ever registered.

Figure 15: Wind output and contribution to demand coverage in Spain during two days with comparable electricity consumption and peak demand

Figure 16: Wind forecast error in Spain


Source: Red Eléctrica de España, figure in EURELECTRIC, Integrating Intermittent Renewables, March 2010

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0

0:00

8000

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6000

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d P

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uct

ion

in M

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Time 02/11/2008

-2000 MW

sipreólicoreal productionmarket program

-2500 MW


impact on conventional technologies

We have seen how, on the one hand, there have been large additions of new capacity to the system as a result of the combined “dash for gas” and “dash for wind”. On the other hand, after many years of sustained growth, demand decreased in 2008-2010. This has led to over-capacity in the system.

Because RES are dispatched first and at zero variable cost32, thermal units (coal and CCGTs) have seen their utilisation rates plummet.

This effect has been particularly painful for less com-petitive plants, i.e. older domestic coal plants.

The situation for thermal units was even worse between fall 2009 and spring 2010. A very rainy year, combined with the windy season, led to a number of coal units being kept idle for six months and more.

In addition, the average wholesale market price has fallen and has also become more volatile.

System operation is now more complex, with a higher level of balancing services needed, in particular tertiary and spinning reserves. In 2007, the energy involved in tertiary reserve was 3,859 GWh. In 2010, this energy amounted to 5,709 GWh.

Thermal generators have to cope with higher flexibility requirements. For example, CCGTs are often operated either in:

“Two-shifting” mode, i.e. running during the day and stopping during the night;

“Spinning reserve”, being kept on-line at very low load (i.e. technical minimum load), in particular during hours of low demand and high wind generation.

The figure below shows an extreme situation on 3 March 2010 when only one CCGT unit was operating during off-peak hours, while up to 27 CCGT units were running during peak hours.

actions taken by generators

Generators have taken a number of actions to better cope with the very high RES penetration in the Spanish system.

Since thermal plants are experiencing lower utilisation rates:− Generators are working to translate lower activity on

operation and maintenance costs by modifying the structure of maintenance contracts to make them as variable as possible (i.e. ensuring that contractor costs are linked to actual utilisation).

− In case of plants with multiple units, operators are putting one or more units in cold reserve shutdown, while the rest of units are kept available to the system.

32 The Spanish regulation also allows cogeneration plants to bid at zero marginal cost, hence exacerbating the pressure on other generators.

Figure 17: Utilisation rates for coal and CCGTs

Figure 18: Evolution of generation in Spain on 3 March 2010

Source: Red Eléctrica de España, figure elaborated by Endesa

Source: Figure elaborated by Endesa, data from Red Eléctrica de España

coal ccgt

8 000

7 000

6 000

5 000

4 000

3 000

2 000

1 000

0

-47%

av. 05-07av. 05-07

av. 09-10av. 09-10

-30%

nuclearcoal hydro

imports - exportswindrest of res + chp ccgt

fuel oil + gas

21 22 23 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 20 21 21 22 23

cum

ula

tive

gen

erat

ion

by

tech

no

log

y (M

W)

0

-5000

5000

10000

15000

20000

30000

25000

35000

40000

1 combined cycle unit during off-peak hours

27 combined cycle units during peak hours

28

Higher flexibility is requested from conventional units:− In CCGT units, generators are assessing the

possibility of reducing technical minimum load to avoid being shut down during hours of low demand.

− As for nuclear plants, a joint working group has started studying the requirements whose imple-mentation could be necessary to allow nuclear units to perform “load following” (i.e. load reduction) during the night. Unlike French or German nuclear plants, Spanish nuclear plants are currently operated in a pure baseload mode. Load following would require a lower percentage of uranium enrichment inside the reactor. However, the nuclear supervisory body (CSN) eventually rejected this possibility.

A higher level of reserve is needed:− Hydro plants are offering a higher level of their

generation capacity in the balancing markets (tertiary reserve).

− The two largest generators in Spain (Endesa and Iberdrola) are developing projects to build new capacity and repower existing pumped storage power plants, which will provide tertiary reserve and storage for excess wind generation.

At the same time, the Spanish regulator has issued a decree setting a minimum level of generation corresponding to approximately 5,000 hours per year for units burning domestic coal (10 units in total, combined capacity of 4.5 GW). This generation is dispatched as a technical constraint in the market and the generated electricity is paid at a regulated price covering both fixed and variable costs. This decree implies that additional flexibility is required from plants using imported coal, as well as from CCGTs.

summary

Conventional generators are currently providing the flexibility that the Spanish electricity system needs to accommodate the development of v-RES, despite experiencing shrinking margins due to plummeting operating hours of their power stations. In particular, the flexibility provided by CCGTs (operated in two-shifting mode) has allowed the system to integrate large amounts of v-RES more easily and successfully.

The country can be seen as a pioneer in the field of variability and flexibility due to the high level of v-RES in the system and the changes implemented as a reaction to the associated challenge.

4.3 the nordic system: the power of water and cables

Sweden, Norway, Finland and Denmark constitute one well-functioning electricity market (Nord Pool) and have also well established cooperation mechanisms between TSOs (Nordel) to operate as a single common grid. The total yearly generation is 370 TWh, of which 55% comes from hydro, 20% from nuclear, 15% from fossil fuels and 10% from other sources. Denmark, which has no hydropower, started to massively introduce wind earlier than others; today 9 TWh or 25% of the country’s total generation comes from wind.

The large hydro generation base gives the system some special characteristics. A huge storage capability (120 TWh on a seasonal basis) is accompanied by a large flexible generation capable of withstanding the large variations between night and day, cold or warm temperatures, or load variations enforced by RES variability. The hydro units also make the power system robust with a good ability to handle sudden disturbances in both transmission and large generating units. A very good stability in frequency and voltage is easily attained by accessing the many hydro units with large rotational inertia and ability for fast changes in power output.

