EDI Quarterly

Contents

1 The role of gas in Smart Grids

3 The role of gas in the Dutch Energy Transition

6 National energy policy in the context of the North- West European market 9 Smart heat and power: utilizing the flexibility of Micro Cogeneration

12 Current design of EU- ETS clashes with its own objectives

17 Shifting Streams

20 Books, reports and upcoming conferences

Q2Volume 2, No. 2, June 2010

Editor’s Noteby Leo Hoenders and René Snijder, Energy Delta Institute

The role of gas in Smart GridsIn January 2008 the European Commission proposed binding legislation to implement the 20-20-20 targets i.e. to reduce CO2 emissions by 20%, to reduce primary energy use by 20% by improving energy efficiency and to increase the share of renewable energy to 20% by 2020. The projected increase in energy demand in the coming decades gives rise to create smart energy systems.

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An increasing part of the primary energy sources, such as gas, coal, wind, solar etc, is being used to generate electricity. The electricity grid requires sizeable investments to be able to cope with the projected increase of electricity generated from renewable energy sources. This has lead to the introduction of the concept of smart grids. Smart grids are hot. Head-lines like ‘the Department of Energy is investing $3.4 billion in Smart Grid technologies’ (22 February 2010) and ‘Global smart grid market to reach $187 billion in 2015 (20 April 2010)’, illustrate the development of smart grids.

What is a smart grid?

This is not an easy question to answer. There is still no consensus on what smart grids actually are. Various definitions are being used to define smart grids:* ‘a smart grid uses digital technology to improve reliability, security and efficiency (both economic and energy) of the electric system from large generation, through the delivery systems to electricity consumers and a growing number of distributed-generation and storage resources’ (DOE/OEDER 2008a(1)). * smart grids: ‘electricity networks that can intelligently integrate the behaviour and actions of all users connected to it – generators, consumers and those that do both – in

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order to efficiently deliver sustainable, economic and secure electricity supplies (the European Technology Platform Smart Grids).

Others argue that smart grids are a comprehensive vision that combines physical assets, operating systems and new engineering design standards with economic, policy and consumer behavioural changes (ADICA). The foucs is more on the capabilities of smart grids like enabling active participation by consumers, reducing efficiency losses, integrating all forms of generation and storage options etc. The difficulty is to create a common vision amongst all stakeholders.

The different definitions and visions illustrates that smart grids have become a catch-all term that encompasses various perspectives of different stakeholders.

What is the role of gas in smart grids?

Currently, we can distinguish five levels where gas is converted into electricity and where the primary energy source gas is in direct competition with the secondary energy source electricity. The first level is the supranational level. On this level, gas is being converted into electricity which is being transported cross-border. Already at this level, choices have to be made because electricity at present cannot be transported economically over distances above approximately 500 km while the primary energy source natural gas can be transported over 5000 km and more. On this level, gas supply competes with other primary energy sources like large offshore wind farms, large solar projects (DeserTec), nuclear and hydropower from Norway.

The second level is the national level. On this level the electricity generated is mainly used for national purposes. The same choices as on supranational level have to be made but here coal fired power plants, onshore wind farms etc are also in competition as primary energy sources with the gas-to-power option.

On the third level there are the industrial areas. These can differ in size but in general gas is being converted locally into electricity and heat. The choices are limited here. Gas has a strong position but is competing against wholesale electricity prices. Surplus electricity and gas can be traded to other customers at this level. On the other hand, the heat generated has to be efficiently used for industrial processes. The combined generated heat and power provides the economic incentives which explains the strong position of gas-to- power option at this level.

The fourth level is the local community. Conversion from gas into heat and electricity at local community level where heat and elec-tricity are distributed through grids. This often limits the choice of individual households and small businesses for direct connection to the gas grid and other possible sources of heat and power. In addition to this, a dedicated electricity and heat grid limits the future possibilities of the integrated approach for innovations in gas applications.

The last level is the household and small businesses. The presence of a gas connection provides future possibilities of introducing economical and efficient gas appliances generating heat and/or power and cooling. An example is the micro combined heat and power, allowing households to become prosumers (connected users can both consume (buy from the grid) and produce (sell back to the grid). Making the right choices to convert gas into

electricity determines the efficiency of the energy delivery to the society.

Smart grids should take the gas option into account in order to become possibly even smarter and more efficient.

Gas competes with electricity on each of the above described levels. The demand for the amount of electricity and/or heat also influences the choice whether to use gas or electricity.

Energy versus economic efficiency

The choice has to be made whether to use gas to generate heat and power, which is best done where the heat can be used most efficiently, or to use electricity generated by wind, solar etc, for both heat and power. On what level the choice to convert gas into electricity is made, can be based solely on energetic grounds. However, on economic grounds a different outcome might result in a different choice. For example electric heat pumps were installed in an area in Zutphen which created an all-electric block at a higher cost compared to the gas/electricity grid combination.

However, the costs for preparing the electricity grid were fivefold as compared to the original combined gas and electricity grid. This example illustrates that the choice has to be made on energetic and economic grounds.

At the moment we are at a cross-road. Within now and five years, huge investment decisions in energy infrastructure will be taken which will determine the future energy mix. Investments in smart grids are incentivized, especially driven by electric vehicles, solar panels, wind turbines etc. The question is how gas will be present in the future energy mix, especially on the lowest level. To make this choice, one should not only base this choice on energetic grounds, but should make an economic evaluation. Eventually this can result into smarter grids but if this choice is solely for the electricity option, this could lead to a suboptimal system for the coming decades. It all boils down to who is setting the course. Is it the government or the market? Who is deciding what is an optimal grid (electric versus combined gas/electric)? The question is how to make this choice…

Figure 1 The levels of competition

The role of natural gas in the Dutch Energy Transition

The issue of climate change and its consequences is increasingly acknowledged on a global level and the idea of moving towards a low-carbon economy is increasingly becoming conventional wisdom. However, the actual implementation of emission reduction measures is a complicated process that is subject to many uncertainties and conflicting political and economic interests.

On a regional level, the European Union embarked on establishing a common energy policy to achieve sustainable, competitive and secure energy supplies in the EU, and meet the commitments made under the Kyoto Protocol. In March 2006, the European Commission issued a Green Paper in which the famous 20-20-20 targets were put forward.

As a Member State, the Netherlands has set an even higher target of 30% CO2 reduction by 20201. This ambition forms the main driver for policies and transition programs such as stimulating the development of wind power and energy saving in the built environment. However, reality provides a less optimistic picture in the sense that it will be extremely difficult, if not infeasible, to realize this 30% reduction without buying tens of millions of CO2 certificates. The share of renewable energy in 2008 was only 3% and CO2 emissions in the industrial and energy sector stabilized at around 100Mton CO2. Together, these sectors account for almost 50% of total emissions 2. Electricity production has been specifically targeted by the Dutch government to reduce CO2 emissions in the coming decade. The development of large scale low-carbon generation capacity will be pivotal to meet these ambitions.

Scenarios for transition to low carbon power generation

In order to gain more insight in the way in which the nature and mag-nitude of the role of gas is affected by the decarbonisation of the Dutch electricity sector, my paper, ‘The role of Natural gas in the Dutch Energy Transition 3’ discusses three scenarios that assume the dominance of a specific low-carbon generation technology. These scenarios are:

Wind scenario: the ambitions of the Dutch government to realize 10GW wind capacity in 2020 (of which 4,5GW is to be realized by 2012) will actually materialize.Nuclear scenario: the political and societal barriers for building new nuclear capacity in the Netherlands are removed. A decision is taken by the new cabinet in 2012 to construct 3-4GW of nuclear capacity that is expected to be operational in 2023.Coal with CCS scenario: coal-fired generation in combination with Carbon Capture and Storage (CCS) will dominate base load by 2025.

The Netherlands becomes front runner in CCS technology in Europe and has the ambition to become the “CO2 roundabout” of Northwest Europe as an extension of the gas roundabout concept (discussed above). As a result, 4-5GW of coal-fired capacity is built before 2025.Although all three scenarios are possible, reality will probably be more

nuanced. Following the almost sacred principle of fuel diversification in the energy sector, a balanced mix of generation technologies is most likely. Nuclear power has the lowest probability of expanding its share in the generation mix due to the political and public controversies which it raises. However, an increasing sense of urgency about climate change, could alter this outlook. In any case, the government and energy companies must be aware of the conflicts and possible lock-in effects in especially base load generation capacity development. This also includes the latent lock-in effect of pre-construction phases of large scale capacity. The combination of large scale wind and nuclear or coal with CCS capacity will have detrimental effects on the value of one of those investments. The coming years will be pivotal for the transitional design of the Dutch generation mix and a ‘keeping options open’ approach will not help to establish this. Although base load technologies can co-exist to a certain extent, the conflicts between the different options, which also depend on the development of export opportunities, require decision makers in the sector to commit to significant investments in a specific technology.

Role of gas

Looking at the role of gas in energy transition, a decision in favour of any alternative large scale base load generation technology will not reduce its current strong position in power generation. Although this conclusion is not earth shattering given the current strong footprint of gas in the Dutch energy system, all stakeholders must be aware that gas will stick around for many years to come. In fact, one of the main conclusions of my paper is that regardless of this decision, gas will probably become even more important as a transition fuel towards 2020.

