EUROPEAN COMMISSION

Brussels, 30.11.2016

SWD(2016) 418 final

COMMISSION STAFF WORKING DOCUMENT

IMPACT ASSESSMENT

Accompanying the document

Proposal for a Directive of the European Parliament and of the Council on the promotion of the use of energy from renewable sources (recast)

{COM(2016) 767 final}
{SWD(2016) 419 final}

Contents

Abstract accompanying the Impact Assessment

1.Introduction

1.1.Background and scope of the initiative

1.2.Context of the initiative

1.3.Links with parallel initiatives, approach taken for modelling, data gaps and other limitations

1.3.1.Links with parallel initiatives

1.3.2.Approach taken for modelling and limitations

2.What is the Problem and why is it a Problem?

2.1.Evolution of the problem and need to act post-2020

2.2.The problem areas and underlying main drivers

2.2.1.Problem 1 - Investor uncertainty

2.2.2.Problem 2 - Need to improve cost-effectiveness of deployment of renewable energy

2.2.3.Problem 3 - Absence of functioning markets

2.2.4.Problem 4 - Need to update the regulatory framework

2.2.5.Problem 5 - Lack of citizen-buy in during transition

2.3.The EU dimension of the problem

2.4.Who is affected and how

2.5.REFIT Evaluation of the RES Directive

3.Subsidiarity and the diverse situations in Member States

3.1.Legal base

3.2.Necessity of EU action

3.3.EU added-value

4.Objectives

4.1.General objectives

4.2.Specific objectives

5.Policy options

5.1.Options to increase renewable energy in the electricity sector (RES-E)

5.1.1.Consolidating a framework for cost-effective, and market-oriented and Europeanised support to renewable electricity to promote regulatory certainty

5.1.2.A more coordinated regional approach to renewables support

5.1.3.Reducing the cost of capital for renewable electricity projects

5.1.4 Administrative simplification

5.1.5.Overall comparison of the options to increase renewable energy in the electricity sector (RES-E)

5.2.Options to increase renewable energy in the heating and cooling sector (RES-H&C)

5.2.1.Mainstreaming renewables in heating and cooling supply

5.2.2.Facilitating the uptake of renewable energy and waste heat in district heating and cooling systems

5.2.3.Overall comparison of the options to increase renewable energy in the heating and cooling sector (RES-H&C)

5.3.Options to increase renewable energy in the transport sector (RES-T)

5.3.1.Overall comparison of the options to increase renewable energy in the transport sector (RES-T)

5.4.Options to empower and inform consumers of renewable energy

5.4.1.Empower consumers to generate, self-consume and store renewable electricity

5.4.2.Disclosing information on the sources of electricity generation

5.4.3.Tracing origins of renewable fuels used in heating and cooling and transport

5.4.4.Overall comparison of the options to empower and inform consumers of renewable energy

5.5.Options to ensure the achievement of at least 27% renewable energy in 2030

5.5.1.Baseline of 2020 targets

5.5.2.EU Trajectory 2021 - 2030 for achievement of the EU renewables target

5.5.3.Mechanism to avoid an "ambition gap" to the EU renewables target

5.5.4.Mechanism to avoid and fill a "delivery gap" to the EU renewables target

5.5.5.Overall comparison of the options to ensure the achievement of at least 27% renewable energy in 2030

Abstract accompanying the Impact Assessment

1.    Policy Context And Key Challenges

The Energy Union framework strategy puts forward a vision of an energy market 'with citizens at its core, where citizens take ownership of the energy transition, benefit from new technologies to reduce their bills, participate actively in the market, and where vulnerable consumers are protected'.

The Energy Union with a sustainable, low-carbon and climate-friendly economy includes President Juncker's political ambition to become the world leader in renewable energy, the global hub for developing technically advanced and competitive renewable energies 1 .

To live up to this vision, a series of legislative proposals have been prepared, following the objectives of secure and competitive energy supplies and building on the EU's 2030 climate commitments reconfirmed in Paris last year.

Renewables in Europe – good results so far

As a result of Directive 2009/28/EC (2009 RES Directive), with currently 16% of renewable energy in its final energy consumption 2 , the European Union is on track to achieve its 20% renewables target by 2020. This piece of EU legislation, along with other EU and Member State complementary measures, has boosted European investment in renewable technologies at a domestic level. Renewables are now being deployed across the various sectors (electricity, transport, and heating and cooling) in all Member States. Economies of scale and innovation have reduced significantly the related costs 3 .