Similar to the rest of Europe, the Scandinavian countries have a high ambition to increase RES generation. In the next decades the majority of these additional resources will come from wind. Assessments of large-scale wind introduction scenarios have been performed by different stakeholders. They show that a moderate introduction of wind may be handled by the existing transmission system and flexible generation sources. A higher level of wind introduction may however cause issues both for the transmission system and the location of wind generation. In addition to the intra-Scandinavian scenarios there are also possibilities to transmit regulating capacity to other parts of the European grid via interconnections, which could also influence the upcoming planning within the Nordic countries.


flexible generation capacity in sweden and norway: the existing system

The yearly electrical consumption in Sweden and Norway is around 270 TWh. The main generation source is hydro which (as a statistical mean) contributes 200 TWh.

The load has a strong seasonal pattern with a high consumption in wintertime – see example from Sweden below. The inflow into rivers from precipitation or from melting snow also has a strong seasonal pattern and is not correlated to the load pattern.

These seasonal imbalances between load and incoming flow have led to the establishment of huge storage capacities to secure supply at every time of the year. The storage capacity in Sweden (whose use is shown below) corresponds to 34 TWh and in Norway to 85 TWh.

Furthermore the incoming flow may vary substantially between years both in total amount and the timing of spring floods. There are also load patterns on a weekly and daily basis where the storage capabilities are used to match demand.

The Nordic power system is thus designed to have a large flexibility on a long timescale. Nevertheless, for most of the rivers and power plants this flexibility is also accessible at shorter timescales.

There are very few pumped storage plants in the Nordic power system, hence validating the idea that the balancing needs are currently fulfilled by the existing hydro plants. In other words, even when a large portion of hydro is running, there is still both downward and upward regulating capacity which is also sustained by the storage capacity embedded in the reservoirs.

The maximum power capacity is designed for an extremely cold winter day. This means that there is capacity available both in generation plants and transmission lines most of the time. The capacity in Sweden and Norway together is 65 GW of which hydro represents 70%, or 45 GW.

Figure 19: Yearly consumption and rivers’ inflow in Sweden

Figure 20: Reservoir storage level in Sweden

Source: SvenskEnergi, “Power situation in Sweden in spring 2011”

Source: SvenskEnergi, “Power situation in Sweden in spring 2011”

Jan SepMar May JulSep Nov

4.0

3.0

2.0

1.0

0

TWh

/Wee

k

Past 52 weeks

Prior period

Electricity usage per week

Dec OctFeb Apr AugJunAug Oct

10

7

8

9

4

5

6

2

3

0

1

TWh

/Wee

k

Past 60 weeks

Prior 60 weeks period

Median

10% resp 90% probability

Estimated inflow (not spill corrected)

Dec OctFeb Apr AugJunAug Oct

100

70

80

90

40

50

60

20

30

0

10%

Max. / min.

Prior 60 weeks period

Past 60 weeks period

Average

30

There are many interconnections to other countries and the possibilities for export and import are used to balance seasonal patterns and differences in shorter timescales. The net export/import per year varies typically between +/- 5 TWh, which is not much compared to the combined capabilities of the transmission grids of 6 GW. Figure 22 shows a very dry year in which imports dominated. The peak was registered in wintertime, and during the spring flood the transmission lines were used for export.

There is also a geographic dimension within the Nordic countries to be taken into account. Most of the demand is in the southern part, whereas most of the Swedish hydro generation is in the northern part. In Norway a large portion of hydro generation is in the southwest corner. This situation has prompted investments in high transmission capabilities from north to south and also from west to east in southern Norway, and further into Sweden (see the figures of the transmission grids in the next chapter).

flexible generation capacity in sweden and norway: the future situation

There are several trends that will contribute to change the future demand for system services provided by hydro plants in the Nordel system. A fast growing share of v-RES in the system will increase the need to handle power ramps, balancing services and capacity planning. A growing variability in consumption patterns may add to the variability from RES especially for balancing intraday needs.

A large share of geographically distributed v-RES will create new and different load situations in the grid. These totally new situations may trigger faults not detected earlier or create a less robust situation in case of major disturbances in the grid. This may cause an extra need for actions in the power system and/or system services.

Extreme weather situations such as extreme temperatures (either cold or warm), heavy storms and/or snow blizzards are one of the major causes of power system disturbances. Climate change will exacerbate the frequency of such occasions; this is why more investments in the power system and preparedness services may be foreseen.

The Swedish TSO Svenska Kraftnät has estimated the increased service needs resulting from large-scale wind introduction in the Nordic system. Their conclusions are summarised in the table below. There is a good chance that hydro operators may deliver these capabilities with existing plants.

In a university study sponsored by the Swedish Electrical Branch research organisation the balancing capacity of the hydropower system in northern Sweden was studied for different wind introduction scenarios33. The modelling used historical data series of wind and load and considering 154 hydropower plants with a total installed capacity of 13,200 MW (i.e. about 80% of Swedish hydropower). Hydrological couplings and water handling permits were explicitly included. The transmission limitations between northern and southern Sweden were also considered, as well as the export limitations to Norway and Finland respectively.

Figure 21: Trade patterns in Sweden

Source: SvenskEnergi, “Power situation in Sweden in Spring 2011”

Todayadding 4,000

mW of wind

adding 12,000

mW of wind

Automatic normal reserve (frequency controlled)(MW / 0,1 HZ)

600 850 1,350

Balancing reserve (Intraday)(MW)

Add 600 Add 1,900

Capacity reserve (no wind)(MW)

900 2,700

Table 4: Service needs in Sweden at current wind penetration, as well as considering two different growth scenarios

Source: Svenska Kraftnät, table elaborated by Vattenfall Hydro

Jan Mar May Sep

2008

2009

2010

2011JulSep Nov

0.8

0.6

0.2

0.4

-0.4

-0.2

0

-0.8

-0.6

9

6

3

-3

0

-9

-6

TWh

/Wee

k

TWh

to S

wed

en

Import

Export

fro

m S

wed

en

PolandGermanyNorwayDenmarkFinlandNet total

Through week 38Full year value


The results showed that during normal conditions, hydrological constraints and permits allow hydropower to be used for balancing of hourly variations, even for large amounts of wind power. Very large wind introduction, i.e. 30 TWh in Sweden, resulted in some adverse effects on hydro generation (spill) and also (sometimes) transmission constraints.

tso views, internal and external transmission, regulating capacity

The transmission pattern in the Swedish and the Norwegian transmission grids depends mainly on the inflow into the hydropower system and the distribution of generation and consumption. In Sweden, most hydropower generation is located in the north or the middle of the country, while nuclear and thermal generation, as well as the main consumption centres, are in the south. Northern Sweden and southern Sweden are connected through several high-voltage power lines. In Norway, generation and consumption are more evenly distributed with some concentration of large hydro plants in the south west.