First of all, gas will consolidate its function as the fuel for gene-ration during peak hours because of the absence of alternative generation technologies that can be regulated in a similar way on a large scale. In absolute terms, more electricity will be produced by gas-fired units because of the expected increase of peak demand.

Secondly, following the assumption that the majority of conventional coal projects will be cancelled in the coming years, gas is probably the most technologically and commercially viable option for replacing a part of base load generation capacity. This means that the share of gas in power generation further increases, at least for an intermediate period until a cleaner alternative is available. Looking at the nuclear and coal with CCS scenarios, this alternative will not be there before 2020. Consequently, additional gas-fired capacity will be built between 2010-20 which, assuming that investments will have to be earned back, will create a lock-in of gas beyond 2025.

Thirdly, there is the role of gas-fired generation as regulating instrument to safeguard grid stability. Pursuing the wind scenario will put an additional call on gas-fired generation as the only indigenous flexibility provider to balance the intermittency of wind. If the ambition of 10 GW of wind capacity will be achieved, approximately an additional 1 GW of flexible generation capacity is

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Floris van ForeestResearch fellow

Oxford Institute for Energy Studies

Figure 1 The levels of competition

accommodated by the additional gas-fired capacity. However, this roadmap will have serious financial consequences for the government budget. If in the coming 2-3 years the government fails to implement a regulatory and financial framework which will allow the realization of the 6GW offshore wind and new coal-fired plants will be built, the 2020 targets will not be met. Longer term, beyond 2020, to realize large scale decarbonisation of base load power generation, large investments are also required in either coal with CCS or nuclear energy. Capital expenditures have to be balanced against estimates of production costs and revenues. These are based on assumptions about efficiency levels, capacity factors and fossil fuel and CO2 prices. Furthermore, government support will partly determine the investment climate. These investments should also be perceived in the light of the discussed conflicts in base load generation. Both generation types and wind can only co-exist to a certain extent to remain economically attractive. Between coal with CCS and nuclear, the former is the currently preferred option of policy makers in the Netherlands, but the latter should not be ruled out. I would suggest that the government should seriously investigate the nuclear option and prevent latent lock-in effects in case coal with CCS proves not to be a commercially viable option in the longer term.

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required to accommodate the integration of wind energy. This role will be less significant in the nuclear or coal with CCS scenarios, but additional balancing capacity will also be required in case 5GW wind capacity is installed.

Finally, the expected increase of CHP units in the industrial sector to improve energy efficiency further enhances the gas footprint in energy transition.

The conclusion of the paper on the role of gas could also be ap-plicable to other countries with a strong gas profile such as the UK or Italy, but also to less gas-dominated markets such as Germany. On the other hand, it is not self-evidently applicable for countries where gas currently plays a minor role.

Meeting the 2020 targets

In my opinion, the only way to meet the 2020 targets is to replace decommissioned coal plants by gas-fired units, which also run partly base load, and build large scale offshore wind parks. Gas is a relatively clean and efficient energy source for power generation. Given the fact that a CCGT plant emits 50% less CO2 than a coal-fired plant and runs at higher efficiency levels, investment in the former faces much less opposition. The wind intermittency can be

Table 1.1: Installed capacity per scenario¹The majority (~ 90%) of decentralized capacity is gas-fired ²Mainly Biomass and some solar PV ³The higher total capacity in the wind scenario despite the shorter timeframe is a bit distorting in the sense that the 10 GW wind capacity produces less than coal with CCS and nuclear plants due to lower load factors. They range between 20% (onshore) and 40% (offshore)

Wind scenario (2020)

Nuclear scenario (2025)

Coal with CCS scenario (2025)

Demand 133-143 TWh 140-154 TWh 140-154 TWh

Peak load (MW) 24 GW 26 GW 26 GW Installed Capacity (MW)

Gas (CCGT) 9-11 GW 7-9 GW 7-9 GW Coal 4 GW (no CCS) 3 GW (incl. CCS) 6-7 GW (incl. CCS) Nuclear 0.5 GW 4 GW 0.5 GW Decentralized¹ 10-12 GW 10-12 GW 10-12 GW

10 GW 5 GW 5 GW Wind Other² 1 GW 1-2 GW 1-2 GW Total³ 34.5-38.5 GW 30-35 GW 29.5-35.5 GW General assumptions

CO2 reduction In all three scenarios the objective is 30% reduction Carbon Capture

and Storage The application of this technology is focused on coal-fired plants as coal has the highest relative net carbon emissions to electricity production

Energy efficiency

The economic recession has caused a significant reduction, but electricity demand will return to the pre-crisis growth level of 1-1.5% per annum. Gas demand of households and office buildings will decrease due to energy saving measures and non-fossil heat generation

Import Interconnection will improve, but import level of electricity will remain between 15-20% of total demand

Clean electricity Wind is the dominant renewable energy source and large scale commercial application of Coal with CCS is feasible after 2020

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Implications for the industry

To meet the 2020 targets, large investments in power generation capacity have to be made by energy companies in the coming years. Investment decisions will be taken in an environment that is highly influenced by a mix of political and economic interests. Changing policies and regulatory frameworks do not contribute to a stable investment climate. Political decision making regarding reductions of CO2 emissions can create new investment opportunities, as new support mechanisms are introduced, or a stricter CO2 certificate regime results in structurally higher CO2 prices. Furthermore, geopolitical conflicts in oil and gas rich regions can influence the oil price, and indirectly the gas price, due to their linkage. On the other hand, general economic and financial conditions also influence the economic viability of generation technologies. Economic growth or decline results in shifting demand and supply curves and subsequently affects fossil fuel and electricity prices. In addition, investment in new technologies is often financed by investment companies and banks, which therefore can influence the pace of development.

The current economic downturn underwrites the influence of market factors on the electricity sector. A lack of finance capacity and appetite among investors can cause delays or even cancel-lations of large renewable projects such as offshore wind farms.

Going forward, investment in gas-fired power generation and (off-shore) wind, if supported by subsidies, seems the most logical approach on at least the medium term in the light of the transi-tion to low carbon power generation. However, political support

for new nuclear capacity in the Netherlands, a structural higher CO2 price and shifting fuel prices, can alter this picture in favour of other, capital intensive, technologies such as nuclear and coal with CCS. Given all the uncertainties, a more reserved investment strategy, in anticipation of more clarity on the third phase ETS and firmness of the CO2 reduction targets, could be the way forward in the coming 2-3 years.

Dutch gas policy

The envisaged strong position of gas in energy transition requires the Dutch government to evaluate a longer term gas policy. An outlook which gives an increasingly important role to gas in power generation in the transition phase, in combination with depleting national reserves, puts current production and export policy in a different perspective. Although increasing power sector demand will be partly offset by a decrease in household and commercial demand, the importance of an energy transition which includes CO2 reduction and energy security probably requires a different allocation of national gas resources. In other words, if gas is considered as an important transition fuel and the Netherlands does not want to depend too much on imports after 2020, production and exports will have to be curtailed to decrease the depletion rate of indigenous resources.

Driver Investment cost

Lifetime Production cost 2007

Production cost 2020

Net Efficiency

Emission (Lifecycle)

Metric €2005/kW Year €2005/MWh €2005/MWh kg CO2 (eq)/MWh

Technology

WindOnshore 1000-1370 20 75-110 55-90 n/a 11Offshore 1750-2750 20 85-140 65-115 n/a 14Combined Cycle Gas Turbine 480-730 25 50-60 65-75 58% 420Combined Cycle Gas Turbine CCS 1000-1300 25 n/a 85-95 49% 145Pulverised Coal Combustion 1000-1440 40 40-50 65-80 47% 820Coal CCSPulverised Coal Combustion 1700-2700 40 n/a 80-105 35%¹ 270Integrated Gasification Combined Cycle 1700-2400 40 n/a 75-90 35% 270Nuclear 1970-3380 40 50-85 45-80 35% 15¹ Reported efficiencies for carbon capture plans refer to first-of-a-kind demonstration installations that start operating in 2015

Footnotes

3 Ministry of Environmental Affairs, Government Program Clean and Efficient: New Energy for the Climate, September 20074 Energy Research Centre of the Netherlands (ECN), Monitor Clean and Efficient Program, April 2009, p. 175 Van Foreest, F., ‘The Role of Natural Gas in the Dutch Energy Transition: Towards low-carbon electricity supply’, Oxford Institute for Energy Studies, January 2010 6 European Commission(2008), Second Strategic Energy Review, Energy Technologies for Power Generation – Moderate Fuel Price Scenario, p.4. State of the art technology in cost price calculation.

Table 1.2 Parameters of main generation technologies 4

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National energy policy in the context of the Northwest European market1

Bram BuijsClingendael International

Energy Programme

Faced with the consequences of an unbundled and regionalizing market, combined with a growing number of targets and policy measures that are being determined in the EU domain, national governments increasingly struggle to formulate a meaningful and effective national energy policy. A recent study by the Clingendael International Energy Programme focuses on these challenges and pays attention in particular to the international dimension and issues related to the fuel mix and infrastructure.