The renewable energy sector already delivers an important dividend to EU energy security with around €20 billion saved in fuel import costs in 2014 for the whole EU. The sector also remains key to EU objectives to sustain and improve growth, employment and competitiveness. The EU renewable energy industry employed in 2014 around 1.1 million workers 4 , and European companies held 30% of all patents for renewable technologies globally in 2013 5 .

Taking renewables to the next level – the 2030 framework and EU leadership in renewables

The EU has set itself a target to reach, collectively, a share of at least 27 % in the final energy consumption by 2030.

While the EU is today well on track to achieve its 2020 renewables target, yet, investments in renewable have dropped by more than half since 2011 to $48.8 billion last year. The EU now accounts for only 18% 6 of global total investment in renewables, down from close to 50% only 6 years ago. This calls for concrete and decisive actions to put the EU back on track in pioneering world efforts.

While the Renewables Directive, together with the Market Design and Energy Union Governance initiatives, will be a central element for the EU to pursue its ambition of a world leadership role in renewables, this political goal needs to be further supported in a holistic approach by policies and initiatives also in areas outside the scope of this package, such as financing (including ESIF and EFSI), regional development, research and innovation, international cooperation and industrial policy.

Key challenges and opportunities going forward

The costs for a number of renewable energy technologies have rapidly declined, this shifting the need for policy intervention from cost-competitiveness issues to market integration aspects - at least for most mature technologies.

The EU policy framework for renewable electricity (RES-E) has successfully turned solar and onshore wind technologies from niche technologies into central players in the power sector. However, the heating and cooling, and the transport sectors continue to rely heavily on fossil energy imports.

The move from national binding targets set by the current 2020 framework, towards an EU-level binding target for renewables for 2030, opens up new challenges, but also new opportunities for the EU to achieve the target collectively and in a cost-effective, sustainable way.

New technologies like smart grids, smart homes, increasingly competitive roof-top solar panels and battery storage solutions make it possible for energy consumers to become active players on the market and this opportunity should be harnessed.

Markets for renewable energy are opening across the world. Whilst global investments in renewable energy are growing, the investments in renewables in the European Union are declining, jeopardising the EU leadership ambition.

2.    Problem definition

The EU as a whole is currently on track to reach a share of renewable energy of 24.3% by 2030, falling short of the 2030 ambition. This result shows that we risk following a development path that is insufficient to achieve the 2050 decarbonisation scenarios.

Several obstacles still prevent a cost-effective achievement of an at least 27% renewable energy target within the European Union in a business as usual scenario.

Investor uncertainty

For the EU, the investment needs are estimated to be around or above €1 trillion from 2015 to 2030 in renewable electricity generation alone 7 . It is unclear at which point in time an enhanced market design and a strengthened EU ETS, alongside other factors such as further cost reductions, will provide sufficient incentives for renewable energy investments, without any additional support to cover investment gaps. Further uncertainty for investors comes from the future evolution of rules on support schemes. In addition, the uncertainty regarding the EU sustainability criteria post-2020 is not conducive for investment in the bioenergy sector, including in advanced biofuels.

Lack of cost-effectiveness

Renewable technologies are being deployed across various sectors - electricity, heating and cooling, and transport, with different levels of cost-effectiveness. Over the past decade, a lot of emphasis was put on the development of renewable electricity. The 2030 and 2050 decarbonisations scenarios require however also accelerated renewables deployment in heating and cooling, and transport.

Renewable technologies, their cost and potentials vary significantly. Ignoring these differences might result in either underinvestment or overcompensation. There are also clear benefits to be reaped from a more Europeanised approach to renewables support, in order to facilitate cost-effective deployment of renewable electricity across the EU. Last but not least, differences in cost of capital and national approaches to other investment conditions such as grid connection fees undermine the optimal allocation of renewable electricity generation capacity across the EU.

Imperfect markets

Well-functioning internal energy markets are crucial for the deployment of renewables. However, the markets in the electricity, transport and heating and cooling sectors are at different phases of development or integration and require different measures to ensure their correct functioning. In the case of the electricity sector, where renewables are expected to reach around 50% market penetration by 2030, the electricity market should be redesigned to support the integration of renewables as proposed in the framework of the Market Design initiative. In the heating and cooling market, the challenge is to ensure access to existing infrastructure and sufficient incentives for the expansion of renewables. In the transport sector, renewable energy uptake is still hampered by a lack of clear market signals for low-carbon and renewable fuels.