Along with the assessment of service needs presented above, Svenska Kraftnät has assessed the consequences of a large-scale introduction of wind for the development of the power grid. They have concluded that 10 TWh of wind in Sweden will probably not lead to extra transmission investments. However, a 30 TWh/year wind generation increases the need for more transmission. This will translate into different investments depending on the location of the wind sources. If large-scale wind was introduced in the north, it would compete with hydro resources for access to transmission lines. Figure 23 shows the Swedish and the Norwegian transmission grids (300 kV and 400 kV), with the blue circles representing major hydro generation areas.

Regarding scenarios with changes in demand and generation together with an increased international connection there are identified needs for reinforcements of the grid. The prognosis for the situation in neighbouring countries in 2020 is an important input to these plans. A joint master plan was elaborated by Nordel in 2008. The figures below depict the Nordic Grid Master Plan – which prioritised the reinforcements in the Nordic grids – and the estimated generation mix in 2020 in Scandinavia and the neighbouring countries respectively.

Figure 22: Location of major hydro units and transmission lines in Norway and Sweden

Source: Svenska Kraftnät and Statnett, “Swedish-Norwegian grid development”

33 M. Amelin, C. Englund, A. Fagerberg, “Balansering av vindkraft och vattenkraft i norra Sverige” (“Balancing of wind power and hydro power northern Sweden”), Elforsk report 09:88, September 2009.

Figure 23: The Nordic Grid Master Plan

Source: NORDEL, Nordic Grid Master Plan, March 2008, in Svenska Kraftnät and Statnett, “Swedish-Norwegian grid development”

Previously proposed1. Fenno-Skan II (Decided) 20112. Great-Belt (Decided) 20103. Nea - Järpströmmen (Decided) 20094. South Link (Decided)* 20145. Skagerrak IV (Letter of Intent) Prel. 2014

Proposals for possible new reinforcements6. Sweden - Norway (South)* SouthWest Link Prel. 20157. Sweden - Norway (North-South axis) Ørskog - Fardal Prel. 20138. Artic region Ofoten - Balsfjord - Hammerfest Prel. 2014

* Combined in the “SouthWest Link”

Possible external reinforcements (Not prioritised)

Reinforcements requiring additional analysis

9. Finland - Sweden

National reinforcements of importance to the Nordic grid

Decided or planned

Under consideration

32

The new interconnection planned between Norway and Denmark (Skagerrak IV) will be the first in Europe to reserve part of its capacity for system and balancing services. Sweden and Norway will also benefit from the opportunity to import system and balancing services in certain situations. Already today there are periods when consumption can be covered by deregulated power generation and low-priced imports through the cross-border interconnections.

handling a storm front in the nordic existing power system

An example of the balancing needs in the Nordic region is presented in Figure 25, using a storm front moving towards Denmark in January 2005. Denmark is quite small, with a north-south shoreline; therefore when a storm front approaches and wind speed is particularly high, all wind farms get disconnected within a short time period.

The storm caused wind power plants to shut down from maximum production to nearly zero (the green dotted line): in a period of 6 hours wind generation decreased by 1,800 MWh. The downward generation ramp in Denmark was balanced by hydropower from Norway (red dotted line). The sea-based cable transmission line (blue dotted line) changed direction from export (about 1,000 MWh during the night and the first hours of the day) to import (up to 1,000 MWh when the storm was pounding the Danish coasts during the day), as viewed from Denmark.

summary

The Scandinavian region has two strong assets in facing the increased requirements for flexibility that the introduction of v-RES has recently induced: hydropower and a physically and operationally well-interconnected market.

Hydropower will retain its fundamental role of balancing energy in the region, whilst further interconnections to mainland Europe, as well as the development of new market arrangements (such as the market coupling project under development), will make the region even more important on a European scale.

Figure 24: Estimated generation mix in the Scandinavian region in 2020

Source: ENTSO-E, in Svenska Kraftnät and Statnett, “Swedish-Norwegian grid development”

Figure 25: Correlation between a storm hitting the Danish western coast, Danish wind production and the balance of flows between Denmark and Norway

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

1 0001 2501 5001 7502 000

750500250

0-250-500-750

-1 000

MW

h/h

180 km Hour

8 January 2005

transm. DK1 - > NO1balance norw. (NO1)wind P. DK1

Source: North European Power Perspectives (http://www.nepp.se/organisation.htm)

2020

nuclear powerfossil fuelsres capacity (excl. Hydro)hydro powerother

the flexibility challenge and its impacts

5

34

5.1 economic viability of dispatchable power plants and the impact of flexibility on the levelised costs of electricity

Power plants that run unevenly through the year have higher costs compared to similar plants that can be dispatched around the clock, all year long. Multiple factors deserve consideration when examining the impact of load factors on generation costs.

The distinction between capital costs and fuel costs, for instance, implies that gas-fired power plants are the least affected by reduced load factors as their economic performance depends more on the fuel costs rather than on the capital costs. If a gas-fired plant is kept shut because high fuel costs increase its marginal cost, this has a more limited effect on the plant’s profitability (i.e. the revenue stream). Coal and nuclear power plants, by contrast, have higher capital costs and lower fuel costs, and are thus more sensitive to reduced operating hours during which the fixed costs cannot be recovered.

A distinction also needs to be drawn between older and newer plants. Old plants have lower capital expenditures (close to zero) because of depreciation. Therefore only fuel costs – and maintenance costs – have to be considered, resulting in a more positive merit order.