An emerging Northwest European power market The regional integration of power markets in Northwest Europe is progressing in a gradual fashion, as cross-border interconnection capacity is being expanded. Just as historically provincial grids merged together into national electricity grids, increased grid integration is taking place at a supranational level at many different countries within Europe. Frontrunner in this trend has been the Scandinavian power market, where the first full market coupling took place with the creation of the Nordic Power Exchange (or Nord Pool) between Denmark, Norway, Sweden and Finland, which has been in operation now for several years. Moving in this direction, Germany, France and the Benelux have joined in the “Pentalateral Forum” with the aim of increasing cross-border connectivity and making smarter use of the existing interconnections. A next step, scheduled for September this

year, will be the addition of Luxembourg and Germany to the “Tri-Lateral Market Coupling (TLC)” already in existence between the Dutch, Belgian and French power markets to establish an integrated Central Western European (CWE) electricity market.

For the Netherlands, interconnection capacity is growing not only through overland connections but also by subsea cables with Norway (via NorNed, completed in 2008), the United Kingdom (via BritNed, construction started in 2009 and expected to be ready in 2011) and Denmark (via COBRA, still in planning phase). Even though the utili-zation and management of the interconnection capacity in Europe still leaves much room for improvement, the market coupling resulting from these increasing linkages and the cooperation within the Pentalateral Forum is expected to lead to a gradual convergence or ‘harmonization’ of electricity prices. Figure 1 shows a potential future sequence of European power market integration which was presented as part of discussions at the 17th EU Electricity Regulatory (Florence) Forum meeting of December 2009.

A second important trend taking place is the consolidation among European energy companies and the emergence of pan-European utili-ties. As a consequence of the unbundling process and market liberali-zation that have been put forward in the EU context, energy companies have increased their operations across borders. Major mergers and acquisitions have taken place, such as the merger between GDF and

Figure 1. Potential sequence of European market coupling. Source: PCG Report to the XVIIth Florence Forum, 10&11 December 2009, Rome. Available online at: http://ec.europa.eu/energy/gas_electricity/forum_electricity_florence_en.htm.

Jacques de JongClingendael International

Energy Programme

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Suez, the take-over of Endesa by Enel and Acciona, and the acquisition of power generation assets of Enel and Endesa by E.ON. Regarding the situation in the Netherlands, the takeover of Nuon by Vattenfall and Es-sent by RWE are cases in point. Given that many of the large firms hold a wide range of assets in the whole European market, they base their investment decisions not only on national energy market conditions or national energy policies, but weigh in considerations on their overall power plant portfolio and aim to spread risks related to capital invest-ment and fluctuations of fuel and carbon prices2.

Changing supply and demand patterns and the role of infrastructure

The impediments to a transformation towards a single European internal electricity market are manifold, but particularly challenging are the demands put onto infrastructure – both in terms of creating sufficient regional interconnection capacity, as well as accommodating more dynamic supply and demand patterns. There are several trends which can be identified. First of all, on the supply side, there is the increasing use of intermittent renewable energy sources. Of course this holds especially for the growth of wind energy, which already occupies a significant share of the energy mix in several EU member states and which ranked first in terms of the volume of newly installed capacity in the EU as a whole in 2008 and 2009. A second development is the (expected) growth of decentralized power generation. Integrating the supply of electricity by a large number of small-scale and dispersed sources requires the grid to be able to handle multi-directional flows and more complex balancing conditions.

On the demand side, it is expected that a trend towards electrification in various sectors will lead to a continued growth in electricity demand: for instance by a wider deployment of electric heat pumps and plug-in (hybrid) electric vehicles. The introduction of smart metering in combination with smart grids will be important to promote demand-side responsiveness: itself another key element in order to manage the increasingly volatile and complex dynamics of electricity supply and demand. However, for the deployment of smart metering and smart grids large investments are needed.

It is broadly recognized that increased regional interconnection can serve to balance out fluctuations in supply and to allow for a more optimal deployment of renewable energy sources across Europe. More generally, the coupling of electricity markets can permit a more efficient use of power generation assets. Experience proves that increased regional integration will be essential to accommodate the increased de-mand for flexibility in power generation, energy storage and balancing options that comes with a large-scale deployment of renewable energy sources. This is illustrated by the example of Denmark: the growth of wind power in Denmark would not have been possible without the op-portunity to import and export electricity through strong interconnections with Norway, Sweden and Germany. In this case, the pumped storage and hydropower capacity in Scandinavia serves as a very effective means of providing a secure electricity supply complementary to the variable wind energy production. In future, there will be a larger role for balancing base-load electricity generation, intermittent renewable energy sources and flexible (gas-fired) power plants at a regional level.

The trends indicated above yield new requirements on infrastructure, both in terms of investment and management, and they put into ques-

tion the adequacy of current practices. Discussions have been going on as to whether current regulatory regimes and efficiency improvement obligations for system operators are sufficient to ensure the grid is future-proof 3. There are also doubts whether sufficient large scale investment in cross-border interconnection capacity will materialize under current circumstances.

Another aspect to consider is that the new requirements for infrastructure mean that the cost balance between investments in production and infrastructure (both transmission and distribution) is shifting. Instead of being significantly smaller in terms of expenditure, it is projected that infrastructure investments in coming decades will become as important as investments in power generation capacity. This calls into question whether the subordinated role of infrastructure development with regard to power generation capacity should be maintained: should infrastructure continue to follow production without any conditions attached? There are good reasons to consider how a more coordinated approach can be developed, without interfering with market principles.

Implications for national energy policy making

A consequence of European market liberalization is that national gover-nments are left with rather limited means to influence domestic energy markets. The most important instruments available are in the field of permitting procedures, regulation on environmental matters, subsidies and taxes. Scope for domestic policy is further limited since a major part of greenhouse gas emissions is currently regulated through the EU Emission Trading Scheme (EU ETS), of which the cap and allocation method of emission rights will become a strictly European prerogative from 2013 onwards.

The increasing regionalization also carries a series of consequences for policy making at the national level. First of all, due to increasing share of cross-border electricity flows, technical security of supply in terms of grid stability is increasingly a supranational question: in the case that a grid failure occurs in Northwest Germany, the impact on the Netherlands will likely be bigger than on Bavaria. The prospect of increasing interdependency points out the need for more cooperation and coordination at a regional level and makes it distinctly less sensible to only consider policies aimed at the national situation.

In fact, it can be argued that increased market integration makes it more difficult for European governments to follow their own nationally-specific policy that will impact locational advantages, such as the implementation of mandatory CCS requirements or emissions performance standards. Such nationally diverse measures do not seem desirable given the regional or even global objectives that these policy measures are intended to serve and given the fact that they might very well be detrimental to the overall effectiveness of the policy. This point has been raised often with respect to the optimal deployment of renewable energy sources and cost-effective lowering of greenhouse gas emissions within Europe. Again taking the Netherlands as an example, the unilateral implementation of very strict requirements on coal-fired power plants might lead to the decreased use or closure of such plants in the Netherlands, even though their plant efficiency might be greater than German coal plants located across the border.

In many European Member States discussions on the fuel mix still take place as if it were a solely a national affair: the fierce debates over

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the expansion, extension or decommissioning of nuclear power plants being a key example. Yet, in particular for policies related to the fuel mix, it would make good sense to look at the regional context. Many of the concerns as well as the benefits, such as addressing climate change or increasing energy security, transcend the national interest. Moreover, it is recognized that trading and market coupling at a regional level will be necessary in order to achieve a minimization of costs related to the promotion of renewable energy sources.

Figure 2. The fuel mix in Northwest Europe (2006). Source: DG TREN, EU Energy and Transport in Figures (gross electricity production), 2009.

When considering fuel mix issues in a regional context, it is worthwhile to notice that the Northwest European market as a whole has a rather balanced fuel mix, even though national markets have their strong peculiarities. If we look at the overall fuel mix of Northwest Europe, as illustrated by Figure 2 we see that the largest share of generated electricity comes from nuclear power (38%): of course due to France in particular, but also because of large shares in Sweden, Belgium and Germany. It is followed by coal (26%), which plays an important role in the UK, Germany and Denmark, and gas (16%). In terms of renewable energy sources there is a large share of hydro (13%); non-hydro renewable energy sources (such as wind and biomass) only occupy a share of 5%. Utilizing existing complementarities, insofar as possible, will need to play a larger role in future.

Conclusions

A discrepancy is growing between the effectiveness of national energy policy instruments and the evolving regional power markets in North-

western Europe. On the one hand there are national targets, such as those related to the fuel mix and the share of renewable energy sources, as well as policy instruments such as subsidy schemes, fiscal measures and permitting procedures which can be utilized at a national level. On the other hand, much of the issues at stake cannot be dealt with in a meaningful way at only a national level. Grid stability, the develop-ment and accommodation of renewable energy sources are becoming supranational issues. Operations of European utilities extend across borders and an increasing share of policy and regulation is being made at a European level. It can be concluded that we are in a twilight zone in which the development of the fuel mix is still a part of national policy despite a growing impact of international factors.

Consequently, the observations made here call for a more supranational approach and greater regional coordination, for instance through bodies such as the Pentalateral Forum.

Second, it can be argued that there are reasons for governments to consider playing a stronger role in guiding investments and utilization concerning infrastructure. As infrastructure becomes more critical in terms of costs and deployment, it may become a stronger instrument for the government to influence developments within the power market. This holds for facilitating the expansion of cross-border inter-connection capacity and the introduction of smart meters and smart grids. Another example is government involvement in the arrangements necessary for linking offshore wind farms to the grid. In order to avoid costly investments that might turn out to be unnecessary in the longer run, a closer cooperation on infrastructure development between government, market players and transmission system operators is warranted. To this end, it will be important for policy makers to attempt to sketch as clearly as possible a vision on the future of the energy landscape, however difficult that may be. At a European level attempts to improve coordination are also being made, for instance by requiring the European Network for Transmission System Operators for Electricity (ENTSO-E) to publish a Ten-Year Network Development Plan that provides an outlook on European infrastructure development. National energy policy is embedded in a changing regional context: the more that this will be taken into account, the better chances are that policy can be set out that will be effective and sustainable in the long run.