Update of the regulatory framework

The renewable energy target of at least 27% is expressed as a binding target at EU level. This is a policy change from the previously binding targets at national level on which the current EU legislation and in particular the 2009 RES Directive is built. Furthermore there will be no specific sectorial targets as it is the case with the current 10 % target in the transport sector. This calls for an update of the regulatory framework so that it is adapted to the new approach.

Lack of citizen buy in

Existing rules do not sufficiently enable citizens and communities to have sufficient buy in into the energy transition. This can lead to lack of public acceptance at local level, resulting in higher development costs and slower renewable development. Empowering consumers and energy communities, and providing them with reliable information about renewables, are therefore fundamental preconditions for deploying renewable energies in a cost-effective way.

3.    Overarching goals of the revised Renewable Energy Directive

Renewable energy is central to the five dimensions of the Energy Union: energy security, energy efficiency, competitiveness, emission reduction, and global leadership through innovation. As such, the new EU-wide renewable energy target for 2030 set by the European Council in October 2014, based on the Commission's proposal and underpinning analysis presented in the 2030 Framework for Climate and Energy 8 and the Energy Union Framework Strategy 9 , is key for achieving the Energy Union priorities.

Therefore, the ambition is to increase the share of renewable energy consumed in the EU to at least 27% by 2030 in line with the cost-effective pathway described in the 2030 Framework for Climate and Energy, and further reduce greenhouse gas emissions (at least 40% by 2030) and save at least 27% energy by 2030 compared to 2007 baseline projections.

The specific goals are:

First, the renewables deployment should contribute to greenhouse gas emissions reduction of at least 40% compared to 1990 levels, including a reduction of 30.2% of emissions in the non-ETS sector compared to 2005 levels. It should bring the EU economy closer to the required decarbonisation pathway to achieve the objective of 80-95% emissions reduction by 2050.

Second, the revised Directive should improve energy security by diversifying the energy mix and reduce EU's dependence on imported fossil fuels, particularly in the heating and cooling sector and the transport sector, as outlined in the 2030 Framework for Climate and Energy. Overall, the specific measures proposed for these two sectors could lead to a reduction in import dependency.

Third, renewable energies should further contribute to the integration of the internal energy market. The results show that a continuation of nationally-based support schemes would lead to less efficient deployment of renewable energy, a concentration of renewables investments in three countries, and a 25% increase in the average electricity prices in 2030 compared to 2010 10 . In contrast, a consolidated framework that builds upon a good market functioning, a more coordinated regional approach and addressing the costs of capital can achieve a more balanced deployment of renewables across the EU and reduce energy system costs.

Finally, the proposed options should foster innovation in renewables deployment and ensure that the EU can truly become a global leader in renewables. The proposed measures would strengthen both technology and market driven innovation, support the creation of flexible and integrated infrastructure, and create healthy supply chains, thereby enhancing the EU technological leadership role in this sector. With this experience, European companies will be able to position themselves to support the global transformation towards a more sustainable energy system.

4.    Interlinkages with other initiatives

The preparation of this Impact Assessment has been done in close coordination with, and is complementary to, other related Commission initiatives. First and foremost, this includes the Market Design and Energy Union Governance proposals but also the revision of the Energy Efficiency and Energy Performance of Buildings Directives, the EU ETS and the Effort Sharing Regulation, the LULUCF Regulation and the Bioenergy Sustainability Policy.

These other pieces of legislation mutually complement the Directive. However, they are not by themselves sufficient to allow the EU to reach, collectively, a share of at least 27 % in the final energy consumption by 2030 in a cost effective way and to deliver on the EU political priority of becoming the world's number one in renewables.

The Market Design initiative will, inter alia, facilitate the development of an electricity market fit for renewable energies, where short term markets are fully developed and integrated and flexibility plays a key role in enhancing the market value of renewables. This enhanced electricity market design, together with the strengthened EU ETS, will be a key foundation of the 2030 framework and will ensure that renewable energy generators can earn a higher fraction of their revenues from the energy markets. The revision of the Renewables Directive will build on this approach and complement it by introducing different measures aimed at attracting the necessary investments cost-efficiently and in a timely manner.

The Energy Union Governance frames the Integrated National Energy and Climate Plans, which set out national contributions to the legally binding EU-level RES target. The revision of the Renewables Directive complements the Energy Union Governance by considering different options to fill a potential gap either on ambition or delivery of the EU target. At the same time, the Governance initiative streamlines and integrates the existing planning, reporting and monitoring obligations of the energy acquis including those for renewable energy post 2020.