In addition, generation costs will be affected by the increased need for maintenance of plants that are frequently shut down and restarted. This will be reflected in the variable operations & maintenance (O&M) costs.

At this point, it makes sense to introduce the concept of levelised cost of electricity (LCOE). LCOE is a tool used to enable comparisons between the costs of different generation technologies and “would correspond to the cost of an investor assuming the certainty of production costs and the stability of electricity prices. […] The calculation of the LCOE is based on the equivalence of the present value of the sum of discounted revenues and the present value of the sum of discounted costs”34. Figure 26 shows the LCOE for different generating techno logies.

34 IEA, Projected Costs of Generating Electricity, 2010 Edition.

Figure 26: Levelised costs of electricity for the main power generation technologies

Source: VGB, Investment and Operation Costs Figures – generation portofolio

Gas open cy

cle

* for > 2015 ** without pumping costs

Gas CCGT

Hard co

al 600

Lignite

600

Hard co

al 700*

Lignite

700*

HC 700 + CCS*

HC 600 + Bio cofir

ing

Nuclear E

PR 1600*

Pump storage

**

River

Wind Onsh

ore

Wind off-sh

ore close

Wind off-sh

ore far

Solar PV 2800€/k

W

Solar PV 3200€/k

W

Solar CSP 3200€/k

W

Solar CSP 3500€/k

W

Biomass 100€/t

80

90

100

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120

70

60

50

40

30

20

10

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EUR

/MH

h

hydro

wind

solar pv

biomass

co2 costs eur/mwh

fuel costs eur/mwh

o&m costs eur/mwh

invest costs eur/mwh

160

180

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140

120

100

80

60

40

20

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EUR

/MH

h

fuel costso&m costsinvest costs

solar csp


An important consequence of the increasing v-RES capacity is a decrease of the annual operating hours for the conventional fleet, leading to a decline in baseload power. Although generation fleets are split into baseload, mid-merit and peaking plants, the reduction of the operating hours is remarkable when assessed on an average basis.

This reduction has a major impact on the generation costs, because the relation between costs and operating hours is non-linear. Figure 27 shows the simplified LCOE as a function of the equivalent full operating hours. If a newly built CCGT operated between 2,000-3,000 hours per year, its generating costs (between 8-10 Eurocent per kWh) would be higher than the average electricity price on the market (roughly 50-60€/MWh for baseload power); hence generation costs will not be covered35. In contrast, a CCGT which has recovered 70% of its costs would have generating costs of 4.5-5.5 Eurocent per kWh, and would thus be able to compete for baseload supply. At the same time, variability with its accompanying technical challenges will also increase the demand for network services, so-called ancillary services, and will lead to higher prices for this type of services.

EURELECTRIC has already voiced its request for an appropriate market model to deal with such situations in another RESAP paper36.

5.2 the impact of negative prices

Negative prices have to be seen as an intermediate characteristic of the current transitional phase. They are the consequence of opportunity costs, i.e. it is less costly to operate the plant at even negative prices for a very limited period of time than to shut down the plant. This allows the plant operator to prepare for the expected increase of demand and/or market conditions bringing/promising higher prices.

Why do we believe this will only occur during a transitional phase? Variable RES are still (relatively) limited, but as they increase the opportunity to compensate negative prices will vanish because the risk in remaining operational will become too high. The only option left then will be to shut down the plant (with all the consequences described so far).

5.3 the impact of increasing v-res on the functioning and operation of gas markets

As described in the preceding chapters, gas-fired power stations will be one of the most important contributors to the integration of v-RES by providing flexible and back-up services. Unlike coal, oil or water which can be (to a great extent) stored close to the power stations, natural gas is supplied continuously from the main high-pressure transmission lines to the main off-takers (such as power stations) and distribution networks, and can be directly stored in the pipelines only in limited amounts by means of line-pack37. Higher requirements for flexible gas-fired plants lead to the need for a more flexible gas supply, which in turns results in a greater need for storage, line-pack and LNG supply.

35 Carbon allowance prices and margins are not included.

36 EURELECTRIC, RES Integration and Market Design: are Capacity Remuneration Mechanisms needed to ensure generation adequacy?, May 2011.

37 Line-pack consists of storing gas directly in the pipelines by manipulating their pressure.

Figure 27: Examples of levelised cost of electricity for a brand new CCGT and an older CCGT whose investment has been 70% paid off

16

18

14

12

10

8

6

4

2

0

Gen

erat

ion

co

st, €

cen

t/K

Wh

Yearly operating hours

0 1.000 2.000 3.000 4.000 5.000 6.000 7.000 8.000

CCGT new

8

9

7

6

5

4

3

2

1

0

Gen

erat

ion

co

st, €

cen

t/K

Wh

Yearly operating hours

0 1.000 2.000 3.000 4.000 5.000 6.000 7.000 8.000

CCGT 70% paid off

Source: VGB PowerTech

36

An analysis from Pöyry on the likely impacts of wind generation on the British and Irish gas markets will help to better understand the challenges for the gas markets38. Figure 28 shows the gas demand of the power sectors in the two markets, based on actual data for the gas year 2007-2008 and projecting the same pattern for the gas years 2009-10 and 2029-30, while assuming a high build of wind generation with gas-fired generation keeping pace. The volatility of the power sector’s gas demand – described as “gas intermittency” – is evident from the green lines. In particular, demand in the British market could drop as low as 1-3 million cubic meters per day (mcm/d) and reach up to 110 mcm/d within just a few weeks. Total gas demand, by contrast, would be much less volatile. Households, the commercial sector and industry are far more stable and predictable, hence easing gas intermittency from the power sector39.

From this starting point, Pöyry has modelled the evolution of the supply mix in the gas years 2019-20 and 2029-30, building on the actual daily supply mix of the gas year 2008-09 (see Figure 29 below). It can be seen that the country still hugely relies on its domestic production, and that the interconnectors were mainly used to export gas towards the continent. One could also observe that when gas demand was at its peak during the winter season, gas from storage was crucial to keep the system balanced. Indeed, even in the winter season there were several days where injection took place, probably driven by the lower gas demand during the holiday season.