Footnotes

1 This article is based upon the Clingendael Energy Paper “Energy Policy and the Northwest European Market. Fuel Mix and Infrastructure” Available online in both Dutch and English at: http://www.clingendael.nl/ciep/publications/energy-papers/?id=7826&&type=summary2 Clingendael Energy Paper, “Energy Company Strategies in the Dynamic EU Energy Market (1995-2007)”, 2010. Available online at: http://www.clingendael.nl/publications/2010/20100608_CIEP_Energy_Paper_Energy_Company_Strategies.pdf3 Algemene Energieraad (AER), “De Ruggengraat van de Energievoorziening”, September 2009.

References

Clingendael Energy Paper, “Energy Policy and the Northwest European Market”, 2010. Available online (English version) at: http://www.clingendael.nl/publications/2010/201005_CIEP_Energypaper_JJong_PBoot_BBuijs.pdfClingendael Energy Paper, “Energy Company Strategies in the Dynamic EU Energy Market (1995-2007)”, 2010. Available online at: http://www.clingendael.nl/publications/2010/20100608_CIEP_Energy_Paper_Energy_Company_Strategies.pdf

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Power generation is responsible for a large share of anthropogenic CO2emissions. Renewable energy sources and energy efficiency are therefore promoted worldwide. In a sustainable energy system, distributed electricity generation (DG) will play a prominent role. This thesis focuses on domestic energy use and on a new type of residential DG technology. Specific potential for applying DG in households lies in utilizing heat and electricity from micro combined heat and power systems (micro-CHP). Micro-CHPs simultaneously generate heat and power and contribute to energy efficiency and CO2 emission reductions. Micro-CHP systems are on the verge of becoming mass marketed as next generation domestic heating systems in countries with an extensive natural gas infrastructure, such as the Netherlands, the UK, Germany, Italy, Japan and parts of the United States and Canada. For these countries micro-CHP is considered an element in the transition towards a fully renewable energy system. The likely trajectory of the implementation of micro-CHP starts with Stirling engine and internal combustion engine systems, followed by systems based on fuel cell technology.

This thesis explores the potential cost savings from intelligent control schemes with micro-CHP systems. Micro-CHP is a special DG technology in the sense that its power output can be controlled (as

Smart heat and power: Utilizing the flexibility of Micro Cogeneration

Michiel HouwingStrategic consultant

Eneco Energie

opposed to stochastic generation such as wind power). To ensure smooth operation, micro-CHP systems will probably be operated in conjuntion with heat storage systems. To fully utilize the controllability of micro-CHP and the additional flexibility provided by heat storage, intelligent control of micro-CHP systems is needed. Intelligent control relies on the use of advanced information and communication infra-structure and smart metering. These enable previously passive domestic consumers to become active participants in the electricity market and in the operation of the electricity system.

The main problem with micro-CHP systems is that in comparison with conventional gas-fired boilers the investment costs are still prohibitive. Besides variable energy cost savings and governmental policies that reward the positive externalities of micro-CHP application,intelligent control may also decrease variable costs and enhance the economic attractiveness of micro-CHP for investors. Potential investors are households, housing corporations, energy retail companies and other energy service companies. The research question this thesisanswers is: How and to what extent can intelligent control of micro-CHP systems increase their economic feasibility?

Economic feasibility is here defined as the difference betweenthe cost savings with micro-CHP application obtained during an acceptable payback period of 10 years, and the additional investment

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costs of micro-CHP compared to gas-fired boiler.

Simulation results and main conclusions

In answering the research question, different control schemes were designed. These schemes are shown in the figure above. The system contains (clusters of) households that interact with their energy retailer. Conventional households obtain all their electricity from thegrid and fulfill their heat demand with a high-efficiency, gas-fired boiler. Two micro-CHP technologies were researched: Stirling engines and proton exchange membrane fuel cells (PEMFC). Stirling systems are currently market ready and PEMFC systems are still mostly in the R&D stage. The main difference between these two technologies is their heat-to-power ratio, which is much lower for PEMFC systems.

The main conclusions from simulations with models of the control schemes are the following:

Micro-CHP is currently economically infeasible, but future systems look attractive. In the ‘fit & forget’ scheme, households buy gas and electricity from their energy retail company and sell electricity back to that retailer. This scheme serves as a base case with which the economic feasibility of more intelligent control schemes is compared. Heat-ledcontrol was found to be the best standard control strategy for micro-CHP systems. Micro-CHP systems provide substantial energy cost savings compared to high-efficiency gas boilers. Less electricity is imported and a little more gas is used, resulting in an overall reduction in primary energy use of about 20%. In a market where transport costs are billed per kWh of electricity sold, a feed-back tariff equal to the import price minus the transport tariff is logical. With such a feed-back tariff, annual energy cost savings are around €250 for Stirling engines and around €500 for PEMFCs (both values for households with avera-ge heat and electricity demand). Considering the payback period of

10 years for the investment, these savings result in room for additional investment of about €2000 for Stirling engines and €4500 for PEMFCs. For Stirlings this is not enough as they are currently about €4000 more expensive than conventional boilers (see figure above). The PEMFC systems seemmore economically attractive. This depends strongly on their eventual investment costs, however, which, after consulting the available price data, are very uncertain. The results do look promising for future generations of micro-CHPs, which are likely to be based on fuel cell technology.

Demand response moderately increases the room for investment in micro-CHP. Micro-CHP systems can be applied more intelligently than in the ‘fit & forget’scheme, without compromising the heating comfort for households. In the ‘rate & react’ scheme the retail company rates the electricity sold to and bought from households and intelligent controllers in households react to the tariffs when dispatching micro-CHP units. In that way the net-consumption of electricity responds to real-time prices.

Demand response was implemented in a model predictive control (MPC) strategy. MPC is a control strategy that incorporates future knowledge in control actions. With MPC applied to Stirling systems, the room for investment was increased with €30 to €300, whichis still not enough to justify investment in Stirling technology. Cost savings with MPC strongly depend on the specific electricity pricing regime and are highest with the most heavily fluctuating real-time pricing scheme. With PEMFC systems, additional variable energy cost savings with MPC are much larger, resulting in an increased room for investment of up to €700. Depending on the eventual cost price of PEMFC systems, applying demand response to this technology can make it economically feasible. Before contributing to improvements in economic feasibility of micro-CHP, cost savings with intelligence should cover investments in control systems and in-house domotics.

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Especially when smart metering and options for data communication with households are already in place (which is plausible in the future), these investments will not be too high. Especially with PEMFCs, it is likely that the increased room for investment from demand response covers the investments in control systems and information and com-munication technology (ICT).

Intelligent control of Stirling micro-CHP does not make them economically feasible. As a next step, the potential of virtual power plants (VPP) to enhance the economic feasibility of micro-CHP was analyzed. Placing intelligence at a higher system level and employing it to control clusters of households can provide economies of scale in the use of control and ICT: with intelligence at the aggregate level, simpler sensing and actuation devices can be used in households. Also, the energy demand of clusters of households can be predicted more accura-tely than the demand of individual households. In the ‘cluster &control’ scheme, micro-CHP systems are controlled in a VPP arrange-ment by an aggregator. An aggregator is defined here as an actor that trades with the aggregate power owes to/from households (i.e. retailer) and/or operates a VPP by controlling micro-CHPs (i.e. VPP operator). The aggregator can also invest in micro-CHPs and/or ICT systems.

Two VPP applications were analyzed. First, aggregate demand response schemes provided savings per household that are similar to the savings with domestic-level demand response. A second application was mode-led in which a VPP provided balancing services to a wind farm. Wind power traders are inherently faced with imbalances due to the stochas-tic nature of wind power generation. VPPs with micro-CHP units can help traders to mitigate unwanted imbalance costs. Model simulations with a VPP of 200,000 1 kW Stirling systems reduced the imbalance volume of a 200 MW wind farm with 33 % and the associatedcosts with 20 %. An annual saving of about €1 million was achieved. Assuming that these savings are evenly divided between the VPP households, an annual saving of about €5 per household is arrived at. Such small savings will not improve the economic feasibility ofindividual Stirling micro-CHPs. So, looking at the results for Stirling engines in the ‘rate & react’ and ‘cluster & control’ schemes, it is conclu-ded that intelligent control of Stirling micro-CHP does not make them economically feasible.

If investments are made based on ‘fit & forget’ application, aggregators have an economic incentive to set up VPPs aimed at demand response.If Stirling micro-CHPs become cheaper in the future or if the technology receives government support, these systems can become economically feasible under ‘fit & forget’ application and large numbers can penetrate the market. As previously discussed, PEMFCs can also become economically feasible under ‘fit & forget’ application.When households or aggregators already deem the investment in micro-CHP – when they operate in the standard ‘fit & forget’ way – economically feasible, the additional savings with demand response provide an incentive for aggregators to initiate VPPs. Net savings of about C50 per household per year provide an aggregate economic incentive to set up a VPP, because the total savings from all households together are considerable. The value of micro-CHP’s inherent exibility therefore lies in the clustered, intelligent application of this technology.