The Energy Efficiency Directive (EED) and Energy Performance for Buildings Directive (EPBD) aim, respectively, at facilitating the achievement of the energy efficiency target and at enhancing the energy performance of buildings. The provisions in the heating and cooling section are consistent with and complement the measures in both the EED and the EPBD, in particular by tackling existing buildings, tertiary and industry, as well as by including specific requirements on renewables.

The EU Emission Trading Scheme (EU ETS) will be reformed for the period after 2020 11 . Existing legislation includes the Market Stability Reserve to address the current surplus of allowances and to improve the ETS resilience to major shocks by adjusting the supply of allowances to be auctioned. The strengthened EU ETS will play an increasing role in providing a stronger investment signal for lower carbon technologies, including renewables, and will ensure that synergies between renewable energy and climate policies are better exploited. Furthermore, the proposed Effort Sharing Regulation 12  makes proposals for setting national binding emission reduction targets for greenhouse gases for the sectors outside the EU ETS and on Land Use, Land Use Change and Forestry (LULUCF). 

The LULUCF Regulation aims at integrating carbon emissions credits and debits form agriculture and forestry into the EU 2030 climate and energy framework. In addition, the Bioenergy Sustainability Policy aims at guaranteing the climate and environmental benefits of EU bioenergy consumption for the period after 2020, focusing in particular on biomass in heating/cooling and electricity. The provisions in the transport sector of this Impact Assessment build and complement these approaches, by promoting higher direct greenhouse gas saving for new biofuels and bioliquid installations.

5.    Subsidiarity

EU level action is needed to ensure that Member States' contribute to the at least 27% EU level binding renewable energy target and that this is collectively and cost-effectively met. Common principles to govern support of renewable electricity are needed to address fragmentation of the internal market and ensure cross-border tradability. Thus also a case for common rules for transport fuel could be made.

EU-level action on heating and cooling is necessary due to the high share of the sector in energy consumption, however given the limited cross-border dimension, the options are designed with a significant degree of flexibility for Member States. Member States' shares of heating and cooling in overall energy mix may differ, as does the relative importance of heating versus cooling. However, the fundamental market failures are similar, particularly due to technology lock-in (i.e. existing fossil fuel heating systems) and lock-out (consumers cannot individually change fuels in collective supplies such as gas grid, district heating, etc.).

Action only at Member States' level would likely lead to a more limited deployment of renewables and create additional costs that can be reduced through complementary EU-level action. It would also lead to more fragmentation of, and distortions in, the energy internal market and put the achievement of the EU renewable energy target at risk.

6.    Description of policy options and analysis of impacts

The overarching goals of the revision of the Directive can only be achieved through a systematic approach, which results in renewables being deployed cost-effectively in all Member States and in all sectors.

A balanced and stable set of measures aimed at facilitating renewables investments across the electricity, transport and heating and cooling sectors in the 28 Member States will enhance regulatory certainty. They should also improve the conditions for renewables investment to take place where needed. In addition, measures oriented towards empowering and informing consumers also mobilise private capital for investments in renewable energy and increase social acceptance of renewable energy projects. Lastly, given the binding nature of the EU level target it is necessary to make sure the target is achieved in a timely manner, in a way that is complementary to the Governance Initiative. The latter defines the iterative process between Member States and the Commission in order to ensure the respective national contributions to the target.

6.1    Expanding renewable electricity cost-effectively

Amongst all sectors that make up our energy system, electricity is the most cost-effective to decarbonize. In 2014, 27.5% of Europe's electricity is produced using renewable energy and the modelling shows that close to half of our electricity will come from renewables by 2030. Yet, the necessary investments in renewable power generation are declining, concentrated in a small number of countries 13 with low weighted cost of capital (WACC) and policy frameworks perceived as most stable, and are insufficient to achieve the 2030 target.

Consistent with 'The vision for the EU electricity market in 2030 and beyond' 14 , the Commission's ambition for the post-2020 context is that renewable electricity generators can earn a high fraction of their revenues from energy markets. Such a market would be based on an enhanced electricity market design – where short term markets are fully developed and integrated and flexibility plays a key role in enhancing the market value of renewables – as well as a strengthened EU ETS. These are no regret solutions that need to be at the core of the decarbonisation of the power system.