But what will happen when the power sector’s demand for gas will start to fluctuate more because of the increasing role of wind output? Figure 30 shows the daily supply mix for Great Britain in 2019-20 and 2029-30. It highlights that gas demand will fluctuate more going forward, forcing in turn greater fluctuations in gas supply – note the patterns of import from Norway in light blue. More importantly, gas storage will be refilled and emptied more quickly, with recurrent cycling occurring in the midst of the winter season, from October to February, which is surely not a typical pattern today.

38 Pöyry Energy Consulting, How wind generation could transform gas markets in Great Britain and Ireland, A multi-client Study, Public Summary, June 2010.

39 However, the Irish market shows quicker up and down movements since the power sector accounts for roughly half of overall Irish gas demand.

Figure 28: Evolution of the power sector gas demand in Great Britain and Irish markets

Figure 29: Daily supply mix in 2008/2009 for Great Britain

Dec OctFeb Apr AugJunOct

Dec OctFeb Apr AugJunOct

140

80

100

120

40

60

0

20

Dai

ly g

as d

eman

d (m

cm/d

ay)

Great Britain

20

10

15

0

5

Dai

ly g

as d

eman

d (m

cm/d

ay)

Irish Market

2009-20102029-2030

2009-20102029-2030

Source: Pöyry, “How wind generation could transform gas markets in Great Britain and Ireland”


300

400

500

100

200

-100

0

Dai

ly f

low

(mcm

/day

)

Dec JanNov Feb Mar Apr May Aug SepJun JulOct

storageinterconnectionlngnorwayukcsdemand


Although these results stem from a theoretical modelling exercise, the model has already become reality in one European country: Spain. As explained above, gas-fired power plants account for roughly one quarter of the country’s total installed capacity. Figure 31 shows that daily Spanish gas demand was particularly volatile throughout the whole observed period (May 2010 until April 2011), with days of low gas demand of 10 mcm and spikes of 60 mcm occurring within weeks of each other.

What about Spanish gas supply? Figure 32 below shows that Spain is mainly supplied by LNG, which is much more flexible than pipeline supply – see in particular the bottom of the figure which presents pipeline imports through the interconnection points of Larrau (from France) and Tarifa (Algerian gas transiting Morocco). Thus, LNG plants, not storage, provide the necessary flexibility in Spain.

Figure 30: Daily supply mix in 2019/20 and 2029/30 for Great Britain Figure 31: Daily gas demand in Spain between May 2010 and May 2011

Figure 32: daily gas supply in Spain in 2009

Source: Enagas, figure elaborated by Gas Natural Fenosa

Source: Enagas, figure elaborated by Gas Natural Fenosa,

300

400

500

100

200

-100

0

Dai

ly f

low

(mcm

/day

)


lngnorwayukcsdemand

2019/20

300

400

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100

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0

Dai

ly f

low

(mcm

/day

)


lngnorwayukcsdemand

2029/30

storageinterconnection

storageinterconnection


1-may-1

0

1-jun-1

0

1-jul-1

0

1-aug-10

1-sep-1

0

1-oct-10

1-nov-10

1-dec-1

0

1-feb-1

1

1-mar-1

1

1-jan-1

1

1-apr-11

70

60

50

40

30

20

10

0

Dai

ly g

as d

eman

d (m

cm/d

ay)

1.600

1.800

1.000

1.400

1.200

800

400

200

600

0

GW

h/d

fa

aasssaguntomugardosbilbaocartagena

huelvabarcelonadomestic productiontarifalarrau

01-0

1-09

17-0

1-09

02-0

2-09

18-0

2-09

06-0

3-09

22-0

3-09

07-0

4-09

23-0

4-09

09-0

5-09

25-0

5-09

10-0

6-09

26-0

6-09

12-0

7-09

28-0

7-09

13-0

8-09

29-0

8-09

14-0

9-09

30-0

9-09

16-1

0-09

01-1

1-09

17-1

1-09

03-1

2-09

19-1

2-09

38

Not all EU countries, however, can reasonably be expected to enjoy the same level of flexibility. Thus, the role of LNG and its value compared to storage depends on national circumstances.

So, what is needed to unleash the potential of storage40, but also of LNG and line-pack, as enablers for v-RES? Three main requirements emerge from this brief analysis:

Investment in new storage capacity, particularly salt caverns. If the facility is capable of following wind variability, its business case would become more attractive because revenues would increase driven by the need to respond to market needs in real time. Indeed, operators of depleted hydrocarbon fields could capture business opportunities by making their facilities more flexible and capable of more rapid cycling. To make this happen, governments and regulators need to create a supportive environment. Investment in LNG terminals, above all where the potential for geological storage of natural gas is limited, should not be forgotten.

New market arrangements: third-party access to storage, linepack and LNG should be provided to market participants, including power station operators. Balancing regimes, nomination and re-nomination lead times, and enhanced secondary markets for trading both commodity and capacity represent tools that can make the gas markets more liquid and flexible.

Finally, commercial agreements between suppliers and consumers, including power stations, can be extremely beneficial to RES integration. Agreements linking gas deliveries to actual use, such as that between Statoil and Poweo, demonstrate how the two sides of the market can act jointly to increase flexibility41.

40 For a more in-depth analysis of gas storage as an enabler of v-RES through gas-fired power plants, please refer to Annex III.

41 See the press statement from Statoil following the agreement struck with Poweo: http://www.statoil.com/en/NewsAndMedia/News/2010/Pages/25JunPoweco.aspx (retrieved June 3rd).

conclusions and recommendations6

40 Power Choices Report

This report gives rise to the following conclusions and recommendations for policymakers and the broader community of stakeholders working on the flexibility challenge.

Renewable sources are on the brink of a boom, with the majority of new installations

being solar and wind, i.e. non-dispatchable plants with a maximum firmness of 10-20%.