Consequences for the gas industry Micro-CHP is not the cleanest technique to generate heat (heat pumps are cleaner and, with air as heat source, can be applied everywhere). This should be acknowledged by the gas industry. However it is

difficult to say which technique will be the most expensive solution from an investment perspective.

Still micro-CHP is a chance for the boiler industry since it is a lot clea-ner as compared to the high efficiency boiler. It makes sense for them to adopt the micro-CHP, to run field tests to reduce the costs as soon as possible and to improve the technique and market the Micro-CHP.

Micro-CHP can be part of two types of VPPs:1. A cluster of Micro-CHPs is invested in by an aggregator and households pay regular fees to the aggregator in order to recover the investment. 2. Micro-CHPs, which have been invested in by households themselves, are intelligently controlled as a cluster.

Both types of VPPs can also be combined. Option 1 would increase the economic attractiveness of the Micro-CHP for households because they do not have to make a large investment. Option 2 only makes sense by using PEMFCs - with Stirling systems savings from intelligent control are very small.

Intelligent control of distributed energy resources is promising for the future. Electric vehicles are envisaged as the launching technology for such intelligent control, but Micro-CHPs can also get a well deserved place in intelligent control schemes for commercial purposes.

12

Current design of EU ETS clashes with its own objectives

A.J. Mulder1

Summary

A model has been developed to forecast the price of carbon allowances under the EU ETS (Emission Trading Scheme). The model was developed under the auspices of TNO as part of the European ECCO3 project. The model sheds light on some important obstacles to success for the EU ETS. While significant and prolonged oversupply of allowances is glooming under the current design, the systemic instability of the EUA4 price is likely to stand in the way of the development of large scale abatement projects such as CCS (Carbon Capture and Storage). Furthermore, other measures directed at sectors under the EU ETS, e.g. regulation mandating the installations of CCS on coal fired power plants, primarily work as a substitute to the EU ETS instead of complementing it. While the cumulative level of abatement is not expected to increase, regulation does increase the overall societal costs of European climate policy.

The promise of the EU ETS: abatement at minimal costs

Ever since the EU Emissions Trading Scheme (EU ETS) came into effect on January 1st 2005, it has been surrounded by uncertainty. Although the scheme could potentially become a powerful weapon in the effort to reduce European carbon emissions, doubts with respect to the scheme’s effectiveness and practical feasibility have remained. In theory, ‘the ETS should allow the European Union to achieve its emis-sion reduction target under the Kyoto Protocol at a cost of below 0.1% of GDP, significantly less than would otherwise be the case’(EC, 2008). In practice, however, the efficiency and effectiveness of the ETS still remain questionable.

If given enough time, political alignment and decisiveness, the EU can possibly have a fully functioning emissions trading scheme, covering all

major polluting sectors and leading to a substantial cutback in carbon emissions. However, time is limited, as the EU is committed to cutting carbon emissions by 20% by 2020 compared to 1990 levels as specified in the Climate-Energy Package. Secondly, the EU has stressed the importance of CCS5 as a bridging technology in order to achieve the EU’s long term emission reduction goals beyond 2020. Therefore the EU aims to make CCS an economically viable abatement technology by 2020. Generally, the EU ETS, which is seen as the flagship of European carbon policy, is expected to provide a strong and stable price incentive to the industry. But whether the EU ETS will result in an EUA price that will support the timely commercial roll-out of CCS is being questioned. Now, five years after its introduction, it is time for the EU ETS to show that it will be capable of delivering on its promises.

Market model: establishing the scarcity of emission rights

To assess the effectiveness of the EU-ETS a market model has been constructed with the main goal of forecasting the fundamental EUA price for the mid- and long-term. Before moving on, it is important to outline what is meant by the ‘fundamental EUA price’.

Fundamentally, there is no price tag on carbon dioxide as long as allowances are in abundant supply. Firms are only willing to pay for allowances if they have a short position and are faced with a non-compliance penalty. The maximum price an individual firm is willing to pay for an allowance is equal to the cost of the cheapest abatement opportunity available to that firm. On economic princi-ple, if the market is short, the firm with the lowest cost abatement opportunity will abate carbon emissions first. As the price increa-ses, more firms will choose to abate CO2 and this process continues until demand and supply are back in equilibrium. As a result, the fundamental allowance price equals the costs of the last tonne of

C.F.M Bos2

Fig 1: BAU Scenario - Scarcity of allowances (negative values imply scarcity)

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CO2 abated. In this analysis, the expansion of the EU ETS across more sectors is left out of the analysis. Also, market mechanisms such as arbitrage and speculation are not taken into account while calculating the fundamental EUA price. As a result, future expecta-tions are not accounted for in the price. Instead, the fundamental EUA price is a reflection of the price of the available abatement potential, given the need for abatement in that year.

The level of the allowance price is dependent on both the controllable political and institutional environment (which determines the supply of allowances) as well as the uncontrol-lable worldwide economy (i.e. uncontrollable from a European policy maker’s perspective), which determines allowance demand. Whereas the supply of allowances is rather predictable, the demand for allowances is naturally much more volatile. Since banking ofallowances was introduced at the start of Phase II in 2008, volatility of demand has become even more important. An example is the recent economic downturn, which has resulted in a potential carbon bubble as allowances can be banked and stored for later use.

Allowance demand volatility: an underestimated problem

While many papers have been written on the volatility and fundamentals of the allowance price, the volatility of allowance demand and supply seems to be getting much less attention than it should. In the end, scarcity of allowances is the most direct and elementary fundamental of the EUA price and should therefore be the starting point for any analysis of the allowance price. Once the required level of abatement is known, one can in principle predict the price of abatement. This holds because theoretically, the rate of abatement will never exceed the reduction of the cap: if this would happen, the market would immediately turn into surplus, which would result in a lower allowance price. Therefore, in order to achieve the emissions reduction goal, the policy should ideally be steered such that the EUA market is continuously short.

By modelling the fundamentals of allowance demand and supply on a macro-economic level and adding volatile time-series to account for the natural volatility of market fundamentals, a model

was developed to provide a more comprehensive analysis of the carbon price than is typically found in the available literature on carbon price analysis. The fundamental EUA price model described in this paper combines political, institutional and economical factors with data of the most recent study on the estimated abatement potential by McKinsey.

Model predicitions

From the results, however, a picture emerges which is anything but optimistic with respect to the functioning and possible success of the European Trading Scheme. The scarcity of allowances over time for the Business As Usual (BAU) scenario, reflecting the current EU ETS policy, is shown in figure 1 with the corresponding EUA price forecast in figure 2.

In figure 1, a bar represents the forecasted mean scarcity of allowances for a specific year where a positive number represents an allowance surplus, while negative numbers represent a scarcity of allowances. The dotted line represents the median and the green and blue lines together form the 80% confidence interval. What stands out from the BAU forecast is that the market is expected to experience major surpluses of allowances until 2020, and even beyond. Assuming that European economic growth was -2% for 2009 and will be 0% for 2010, a significant share of the immediate oversupply in 2009 is the result of the economic turndown following the financial crisis. However, other simulations have shown that even in the absence of an economic crisis a prolonged surplus of allowances would have been likely. Although the recession does bring the EU closer to its emission reduction target for 2020, it seems a risky policy to rely on economic downturns to achieve the emission reduction target. A stock of allowances builds up as firms bank excess allowances during the recession, allowing firms to postpone carbon abatement once the economy rebounds. To increase the probability of achieving the 2020 target it is imperative that investments in carbon abatement are not post-poned for too long, as achieving the target requires a fundamental change in the way we produce and consume across many sectors. European legislators have introduced the EU ETS with

Fig 2: BAU Scenario - Fundamental EUA Price

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the objective to provide the incentive to kick-start this structural change. However, as long as allowances are in abundant supply the incentive to invest in carbon abatement is removed. Prolonged oversupply of allowances is therefore a serious threat to achieving the long-term emission reduction goal.

An oversupply of allowances is threathening the EU ETS

The economic crisis has currently resulted in a substantial oversupply of allowances. Besides the economic crisis, there are a few other important factors that contribute to the surplus of allowances. First of all, the linking directive is an important threat to allowance scarcity. Although the EU ETS cap was set more or less equal to the level of emissions in 2008, the linking directive allows individual firms to use Kyoto credits (CERs and ERUs6) on top of the original cap to offset their emissions. The potential to use Kyoto offsets is different for each participating country under EU ETS, but the weighted average over all countries is 13.3% on top of the EU ETS cap. Effectively, this means that emissions will not drop immediately once the EU ETS cap is lowered as firms can rely on Kyoto credits instead. In 2008 alone, more than 81 MtCO2e worth of Kyoto credits were used to offset emissions. Given the enormous potential to use Kyoto offsets under EU ETS (up to around 277 MtCO2e annually in Phase II), the linking directive provides the EU industry with a potentially cheaper alternative to carbon abatement within the EU.

Secondly, five percent of the original cap is not freely traded yet. Instead, these allowances are allocated to the New Entrants Reserve (NER). Once a new installation has been built, allowances from the NER are issued to cover the new installation. Many new installations, however, are replacements for older installations already covered under the scheme. Therefore, the replacement of the older installations effectively means that more allowances are freely traded on the market, while emissions typically reduce as more effective installations replace older equipment. The current

NER will be used until the end of 2012, after which a new NER will be formed from allowances in the market. This is represented in figure 1 by a sharp drop in allowance oversupply in 2013. In the course of subsequent years, however, the allowances slowly return to the market as new installations are covered under EU ETS.