However, despite such market enhancement, in some cases energy market revenues alone will remain insufficient to attract renewable investments in a timely manner and at the required scale. Where limited, specific financial support is still needed, the market – via competitive tenders – will confirm its necessity and the level of support through tender mechanisms, which will act as a natural phase-out for support measures. Ensuring regulatory certainty is paramount to ensure cost-effective deployment of renewables electricity.

The findings of the Renewable Energy and the Electricity Market Design Impact Assessments and the proposed policy options

The results of modelling work undertaken for the Electricity Market Design and Renewable Energy Impact Assessments indicate that the improved electricity market, in conjunction with a revised ETS with a functioning Market Stability Reserve, could, under certain conditions, deliver investments in the most mature renewable technologies (such as solar PV and onshore wind) by 2030. However, less mature renewable electricity technologies, such as off-shore wind, ocean energy, will likely need some form of support throughout the period. The analysis shows that the picture is dynamic, with the enhanced market design and the strengthened EU ETS gradually improving renewable electricity profitability over the 2021-2030 period. At the beginning of the period, over-capacity, the imbalance on the ETS market and low wholesale electricity market prices and high renewable electricity technology costs, make the case for market only driven investment in renewable electricity technologies more difficult. However, a stronger carbon price signal, a more flexible and dynamic electricity market and technology cost reductions gradually facilitate market investment over this period.

The picture also depends on regions. RES-E technologies could be more easily financed by the market in the regions with the highest potential (e.g. onshore wind in the Nordic region or solar in Southern Europe), while RES-E continue to largely require support in the British Isles and in Central Europe. Conditions however also depend on the cost of capital.

At the same time it has to be acknowledged that whether and at what point in time financing of renewables through markets alone will actually take off remains difficult to predict. This is because financing of capital intensive technologies such as most renewables through markets based on marginal cost pricing will remain challenging. In particular, higher penetration of renewables with low marginal cost could further reduce the market value that such renewables can actually achieve (so-called cannibalisation effect). Further flexibilisation of demand stands out as a key measure in this regards in order to further stabilise the revenue of renewables producers from the market.

On the other hand, the future capacity of renewables to be financed through the market will also depend on certain conditions outside of the market design and ETS prices, such as continued decrease in the costs of technologies, availability of (reasonably cheap) capital, social acceptance and sufficiently high and stable fossil fuel prices.

While the market reforms described above are therefore no regret options to facilitate renewables investment, support schemes will still be needed at least for a transitional period. It is therefore essential to further reform such schemes to make them as market-oriented as possible.

Against this background, the RES Impact Assessment investigates options to ensure that if and where support is needed, (i) support is cost-effective and kept to a minimum, and (ii) creates as little distortion as possible in the functioning of electricity markets.

As a first measure, the RES Impact Assessment suggests creating a common European framework for support schemes. The framework would be effective as it would define design principles (i) that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where needed) of market-based and cost-effective schemes based on emerging best practice design (including principles that are not covered by the current state aid guidelines). At the same time, the framework would be proportionate by leaving actual implementation to the state aid guidelines (e.g. for the definition of thresholds applicable for any foreseen exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment of individual schemes by the services of DG Competition.

Importantly, the framework would enshrine in legislation and expand the requirement to tender support; it would define tender design principles, based on emerging best practice, to ensure the highest cost-efficiency gains. The framework would thus strengthen the use of tenders as a natural phase-out mechanism for support, by which a competitive bidding process determines the remaining level of support required to bridge any financing gap – such level of support being expected to disappear for the most mature technologies over the course of the 2021-2030 period.

The second measure addresses the need for a more coordinated regional approach to ensure a healthy investment portfolio of different renewable power generation technologies and investment locations. The results of the Impact Assessment shows that these measure would result in reduced energy system costs ranging from €1.0 billion (partial opening) and €1.3 billion (mandatory regional schemes) annually for the period 2021-2030, and renewable energy support costs paid by the consumer are reduced by 3% and 5% respectively.

The third measure proposes a renewables-focused financial instrument to address the high costs of capital for investments in renewable power. The risk is that overall investments may be insufficient to meet the 2020 and 2030 targets, a sub-optimal medium- and long-term deployment at EU-level, and a lack of exploitation of the renewable energy potential of countries with a higher cost of capital. Two different financial instruments have been assessed. A financial instrument that reduces the cost of capital in a number of Member States and regions will reduce energy system costs by €1.5 billion and achieves a more balanced deployment of renewables across the EU. A financial instrument that addresses only high risk projects would result in an increase of energy system costs, but could lead to technological breakthroughs in technologies like offshore wind and tidal.