This increases the need for flexibility and back-up resources in other parts of the

power system. Although several ways of enhancing flexibility exist, flexible power

plants, in particular plants that are already operational, will provide the needed flexible

back-up in the short term, with other flexibility measures (e.g. demand-side participation)

coming into play at a later stage.

Coping with power ramps – i.e. sudden and massive requests of active power (MW) –

will become increasingly relevant. Demand has always been variable and flexibility

requirements have thus always existed. However, power ramps will add a new

dimension on top of the traditionally variable electricity demand, thereby introducing

a step-change in the way the electrical systems are operated.

The v-RES challenge requires a basket of different options/solutions to cope with such

variability. The described national cases demonstrate that flexibility will be achieved

through different resources: conventional generators in Spain, interconnections in

Scandinavia, a mix of both in Germany.


Power plants do not respond equally to power ramps. Different technologies entail

different flexibility capability depending on the technical design. They can be more

or less suited to adjusting their output to follow v-RES generation and ensuring that

lights are kept on, but all of them are necessary in the different timescales (i.e. fastest

technologies to respond in the first instance and the others to follow). This should be

recognised by policymakers, who should also make sure that non-technical considerations

do not prevent the different technologies from coming into play and contributing to

increased flexibility.

�The�suitability�of�a�particular�technology�to�operate�flexibly�and�to�back�up�v-RES�is�

also�influenced�by�the�associated�costs and the capability of the different plant to make

the most of business opportunities. For instance the more responsive the power plant

is to power ramps and price swings, the better the outlook in terms of profitability.

Investments must be urgently directed towards research, development and deployment

(RD&D) programmes that allow equipment manufacturers and operators to improve

power plant design, making units more flexible and responsive.

Liberalised markets imply that different designs would help the power system to

integrate v-RES. EURELECTRIC has already called for changes that would allow energy-

only markets to function properly (e.g. removal of price caps and of regulated end-user

prices). Where such improvements have been made and the necessary flexible and

back-up capacity nevertheless does not develop, EURELECTRIC believes policymakers

should consider the introduction of capacity remuneration mechanisms as an

alternative, ideally at regional level and with the ability to be phased out once the

market can deliver.


Coping with v-RES is not just a matter of flexible power plants and associated costs.

From the environmental viewpoint, part-loading of even the most efficient, least

emitting power stations inevitably results in higher emissions per kilowatt-hour

of electricity produced. This effect should not be forgotten or neglected by

the stakeholders engaged in the flexibility debate, in particular policymakers.

Building power plants is a long-term business, which makes it difficult to plan

for appropriate back-up capacity. As a consequence, the permitting procedures

for erecting and operating power stations should be speeded up and simplified.

The prominent role of hydro in providing flexibility means that unexploited hydro

potential should be developed to support flexibility on both a regional (e.g. around

the Alpine area and Scandinavia) and an EU scale.

Gas markets need to become more flexible so that gas-based generators can act

more flexibly. In particular, this implies the completion of the internal market for gas

(whereby gas moves freely based on price differentials) and the necessary investment

to enhance generators’ flexibility, for instance by building more storage or LNG terminals.

annexes

annex i

the flexibility requirements: a critical overview of existing publications

The issue of flexibility has increasingly attracted interest, resulting in numerous publications over the past five years. This goes in parallel with the rising awareness of the challenges that v-RES will bring to the electricity systems.

Key words in new debates are always revealing. Prominent and repeated terms in the flexibility discussion are feasibility, flexibility of conventional plants, load following, conventional back-up, shift in the merit order, availability, power ramps, interconnections, reliability, fast response, NIMBY, forecasting, new high temperature lines, AC-DC, super grid, cost-benefit analysis (CBA), market design issue such as capacity remuneration mechanisms (CRM), smart “everything”, demand-side participation, as well as flexible electricity.

Variable, non-dispatchable and intermittent RES – while describing the same concept – are nevertheless not used in the same way by all stakeholders – according to some, they help identify whether one backs RES development or not! In this view intermittency qualifies RES negatively and must be replaced by variability. Beyond this type of “religious wars” however, we can objectively witness a major change in electricity vocabulary accompanying the transition towards a more flexible electricity system42.

The flexibility discussion, as reflected in the increasing number of reports, has evolved as follows: first state-of-the-art and overview reports have been followed by more detailed technical, economic or regional studies. And the initial black and white debate – using variability as an argument against the development of RES – has been replaced by a much more differentiated discussion on the basis of a changed generation pattern. Flexibility is considered by some governments and companies in Europe as a huge opportunity – Scandinavia or the Alpine region strive towards a new role of large-scale hydro storage, for example. Others though see it as a threat, a risk to system stability and affordability. The enthusiastic approach to RES in the early days of RES development has triggered scepticism within the conventional sector, which is preoccupied with generation adequacy, flexibility and incentives for change. Interestingly, the traditional utilities nevertheless undertake major investments in the new technologies, especially those that are more capital-intensive such as wind offshore.

Studies on flexibility have been carried out by generators, TSOs, intergovernmental organisations such as the IEA, academia and think tanks, as well as consultants for governments or other stakeholders. The first comprehensive reports describing the flexibility challenge and possible options were prepared as early as 2005, for example by the IEA43 or the European Wind Energy Association (EWEA)44.

Five years on we see a new focus on regional issues. The challenges are very different depending on the RES engagement of European regions. We witness impressive regional studies such as Pöyry’s “Challenges for Nordic Power: how to handle the Renewable Electricity Surplus” (2010) or Frontier Economics’ “Study on flexibility in the Dutch and NW European Power Markets in 2020” (2010). These studies illustrate a new demand from generators as well as TSOs and DSOs, but also academia and politics to understand in depth the technical, strategic, commercial challenges related to variable RES feed-in.

Outside Europe, the North American Electricity Reliability Corporation (NERC) has established a task force, in cooperation with the IEA, to examine the integration of variable generation in the US. EURELECTRIC itself has addressed the issue since the early 2000s and has published a report on “Integrating Intermittent Renewables Sources into the EU electricity system by 2020: challenges and solutions”.