Both the linking directive and the NER, in combination with the current recession, result in a hefty surplus of allowances. As a result, the probability that the market will end up short is merely 12% in 2013 (the first year of Phase III) and 33% in 2020.

Low EUA prices are the result

The lack of scarcity of allowances translates into low EUA prices, as depicted in figure 2. In 2008, the base year, the market is still 54.4 MtCO2e short. As a result, some firms are bound to cut emis-sions in order to prevent having to pay the non-compliance penalty. Because insufficient abatement potential is available immediately to absorb the full shortage, the price starts off at €100. Due to a modelling artefact, insufficient abatement potential is available in that same year to absorb the full shortage. As a result, the price jumps to €100, equal to the non-compliance penalty. After 2008, however, the average price immediately drops to zero as a result of the surplus of allowances and recovers to a price of only €10 in 2025, denoted in real November 2009 terms. The 80% confidence interval is equal to zero until 2015, after which the 10th percentile stabilizes at around €20 to €25.

Under the BAU scenario, the EU ETS forces the industry to an average cumulative abatement of 107.3 MtCO2 between 2008 and 2020. As a result, the probability that the EU will achieve its emission reduction goal is merely 13.8% for 2020. Under current legislation the EU cannot be even certain that the 2020 target will be met by 2030. One decade after the 2020 deadline the probability of achieving the target is 92.7%.

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CCS: will the EU ETS result in its timely deployment?

Another European objective is to make CCS economically viable by 2020. Essentially, this means that the carbon price should be high enough to make abatement through CCS a cheaper alternative to emitting carbon dioxide. However, under the BAU scenario, the probability that CCS will become economically viable is only 7% in 2020. Therefore, either hefty government subsidies will be needed to make CCS work, or CCS will not become, at least for the foreseeable future, a cost effective solution altogether under the EU ETS7. Given the large stock of banked allowances, the industry does not need to develop CCS in order to comply with the EU ETS regulation. Because more than enough low-cost abatement poten-tial is available, stricter regulation with respect to allowance supply is needed to make CCS a feasible policy alternative to the industry. As a result, the current EU ETS policy does not support the European objective of making CCS economically viable by 2020.

A policy proposal to increase the probability of success

While a higher cap reduction would reduce the number of issued allowances over time, the effects of such a measure would only become visible over the long term given the large oversupply the market is currently facing. At the same time, a complete abolishment of the linking directive is politically hard to achieve. Therefore, a combination of both measures is proposed to reduce the supply of allowances and improve the probability of achieving the reduction target in 2020. In this scenario the annual reduction of the EU ETS cap is increased to 2.5% and the linking directive is limited to the usage level of 2008, which is equivalent to a weighted average of 4% on top of the official cap. Although we continue to see surpluses until the end of Phase II in this scenario (see figure 3), the picture is entirely different from the BAU scenario. The average cumulative abatement incentivised by the EU ETS until 2020 is now 276.8 MtCO2. As a result, the probability of reaching the 2020 reduction goal in time has increased to 65.6%.

While these numbers provide important insights into the functioning and effectiveness of the EU ETS, more importantly, the analysis in this scenario shows that the natural volatility in both allowance demand and allowance price is substantial. In 2020, long after the economic crisis, the probability of oversupply in that specific year is still 24.5%, while it is equally likely that the market ends up around 100 MtCO2e short. This ‘natural’ volatility has major implications for the EUA price forecast. Whereas the average EUA price is around €26 in 2020, the 80% confidence interval ranges from €0 to €100. The broad confidence interval is primarily the result of the volatility in allowance demand. Although an even tighter cap reduces the probability that the EU ETS will ever return to a surplus of allowances over the long term, the uncertainty and volatility around the demand for allowances results in a naturally uncertain and unstable EUA price.

Can the EU ETS do the job?

An important question, therefore, that should be addressed is whether the EU ETS is the right tool to achieve the goals set by the EU. In the end, the theoretical efficiency and effectiveness of EU ETS can only be achieved if the supply of allowances is sufficiently tight and if the EUA price provides a strong and stable incentive to investors. Especially for projects like CCS, which require a considerable capital investment, a strong and stable incentive is a prerequisite. While a tax or specific regulation would provide a firm and predictable incentive to the industry, one cannot expect the EU ETS to provide a similarly strong incentive. In the end, the EU ETS merely mandates a specific number of allowances to be issued, while pricing is left to the market. Given the volatile nature of allowance demand, the EU ETS therefore seems incapable of achieving both the 2020 emission reduction target in time and the goal of making CCS economically viable by 2020. On top of that, the authorities should be careful when devising other incentives for carbon abatement directed at sectors under the ETS. Model simulations show that, for example, regulation mandating the

Figure 4: Policy alternative: 2.5% annual cap reduction and limited linking directive – Reduction of emissions under EU ETS compared to 2008

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installation of CCS on coal fired power plants could turn out to be a plain substitute for the EU ETS instead of complementing it. Any abatement effort incentivized by other means than the EU ETS primarily reduces the need for abatement in other sectors under the scheme. Therefore, given the EU ETS cap, other measures essentially work as a zero-sum game: instead of intensifying the abatement efforts, they merely transfer the abatement burden from one firm to another. Under the EU ETS, the firm with the lowest cost abatement opportunity is naturally forced to abate its emis-sions, which minimizes the societal costs of abatement. Therefore, any measure that shifts the abatement burden from one firm to another effectively reduces the efficiency of the trading scheme and increases the overall costs to society.

In conclusion, the model shows that a lot of political will and decisiveness are needed to improve the probability of attaining the 2020 goals. Given the current design of the EU ETS, the scheme is likely to miss its targets on all important accounts: an abundant supply of allowances, limited carbon abatement, no strong price incentive and no realization of CCS without substantial

government intervention. A limited linking directive combined with a stronger cap reduction could take away most of the immedi-ate risk of allowance oversupply. However, the natural volatility in allowance demand and in the EUA price would still continue to be a reason for concern as the EU ETS seems to be unable to provide the strong incentive the EU is hoping for.

1 Arnold Mulder is a Master student at the University of Groningen (Nether-lands), faculty of Economics, and has developed the EU ETS model during an internship at TNO. E-mail arnold.mulder @tno.nl

2 Christian Bos is Technology Manager at TNO Built Environment and Geosciences, Utrecht, the Netherlands. He leads the modelling work of the ECCO project. E-mail christian.bos@tno.nl

Footnotes

3 ECCO: European value Chain for CO2 (see www.sintef.no/ecco). This European project researches the economic feasibility of Carbon Capture and Storage value chains, including CCS projects with CO2 Enhanced Oil Recovery (CO2-EOR) in depleted oil fields.4 EUA: European Allowance, i.e. the right to emit 1 tonne of CO2 5 See for example directive 2009/31/EC6 Certified Emission Reductions and Emission Reduction Units7 Note that as part of the ECCO project (footnote 3), it is being studied whether the incremental income from CO2-EOR may improve the econo-mics of CCS in case (depleted) oil fields are being used as storage.

Reference

European Commission (2008) “The EU Emissions Trading Scheme”, Office of the Official Publications of the European Communities

17

Shifting StreamsJoris KoornneefConsultant Energy and

Climate, Ecofys

The Editorial Board of the Quarterly held an electronic interview with Mr. Koornneef upon the completion of his Ph.D thesis and asked him to elaborate on his results in the Quarterly.

In your research you have explored different approaches for assessing the effects of CCS. You discussed Life Cycle Assessments, Scenario tools, Quantitative Risk Assessment (QRA) and the so-called DPSIR framework. Could you elaborate on the strengths and weaknesses of these methods when used for assessing the effects of CCS?

The main strength of the life cycle assessment (LCA) is that it takes into account the environmental consequences of up- and downstream processes, such as feedstock production and waste management chains of a coal fired power plant with post-combus-tion capture, transport by pipeline and storage in a hydrocarbon reservoir. It also shows the trade-offs and synergies between mul-tiple environmental themes that are affected by the production of electricity with CCS. The main limitation of the LCA for CCS that I have conducted is that data on environmental conse-quences (emissions and waste formation) from (demonstration/pilot) power plants operating with CO2 capture are scarce. I therefore had to rely heavily on desktop studies instead of emission reporting documents from operating power plants.

The strength of the scenario tool that I have developed together with colleagues is that it allows a first of a kind study which systematically assesses the potential impact on air quality of various CO2capture systems in the European power and heat sector in 2030. The tool is based on the GAINS model developed by the IIASA. The model is used here to analyse primary energy con-sumption and emission control strategies, including post-, pre- and oxyfuel CO2 capture, and to calculate their potential effect on emis-sion levels of key atmospheric pollutants, being: NOx, SO2, NH3 and particulate matter.

One limitation of the scenario tool is that geographically depen-dent restrictions and advantages regarding transport and storage of CO2 are not taken into account. In other words, I have not looked at the geographical distribution of storage capacity in the EU. Another limitation is that the implementation of CO2 capture is not based on economic optimization. As with the life cycle assessment, the limited availability of reliable data on non-CO2 emissions is at present also a limiting factor resulting in results with relative large uncertainty, as shown later in this article.