The fourth measure addresses the varying administrative costs between Member States, which can account for around 15% of the overall development costs of wind projects. Administrative barriers bring uncertainty and delay to investors, artificially increase the costs of renewable energy projects, create distortions in the allocation of investments within the EU, and therefore hamper building a single integrated market for renewable energy and reaching a cost-effective deployment.

Building on the existing provisions on administrative procedures in the 2009 RES Directive, regulations and codes and on the TEN-E Regulation, the Impact Assessment proposes additional options to address the remaining obstacles including the introduction of a one-stop-shop and a time range for permitting procedures and facilitated procedures for repowering.

6.2    Improve energy performance and energy security with renewables in the heating and cooling sector

Heating and cooling represents the largest energy sector in the EU, consisting of around half of the European energy demand. It is made up of 75% fossil fuel and accounts for 68% of the EU's gas imports. There are currently limited heating and cooling measures across the sector in EU legislation 15 , leading to slow progress, an absence of a long-term policy vision and investor uncertainty. On top of this situation, the negative externalities of the fossil fuel use in the heating and cooling sector 16 are not internalised and reflected in the energy prices for most parts of the heating and cooling sector, which hinders market uptake of highly efficient renewable energy technologies.

While the share of renewable energy in electricity has increased by more than 8 percentage points between 2009 and 2015, the share of renewables in the heating and cooling sector has only expanded by less than 3 percentage points in the same period 17 . The EU Strategy for Heating and Cooling also highlights the important impact of renewables deployment in district heating and cooling systems to reduce the costs and increase the flexibility of the EU energy system 18 .

The findings of the Impact Assessment and proposed policy options

In the absence of additional and coordinated policies, the current slow rate of progress in Member States is incompatible with a cost-effective achievement of the EU renewable energy target by 2030 19 and long-term decarbonisation goals 20 . Given its large share in total energy consumption, measures intended to increase renewables use in the heating and cooling sector are crucial for the EU to meet its renewable target in a cost-effective manner.

The impact assessment has evaluated a number of measures – consistent with the enhanced EED - to improve the renewables deployment in the heating and cooling sector as well as in district heating and cooling systems.

For the heating and cooling supply, an obligation on all fuel suppliers 21 is considered to increase the amount of renewable energy that they supply. This should enable the cost-effective deployment of renewables in heating and cooling at EU-level, and reduce investor uncertainty. Two design variants are compared:

A gradual increase in the obligation every year, or

The obligation to reach a certain share of renewables by 2030

Given the fact that the heating and cooling sectors are very diverse across the EU, Member States would be allowed to have significant flexibility to design the obligation (e.g. choice of obligated parties, the possibility to exempt SMEs from the scheme).

The promotion of efficient and renewable district heating and cooling aims to address the market uptake of renewables, empower the citizens and reinforces the provisions above by:

Making it possible for renewables suppliers to access of district heating and cooling networks through energy performance certification; and

Facilitating consumers' choice of high performance energy supplies (be it centralized or decentralized).

These options introduce an obligation to allow open access rights to infrastructure for RES and waste heat and cold, an obligation to certify the district heating system performance using an existing standard 22 , and the right for consumers to pursue higher efficiency by disconnecting from the district grid. The Impact Assessment shows that if the renewable supply increases in existing district heating and cooling systems by 20% roughly, an additional 2 Mtoe renewable heating and cooling could be delivered by 2030. The risk of disconnection is deemed limited at the EU level, but could vary depending on the Member State. Both options result in new compliance costs linked to the certification which could not be quantified, but are estimated to be minimal if streamlined with the new provisions in the Energy Efficiency Directive.

6.3    Renewable fuels in the transport sector

Transport consumes a third of EU's total energy demand and it is almost entirely dependent on oil. While the transition to low-emission alternative energy in transport has already begun, spurred by the current Renewable Energy Directive, the sector is significantly lagging behind the other sectors. There is high potential for increasing renewable energy use in transport through electrification and development of advanced renewable fuels. It is also an opportunity for Europe to develop leadership in new bio-based products, such as advanced biofuels.

The work on the Impact Assessment has been developed in full consistency with the European Strategy for Low-Emission Mobility. This strategy already indicated that the Commission was examining how to provide a strong incentive to innovate in energies needed for the long-term transport decarbonisation by, for example, introducing an obligation for fuel suppliers to provide a certain share of renewable alternative energy.