42 EURELECTRIC is currently updating the old UNIPEDE terminology to reflect this change.

43 IEA, Variability of Wind Power and Other RES: management options and strategies, 2005.

44 European Wind Energy Association (EWEA), Large scale integration of wind energy in the European power supply: analysis, issues and recommendations, 2005.

the pioneers: describing the challenge, presenting options (2005)

The IEA’s first report addressing flexibility sets the scene, describes the challenge, and presents elements of answers. The IEA’s new GIVAR (Grid Integration of Variable Renewables) project aims at setting up a methodology for measuring flexibility45. Its 2008 report “Empowering Variable Renewables: options for Flexible Electricity Systems”, goes further in analysing the challenge, linked to “such new generation technologies as wind, wave, tidal, solar and run-of-river hydro”, and formulates the need for a new flexible electricity system. Reliable and fast response to large fluctuations in demand and supply is the main characteristics of the latter. The ageing assets are seen as an opportunity, since overhaul is needed, but a careful cost-benefit analysis is necessary to make the right choice among available options. This point becomes even more important against the current backdrop of shrinking budgets.

EWEA’s study stresses that “the capacity of the European power systems to absorb significant amounts of wind power is determined more by economics and regulatory rules than by technical or practical constraints.” The authors stress the unexpected trip-offs of thermal plants, which pose the challenge of power loss, hence variability. The answer to variability lies in extreme grid development, in other words at the European level. This conclusion is all the more surprising given the RES advocates’ reluctance of a European level playing field when it comes to the harmonisation of support schemes, for example. This, as many other of these early reports, reflects a black and white battle in the early days of RES development in Europe.

2010: the rise of regional studies

The higher the amount of v-RES, the higher the prominence of the flexibility issue in the national or regional community. If less than 10% represents a rather limited challenge, proportions such as the envisaged 30-35% of RES-E in the EU reflect a very different situation.

Regional studies address especially the Northern region, but also Germany, where 26 GW of wind have been brought to the system by 201046. Germany wants to go for 27.9 GW wind onshore and 20.4 GW offshore by 202047. Frontier Economics (2010)48 in a study for EnergieNed underlines that “12 GW of wind can be accommodated in the Dutch system” – and thus reveals one major issue addressed in all regional studies: with how much variability can a system deal in a given time? This question is also raised by CERA in a yet to be published study on the limits to German RES development up to 2020. Pöyry goes so far as to state that interconnections are not a panacea for back-up49, a very different argument from that made especially by the Trade Wind Study 200950 and EWIS (see also the study already quoted by Frontier Economics). Market coupling and power prices move into the focus in Frontiers study: how to get the market to deliver the necessary flexibility?

advocacy for res neglecting the need for conventional back-up

The early studies by RES associations strongly emphasise the role of interconnections, but neglect the need for conventional back-up. Conventional generation is criticised as implying a risk to security of supply (Trade Wind), but not seen as a necessary complement to the large-scale deployment of RES. This unfortunate oversimplification has led to misperceptions in the population, as if RES was possible with no new grids, no new conventional generation, and has triggered problems with public acceptance, among other factors.


45 IEA, Harnessing Variable Renewables, A guide to the Balancing Challenge, 2011.

46 European Wind Integration Study (EWIS), Towards A Successful Integration of Large Scale Wind Power into European Electricity Grid, 2010.

47 Germany Energy Agency (DENA), Dena Grid Study II – Integration of Renewable Energy Sources in the German Power Supply System from 2015-2020 with an outlook to 2025, 2010.

48 Frontier Economics, Study on flexibility in the Dutch and NW European power market in 2020. A report prepared for EnergieNed, April 2010.

49 Pöyry, The challenges of intermittency in North West European power markets, March 2011.

50 TradeWind, Integrating Wind: Developing Europe’s power market for the large-scale integration of wind power, February 2009.

entso-e’s ewis study focusing on network related challenges: grid as the solution

The European Wind Integration Study, realised over 34 months and finalised at the end of 2010, co-financed by the European Commission within the FP6, was carried out on behalf of ENTSO-E. The study argues that grids on a European scale are the answer to the variability challenge, and that thus the technical solutions – like technical compatibility across Europe or voltage control reinforcements – have to be chosen. As already mentioned Pöyry rejects this approach as the panacea. There is also a risk of a parallel power shift to the TSOs along with the shift to the flexible electricity system: if control is the solution, then those in charge of the control are setting the rules of the game. EURELECTRIC strongly disagrees with such an approach. The responsibility for balancing should also lie with those generating non-dispatchable electricity, and thus not only with the TSOs but also with the generators. Indeed, increased cross-border capacity heavily matters, as EWIS states, but is only part of the solution. Studies like DENA on the planning of the grid integration of wind energy in Germany onshore and offshore up to 2020 (DENA Berlin or the DENA Grid Study II) are surprising in their neglect of the European context and their overemphasis of Germany as an isolated system – surrounded by nine neighbours, it is one of the most central countries in the EU electricity system.

flexible power plants

Flexible power plants have been addressed in various studies, some of them technology-specific such as Nicolas Puga’s “The Importance of Combined Cycle Generating Plants in integrating large levels of wind power generation” (2010). Fast ramps and multiple ramping is the question addressed here, and was also the focus of EURELECTRIC and VGB’s enquiry on power plant operation practices when developing the present report. In contrast to the overemphasis on grid development, Puga argues that the successful integration of RES into the system depends on sufficiently fast ramping generation resources. While today’s discussion focuses on comparative advantages of open and combined cycle gas turbine plants, Ludwig, Salnikova and Waas have also examined the load cycling capabilities of German nuclear power plants (2010)51. The discussion on flexible plants has started very recently, with reality already demonstrating the shifts in the use of all plants, including hydro plants, and suppliers are working hard on new products to fulfil the new demand from the market.

linking up technologies: the system approach

Fraunhofers’ report “The integration of wind into the future energy system via load-following” (2009)52 analyses the needed load-following for increased wind-based power generation. Flexibility is presented as a challenge; demand-side participation as a solution; storage as too expensive. The report does not develop the needed market design for incentivising new conventional power plants. But symptomatic of the end of the black and white battle opposing RES-only and conventional-only supporters (which, in any case, barely exist in these ideal types), this report opens the needed discussion for a system approach, for a common perspective on how these technologies interrelate, at which conditions in price, market design, technologies, public acceptance etc. Joskow’s comparison of the costs of variable and dispatchable electricity generation technologies goes in the same direction (2010), calling into question the Levelised Cost of Electricity approach and stressing the fundamental differences between the production profiles.