Another research effort was aimed at assessing the strengths and limitations of currently used approaches and tools to assess the risk of CO2 transport by pipelines. The strength of currently used QRA tools is that they build upon the vast experience and set of tools available for the assessment of risk of transporting dangerous (toxic or flammable) substances by pipelines. An important limitation when assessing risks is the absence of validated release and dispersion models for high-pressure CO2 pipeline failures.

Moreover, failure rates used in QRAs for CO2 pipelines are also found to be uncertain, which has significant consequences on the precision of the outcome of the QRA. Furthermore, detailed and accurate dose-response models, uniform HSE (Health, Safety and Environment) thresholds and specific CO2 pipeline regulation are not part of the current knowledge base. Finally, the assessment of the effects of impurities on operation, failure rates and HSE impacts requires further attention.

For CO2 storage, the risk assessments (RA) of several projects have been reviewed. The main strength of these RA methodolo-gies is that they can build upon the vast experience gained when developing existing methodologies and tools for the hydrocarbon industry and for underground storage of nuclear waste. The safe and long-term storage of CO2 is however identified as a critical issue compared to environmental impact assessments for current established activities in the underground, such as underground gas storage. Models developed to assess the transport and fate of CO2 are based on experience in the oil and gas industry. These models are however not developed to assess the fate of CO2 including detailed long- and short-term interactions of CO2 with the under-ground. Also, the integration and validation of various sub-models describing fate and transport of CO2 in various compartments in the underground are found to require further efforts. In addition, failure rates are found to be heavily based on expert opinions and the dose-response models for ecosystems require further efforts. One of my conclusions is therefore that it is not possible to execute a QRA for the non-engineered part of a CO2 storage activity with high confidence. However, this conclusion on the level of confi-dence should not be confused with a judgement on the severity and acceptability of the risks of CO2 storage as I will show later.

Finally, we applied the so-called DPSIR framework - describing environmental Drivers, Pressures, States, Impacts and Responses - as a review framework to systematically identify, characterize and communicate known and new environmental consequences associated with CO2 capture from power plants, transport by pipeline and storage in geological formations. The DPSIR framework is an easy and flexible tool that can be used to investigate the environmental impacts on multiple themes and levels of detail. This flexibility and simplicity of the tool are however also identified as possible sources of bias when using this to structure environmental information related to a CCS activity.

You have used all of these tools in order to assess the Health, Safety and Environmental (HSE) impacts of implementing CCS in the power and heat sector. What are your main findings?

In the life cycle assessment I compare the environmental impacts of three pulverized coal fired electricity supply chains with and without CCS. Two of these chains are reference chains which represent subcritical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. Results show that, due to CCS, the greenhouse gas emissions per kWh are reduced

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substantially to 243 g/kWh. This is a reduction of 78% and 71% compared to the subcritical and state-of-the-art power plant without CCS. The 90% removal of CO2 from the power plant’s flue gases is partially offset by increased GHG emissions in up- and downstream processes. Environmental synergies are found due to the deeper reduction of hydrogen fluoride (HF) and hydrogen chloride (HCl) emissions into the atmosphere. Most notable environmental trade-offs are found to be the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by the reference cases without CCS. The state-of-the-art power plant without CCS also shows a better score for eutrophication, acidification and photo-chemical oxidation potential despite the deeper reduction of SOx and NOx in the power plant equipped with CO2 capture. On a kWh-basis these reductions are offset by increased emissions in the life cycle, resulting in a net increase of SO2 (up to 18%) and NOx (up to 35%) emissions per kWh. The overall increase in the eutrophication and acidification potential for the chain with CCS is the result of the energy penalty due to the energy use for capture and compression, and increase in NH3 emissions over the full life cycle. The energy penalty also results in a trade-off in potential environmental impacts due to an increase of upstream environmental consequences, primarily in the coal supply chain. Another trade-off can be ascribed to the supply chain and emission of monoethanolamine, which is used in the CO2 capture process. This strongly affects the score for the human toxicity potential which potentially increases significantly when applying this post-combustion CO2 capture technology. It should however be noted that this score is highly uncertain due to the absence of reliable data based on measurements. Overall, it is found that the energy penalty induces significant environmental trade-offs on the plant level and throughout the CCS chain. Furthermore, most environmental interventions and impacts are found to be induced in the operational phase of the power plant with CO2 capture.

Using the scenario tool it was possible to assess the trade-offs and synergies between climate and air quality policy objectives in detail for the European power and heat (P&H) sector in 2030. The results show a reduction in GHG emissions for the scenarios with post-, pre- and oxyfuel CO2 capture compared to a baseline scenario without capture between 7% and 16% in the EU27. NOx emissions are 15% higher in the P&H sector in a scenario with pre-dominantly post-combustion CO2 capture and lower when oxyfuel combustion CO2 capture (-16%) or pre-combustion CO2 capture (-20%) is implemented on a large-scale. Large-scale implementation of the post-combustion capture technology in 2030 may also result in significantly higher NH3 emissions. In contrast, SO2 emissions are found to be very low for all scenarios that include large-scale implementation of CO2 capture in 2030, i.e. a reduction varying between 27% and 41%. Particulate matter (PM) emissions are found to be lower in the scenarios with CO2 capture. The scenario with implementation of the oxyfuel combustion CO2 capture technology shows the lowest PM emissions followed by the scenario with a significant share allocated to pre-combustion, respectively -59% and -31%. The scenario with post–combustion capture results in PM emissions varying between 35% reduction and 26% increase.

The contribution of the P&H sector to the total emission level in the EU is found to vary per substance. EU wide NOx and SO2

emission levels are found to be strongly affected by the implemen-tation of CO2 capture. In addition, the NH3 emission level has the potential to become significant in the post-combustion scenario, where the contribution of the P&H sector to the EU27 total increases strongly.

The review of environmental effects then continued with the use of the DPSIR model. The results of that analysis show that the capture of CO2 from power plants results in a change in the envi-ronmental consequences of the power plant depending on the con-figuration of the energy conversion technology and CO2 capture system. This includes (partly) the above mentioned trade-offs and synergies in the reduction of key atmospheric emissions, being: NOx, SO2, NH3, particulate matter, mercury (Hg), HF and HCl. In addition, an increase in water consumption ranging between 32% and 93% and an increase in waste and by-product creation in the order of tens of kilotonnes (assuming a 1 GWe power plant) is found. The consumption of resources is also found to significantly increase when equipping power plants with CO2 capture. Of the environmental consequences induced or changed by equipping power plants with CO2 capture, the effect of emissions to the air are researched in more detail than other environmental interven-tions, such as waste and by-product generation and emissions to surface water bodies. The main conclusion of this part of the analysis is that emission factors and these so called cross-media effects as a result of CO2 capture are uncertain and to a large extent not quantified.

Another part of the research was the risk assessment of CO2 transportation by pipelines. The results show that knowledge gaps and uncertainties have a large effect on the accuracy of the assessed risks of CO2 pipelines. For instance, the individual risk contour (i.e. the contour depicting on a map the probability of 1*10-6 per year that an unprotected ever-present person dies) can vary between 0 and 204 m from a pipeline depending on assumptions made on: the failure rate, direction and momentum of release, the vapour and dry ice fraction in the release and the dose-effect rela-tionship. An assessment of risk mitigating efforts - such as block valves, protective materials and physical barriers, route selection and management agreements- shows that mitigating the relevant risks can be considered part of current practice, making the risks of CO2 transport by pipelines controllable. Therewith it is possible to meet stringent risk norms if required. In earlier RA studies for CO2 pipelines performed all over the world a wide range of assumptions, methods, and toxicity thresholds and endpoints is used. As a result, the distance at which negative HSE effects are expected is found to be between <1 m and 7.2 km (!). This shows the importance of formulating uniform RA guidelines and regulations for CO2 pipelines.

The HSE effects of CO2 storage are also discussed, including the risks. Typical failure scenarios for CO2 storage activity that were assessed in the reviewed risk assessments are: leakage along a well and well head failure, caprock failure or permeability, leakage along a spill point and leakage through existing or induced faults and fractures. For these failure scenarios possible leakage rates are reported in the study rendering the insight that a wellhead failure and leakage along a well are most likely the scenarios with the highest leakage rates (relatively 510 en 0.02 kg /s). Regarding the safety of the transport and storage of CO2, it is found that the

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maximum CO2 release rates (22 tonne/s) associated with a failing transport or storage activity are reported to be the highest for the transport activity.

When using the release rate as proxy for the HSE consequen-ces this would suggest that CO2 transportation activities result in higher risks compared to the storage activity. This neglects however the probability of occurrence and local conditions which are crucial when determining risk with quantitative indicators. My conclusion is thus that a complete and equal comparison cannot be made at this moment.

Some adverse effects attributed to CCS were also listed in your analysis. In your opinion, do the benefits of implementing CCS outweigh the negative impacts?