The findings of the Impact Assessment and proposed policy options

Modelling-based analysis shows that, under the EU Reference Scenario 2016, the deployment of alternative fuels (including renewable fuels) in transport will slow down. It will be insufficient for achieving the 2030 climate and energy target and contributing to the EU's long-term decarbonisation goals. The main reasons for this under-performance include, amongst other: the high dependence of the sector on liquid fossil fuels, lack of economic viability of alternative fuels, the variable GHG emission performance of biofuels and specific barriers in aviation, waterborne (inland waterways and maritime) and heavy duty vehicles.

Against this background, this Impact Assessment analyses four policy options to promote innovation and significant market uptake of alternative and renewable fuels in the transport sector, including different paths to phase out food-based biofuels. These options include:

EU incorporation obligation for renewable fuels, under the revised Renewable Energy Directive;

EU incorporation obligation for renewable fuels, plus an EU-wide cap on the use of food-based biofuels. Two types of caps are analysed: a full phase out of food-based biofuels by 2030 or, alternatively, a phase down to pre-2008 levels. An additional sub-option consists of a faster phasing out of seed crop-based biodiesel and an increase in the direct greenhouse gas saving threshold of 70% for new installations;

GHG emission reduction obligation, under the Fuel Quality Directive 23 .

The impact assessment indicates that, under the same decarbonisation ambition, a complete phase out of food-based biofuels by 2030 would require higher shares of advanced biofuels. This outcome would increase annual investment costs by over 60% compared to a gradual phase out scenario. This cost increase would be partially offset by lowered feedstock costs.

Furthermore, a complete phase out of food-based biofuels by 2030 would lead to job losses in the production facilities, and related industries such as crushing plants and refineries. This would occur particularly in the biodiesel sector where there are lower synergies between conventional and advanced biofuel production technologies. In addition, rape seed production could decline substantially. On the other hand, employment would increase in the production of advanced biofuels and fuels of non-biological origin, including technology development and use of feedstocks such as wastes, energy crops and lignocellulosic material. The net impact of the biofuels options is uncertain.

The analysis also shows that emissions from indirect land use change (ILUC) can be significantly reduced through a gradual phase out of conventional biofuels by 2030, focusing primarily on oil-crop based that are associated with higher ILUC impacts, combined with a higher greenhouse gas emission saving threshold for new biofuel installations.

The assessment finds that an EU-wide incorporation obligation would have the advantage of building on the extensive policy and administrative experience developed by Member States in implementing the Renewable Energy Directive and their national renewable fuel mandates. Furthermore, administrative burden for economic operators would be minimised, as they would continue to use mainly default values.

6.4    Empowering and informing consumers

The Energy Union Strategy places the consumer at its centre. Consumers should have the possibility to sell, consume and store self-generated energy. At the same time consumers should be informed about the energy they buy, as some might wish to purchase renewable energy and are prepared to pay a premium for such energy suppliers. Consumer empowerment could help mobilise additional private capital for investments in renewable energy sources.

However, in the absence of a European framework, Member States have addressed renewable energy self-consumption individually. This situation has led to differing degrees of consumer empowerment, unstable legal frameworks, and few incentives for citizens to invest in renewable energy sources when self-consumption is not facilitated. Equally, consumers wishing to be informed about the energy they buy must be absolutely certain that the renewable energy products are trustworthy. This requires an effective tracking system.

The findings of the Impact Assessment and proposed policy options

In line with the vision on consumers presented in the Energy Union strategy, two sets of measures have been proposed to empower consumers.

Regarding self-consumption three possible options are put forward:

EU guidance on self-consumption

Framework principles empowering consumers to self-consume and store renewable electricity

Distance self-consumption for municipalities

The Impact Assessment finds that the option of including framework principles empowering consumers could drive PV deployment, increase the share of self-consumed electricity and might create 10 000 to 20 000 additional jobs in roof-top solar by 2030 compared to the baseline scenario. An EU guidance is unlikely to have a strong impact, whilst allowing for distance self-consumption 24 could have a negative impact on grid financing.

Regarding consumer information, the proposed measures aim at strengthening and extending the existing "guarantees of origin" (GO) system. Although GOs covered 45 % of all renewable electricity generated in the EU in 2015, the majority of power generation is outside of the system. Furthermore, Member States have implemented the GO system in widely differing ways 25 , which increased the risk of double counting of renewable electricity.