Market design is certainly the most prominent element of the new setting. EURELECTRIC’s report “RES integration and Market Design: are capacity remuneration mechanisms needed to ensure generation adequacy?” (May 2011) opens this debate and addresses the dilemma between the needed support for flexible power plants and the market distortion effects of capacity remuneration mechanisms.

46

51 Ludwig, Salnikova, Waas, “Load Cycling capabilities of German Nuclear Power Plants”, in International Journal for Nuclear Power, 8/9 2010.

52 Only in German, “Integration von Windenergie in ein zukünftiges Energisystem unterstützt durch Lastmanagement”, Marian Klobasa, Fraunhofer Institute for System- and Innovation-Research; Karlsruhe.

annex ii

cycling operation of nuclear power plants: the neckarwestheim case

Nuclear power is commonly believed to be the technology that scores worst in terms of flexibility and suitability to accompany the penetration of v-RES. However, the suitability of nuclear power plant to perform load-following operations is more linked to the economic attractiveness and the safety requirements rather than to the technology itself. Nuclear flexibility varies depending on the design of the reactors and on the balancing timeframes taken into account. As shown in chapter 3, nuclear power plants (NPP) have (on average) very responsive load gradients (about 5% of load per minute) but very long start-up times from both warm and cold conditions. If a NPP is required to adjust its load while already operational, it could thus be a suitable option to make up for v-RES losses; conversely, it would be practically impossible to use a NPP as a balancing reserve if it is not in an operational mode.

Figure 33 shows the power output of the German Neckarwestheim NPP throughout 2009. The white spot on the right-hand side, lasting about 2-3 weeks in October, represents a planned shutdown of the plant for inspection. It can be seen that the power output never got as low as 40% of the rated power output, whereas it frequently went up to full power for short periods. The steepness of the load changes is particularly striking and cannot simply be explained by the fact that the graph compresses the operation of a whole year in a shorter scale. One can reasonably argue that the steepness was due to a combination of different factors, included the fact that Neckarwestheim is located in a region where NPPs represent the majority of the installed capacity, hence having also to load-cycle.

annex iii

the role of gas storage in enhancing flexibility in the power sector

It is outside of the scope of the present paper to thoroughly explain why, how, where and at which cost natural gas can be stored. Enough literature exists, and we would mainly refer to a paper prepared by Ramboll for the European Commission’s DG Energy (2008)53.

Storing natural gas has been a traditional tool for compensating the swinging demand of gas due to weather conditions. Since many households and commercial businesses in Europe rely on natural gas for heating purposes – representing about 30-40% of overall gas demand –, gas demand is usually at its peak in winter. Seasonal storage implies that gas is steadily withdrawn from storage facilities during the winter and progressively injected into storage during the summer. In this way, gas storage acts as a “seasonal or low-frequency balancing tool”.


Figure 33: Exampleofload-cyclingofanuclearpowerplant– Neckarwestheim 1 (GKN 1)

Source: Ludwig, Salnikova, Waas, “Load Cycling capabilities of German Nuclear Power Plants”

53 Ramboll, Study on natural gas storage in the EU, October 2008. Study for the EU Commission.

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On the other hand, market operators need short-term storage to balance their portfolios of supply and demand, as well as optimise and hedge their commercial positions and strategies. This function is referred to as a “market high-frequency balancing tool”.

Finally, gas storage is an essential tool for mitigating supply risks by providing additional supply in case of a failure in the gas chain (e.g. domestic production fields, pipelines, LNG imports, etc).

Natural gas can be stored in four main different types of facility:

Depleted hydrocarbons fields, which can store very large amounts of natural gas, but which have fairly long injection and withdrawal rates54. They are the most economical to use (despite requiring high volumes of ‘cushion gas’55), and are very well suited for compensating (seasonal) low-frequency demand;

Salt caverns can store considerably less natural gas than depleted fields. However, they enjoy quite a high level of flexibility with very fast withdrawal and injection rates. They are therefore very well suited for high frequency balancing;

Aquifer reservoirs represent a combination of the above two. Bigger than salt caverns but not as big as depleted fields, they show comparable (though slightly quicker) patterns to the latter. However, their high capital costs make them less appealing compared to the others;

LNG peak shaving facilities are the smallest of all types, but have the fastest withdrawal rates56.

The more gas-fired stations cycle, the greater the requirement for storage facilities to follow this pattern. What really matters for the purposes of power generators is the rapidity by which gas can be injected into and withdrawn from the storage site, or the speed of cycling sustained by the facility itself. In contrast, the volume of storage sites is less important. So day-on-day changes in power production – enforced by the v-RES changing output – will be one of the factors determining the need for storage going forward.

In the study mentioned in chapter 5.3, Pöyry has simulated different storage patterns (Figure 34). The storage behaviour described with the orange line is best suited to help gas-fired power generation sustain the variable behaviour of v-RES and enable v-RES integration. In other words, the presence of gas facilities that can withstand very fast cycling will be essential for the power sector.

48

Figure 34: Example of utilisation of gas storage facilities


54 To give some examples, the Rehden facility in Germany can store 4.2 bcm of gas – representing one fifth of the entire storage capacity of Germany alone; Rough, one of the main UK facilities, can be refilled in 180 days and emptied in 70 days.

55 Cushion gas is the volume of gas intended as permanent inventory in the storage facility to maintain adequate operating pressure. Definition in Ramboll (2008).

56 Injection rates are not used to characterise LNG facilities because the gas cannot be re-injected into the LNG facility – it would need to be liquefied again.

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