Indeed some adverse effects have been identified, next to positive side-effects. These include direct emissions of hazardous substances and waste formation due to CO2 capture, life cycle emissions and impacts due to the energy penalty and additional risks. Do the benefits outweigh the adverse? Personally I think that climate change is one of the biggest threats that mankind will face in this century. All efforts should focus on developing a portfolio of GHG mitigation options that will make this threat less severe. However, other environmental themes should not be forgotten. NOx emissions, for instance, are a serious problem and should be kept to an absolute minimum. We should thus aim towards redu-cing these other more often ‘forgotten’ emissions as well. For me personally the balance tips towards the positive impacts of CCS as I think that if appropriate attention is paid towards these negative trade-offs, then technical solutions will be implemented that will mitigate the negative impacts as far as possible. With the prospect of the technological development of CCS and the major advan-tage that it in the end may deliver negative GHG emissions when combined with biomass as major feedstock, I think CCS deserves a place in the portfolio of GHG mitigation options.

Could you indicate what in your view the main concerns and knowledge gaps are regarding the procedural assessment of Health, Safety and Environmental impacts of CCS in Environmental Impact Assessments (EIA) and Strategic Environ-mental Assessments (SEA); what would be your most important recommendations with regard to further research and development efforts in the area you researched?

I have looked at the procedural aspects of the EIA and SEA. The Environmental Impact Assessment (EIA) and Strategic Environmental Assessment (SEA) are procedural tools to assess and evaluate possible environmental consequences of, respectively, a proposed CCS project or strategic plan that contains possible CCS projects. The scoping phase of these procedures is of impor-tance to create focus and acceptance of the structure and content of the EIA/SEA procedure. Based on historic experiences with these

procedures worldwide and in the Netherlands with CCS and analo-gous activities, I have constructed some recommendations for the scope of both procedures for CCS in the Netherlands. The most important advice is to start a strategic environmental assessment for CCS as early as possible. In such a procedure in conjunction with a strategic spatial plan it is possible to identify CO2 storage sites, CO2 point sources and possible transport routes. The CCS infrastructure, including storage sites, is then assessed on its possible impacts on human safety and environment in an early phase. The main advantage will be that the public is then involved and consulted in a very early phase of the decision making process, well before the actual start of implementing CCS projects. I expect that for CCS projects it will be then easier to perform an EIA on the project level as they can refer to the strategic plan. Personally I think the public is then also better informed and served, which may fasten the implementation of projects.

In your opinion, what are the implications of these results for the further development and implementation of CCS?

These results indicate that it is necessary to assess environmental impacts in an early stage of technology development. Further, it is required that the CCS community does not forget environmental themes other then climate change. For CCS technologies I regard it very necessary to set up extensive environmental monitoring programmes at CO2 capture (demonstration) plants aimed at creating a better understanding of the formation and fate of solid, liquid and atmospheric pollutants.

Furthermore, the release and dispersion models for high-pressure CO2 releases need to be validated. These models are used in quantitative risk assessments for CO2 transport by pipeline and for CO2 storage activities. Widespread implementation of CCS requires a significant infrastructure build-up. If risks cannot be accurately assessed for this infrastructure implementation may be significantly delayed.

Overall, most gaps in environmental information regarding the CCS chain are identified and characterized for the underground part of the storage activity. And although the failure of the underground CO2 storage system appears to have limited HSE consequences, suggesting a low risk, the uncertainty regarding the assessment of the risk is a potential bottleneck for wide scale implementation of CCS if not properly addressed. To deal with uncertainties in the performance/risk assessment of CO2 storage activities a stepwise approach is recommended, starting with an intensive (e.g. annual) evaluation cycle of CO2 storage activities, including: planning, modelling, monitoring, verification, calibra-tion and evaluation. This cycle should focus on the operational phase and post-closure phase. With assuring monitoring results it then can be decided to gradually reduce the frequency of this cycle and reduce the intensity of monitoring depending on the outcomes of an evaluation using pre-set performance indicators.

Books, reports and conferences

European Climate foundation, April 2010, Roadmap 2050: A practical guide to a prosperous, low-carbon Europe.

The Roadmap 2050 project sets out the crucial role of a zero-carbon power sector to Europe’s long-term climate commitments and shows different pathways that can make this a reality delivering economic and energy security goals.

The Roadmap examines several decarbonization scenarios for the power sector and, based on a back-casting methodology, sets out the near-term implications of this long-term commitment. The analysis shows that in each of the scenarios the cost of zero carbon power remains in current ranges. It also shows that an inter-regional European transmission grid can provide the level of reliability that users expect in all scenarios.

The full report can be downloaded from the Roadmap 2050 website:http://www.roadmap2050.eu/

Nieuwenhout, F.D.J. e.a., May 2010, Market and regula-tory incentives for cost efficient integration of DG in the electricity system. IMPROGRES

Achieving the European target of 20% reduction of greenhouse gases in 2020 relies for a major part on increasing the share of renewable electricity generation, and more efficient fossil fuel based generation in combined heat and power installations. Most of these renewable and CHP generators are smaller in size than conventional power plants and are therefore usually connected to distribution grids instead of trans-mission grids. Different support schemes for renewable energy sources have been successfully implemented and have resulted in a rapid growth of distributed generation (DG). IMPROGRES scenario analy-sis shows that the installed capacity of DG in the EU-25 is expected to increase from 201 GW in 2008 to about 317 GW in 2020. A large part of this increase will be made up of more variable and less controllable renewable energy sources like wind and photovoltaics.

The full report is available from ECN’s website:http://www.ecn.nl/docs/library/report/2010/o10006.pdf

Meeus, L., e.a., May 2010, “Smart regulation for smart grids” Robert Schuman centre for advanced studies.

Climate change and security of supply policies are driving us towards a decarbonisation of the electricity system. It is in this context that smart grids are being discussed. Electricity grids, and hence their regulatory frameworks, have a key role to play in facilitating this transformation of the electricity system. In this paper, we analyze what is expected from grids and what are the regulatory tools that could be used to align the incentives of grid companies and grid users with what is expected from them. We look at three empirical cases to see which regulatory tools have already been applied and find that smart grids need a coherent regulatory framework addressing grid services, grid technology inno-vation and grid user participation to the ongoing grid innovation. The paper concludes with what appears to be a smart regulation for smart grids.

The full report can be found here: http://cadmus.eui.eu/dspace/bits-tream/1814/14043/1/RSCAS_2010_45.pdf

Glachant, J.M., Hallack, M., May 2010, The gas trans-portation network as a ‘Lego’ game: How to play it? Robert Schuman centre for advanced studies.

This paper provides a unified analytical frame for all types of gas trans-portation networks. It shows that gas transport networks are made of several components which can be combined in different ways. This very “lego property” of gas networks permits different designs with different economic properties while a certain infrastructural base and set of gas laws is common to all transportation networks. Therefore the notion of “gas transportation network” as a general and abstract concept does not have robust economic properties. The variety and modularity of gas networks come from the diversity of components, the variety of components combination and the historical inclusion of components in the network. First a gas network can com-bine different types of network components (primary or secondary ones). Second, the same components can be combined in different ways (notably regarding actual connections and flow paths). Third as a capital-intensive infrastructure combining various specific assets, gas transportation networks show strong “path dependency” properties as they evolve slowly over time by evolving from an already existing base. The heterogeneity of gas networks as a set of components comes firstly from the heterogeneity of the network components themselves, secon-dly from the different possibilities to combine these components and thirdly from the ‘path dependence’ character of gas network construc-tions. These three characteristics of gas networks explain the diversity of economic properties of the existent gas networks going from natural monopoly to competitive markets. The full report can be found here: http://cadmus.eui.eu/dspace/bits-tream/1814/13975/1/RSCAS_2010_42.pdf.

EBN, June 2010, Focus on Dutch gas.

In this report EBN gives a comprehensive overview of the Dutch gas sector. The report deals with current reserves and production, gas infrastructure, exploration and current developments. The report can be downloaded from EBN’s website.

The full report can be found here: http://www.ebn.nl/files/focus_on_dutch_gas_2009.pdf.

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EDI Quarterly is published in order to inform our readers not only about what is going on in EDI, but also and in particular to provide information, perspectives and points of view about gas and energy market developments.

Read the latest developments in the energy industry, daily published on the website of EDI.

Editor in ChiefProf. Catrinus J. JepmaPresident of Energy Delta Institute

EditorsLeo HoendersMarius PopescuSanne BückingSteven von EijeIvelina Boneva

EDI Quarterly contact informationEnergy Delta Institute Laan Corpus den Hoorn 300 P.O. Box 11073 9700 CB GRONINGENThe Netherlands T +31 (0)50 5248331 F +31 (0)50 5248301 E quarterly@energydelta.nl

Upcoming conferences

July 6:Platts LNG ForumMadrid, SpainWebsite: www.platts.com

July 9:Will FLNG ever be a reality?London, UKWebsite: http://www.smi-online.co.uk/training/overview.asp?is=5&ref=3411

July 19-20 :Global Shale Gas SummitWarsaw, PolandWebsite: http://www.global-shale-gas-summit-2010.com/

July 28-30: International Conference on Energy and EnvironmentParis, FranceWebsite: http://www.waset.org/conferences/Energy_Environment

August 3-6:2nd Annual Offshore India Oil and Gas SummitMumbai, IndiaWebsite: http://www.offshoreindiaoilgas.com/

September 15-16:Gas Storage 2010Rotterdam, The NetherlandsWebsite: http://www.iir.nl/energy/event/2_daagse_conferentie/

September 23-24:Unconventional GasLondon, United KingdomWebsite: http://www.platts.com/Unconventional_gas_conference

October 12:Energy transition and leadershipTBAWebsite: http://www.energydelta.org/en/mainmenu/conferences/intro