For the electricity sector, the GO system could become the only means for disclosure of renewable electricity consumption to consumers. Furthermore, the GO system could be extended to renewable liquid and renewable gaseous fuels used in the heating and cooling and transport sectors. Such a system could be built on the existing sustainability requirements for biofuels. In addition to providing information to consumers, it would also facilitate cross border trade.

6.5    Making sure the EU will be on track on its ambitions by 2030

The new EU-wide binding target for 2030 set by the European Council in October 2014, is to increase the share of renewable energy consumed in the EU to at least 27% by 2030. In the absence of binding national targets for renewable energy post-2020, one main challenge is how to achieve this target in a cost-effective way through EU, regional and national level actions. This would need to take into account differing national capacities to produce renewable energy, whilst building on the renewable shares achieved in 2020.

In this context, Member States' Integrated National Energy and Climate Plans, to be developed as part of the initiative on Energy Union Governance, will play an important role, as they will include contributions to the EU-level 2030 target for renewable energy. Furthermore, the Energy Union Governance initiative aims, inter alia, via an iterative process with Member States, at addressing in first instance the possibility that contributions do not add up to the binding EU target (by means of recommendations on National Plans). However, the Governance process anticipates that further incentives for target achievement would be included in the Renewable Energy Directive should a gap in the target remain despite of the iterative process.

There are four overarching concerns that may warrant the need for additional and specific mechanisms to be included in the revised Renewable Energy Directive:

-How to ensure that – in line with the European Council conclusions of October 2014 – 2020 target are fully met?

-How to ensure a continued project pipeline from 2021 onwards – the year after the end of the binding 2020 requirement – to restore and maintain investor certainty?

-How to incentivise Member States to contribute appropriately and cost-effectively to the EU level binding target?

-How to ensure that Member States deliver on their contributions?

The findings of the Impact Assessment and proposed policy options

The first measure proposes the 2020 national targets as a mandatory floor for the period 2021 to 2030, providing certainty to investors and creating a virtuous circle of higher levels of investments. This measure would need to be reflected in the requirements for the Integrated National Energy and Climate Plans set out under the Energy Union Governance, and requires a continuation of the existing co-operation mechanisms.

A number of EU trajectories have been examined to ensure a continued project pipeline between 2021 and 2030. The assessment suggests that there are sufficient mature technologies available to warrant a linear uptake of renewables over the 2020-2030 timeframe. This would result in a more consistent stream of investments, bring forward investments that have the opportunity to reduce the levelised cost of electricity, and has a positive impact on greenhouse gas emission reductions.

To avoid an "ambition gap", the proposed options include the iterative process under the Energy Union Governance, a review clause of the legislation to propose additional measures at a later stage, EU wide measures to ensure target achievement included in sectorial legislation, or other measures. The impacts of the options may vary depending on the size and the reason for the gap. The three considerations assessed are the impact of the options on investment certainty, the administrative burden and the political feasibility.

The "delivery gap" can be addressed with the same options considered for the "ambition gap". The key difference is that progress reporting under the Energy Union Governance will be a crucial element to detect delivery gaps at an early stage, that the options for the "delivery gap" and the "ambition gap" are consistent, and any corrective measure can be introduced effectively and without time delays to ensure investor certainty.

7.    Overview of measures and linkage to identified problems

The Impact Assessment considers measures that can respond to one or more of the specific problems that prevent achievement of the overarching objectives of greenhouse gas emissions reduction, energy security, internal market, and global leadership.

As a conclusion, the table below presents a summary of the main measures considered in the impact assessment and their linkage to the identified problems.

Table 1: Overview of measures and linkage to the identified problems

1.Introduction

1.1.Background and scope of the initiative

The Renewable Energy Directive 26 (the "RES Directive") establishes a European framework for the promotion of renewable energy and constitutes the most relevant measure to deliver on the EU's mandate to promote the development of new and renewable form of energy as set out in Article 194 TFEU. It has been the main driver for European investment in renewable technologies at a domestic level, economies of scale and innovation driving down significantly the related costs 27 . It has also had a spill-over effect worldwide, triggering the adoption of renewable energy policies outside the European Union 28 and helping renewables towards becoming a cost-competitive energy source.

The RES Directive establishes, inter alia, national mandatory targets for the share of renewables in final energy consumption for each Member State. It also includes biennial indicative trajectories, as partial milestones to ensure that actual developments are not lagging behind in view of the achievement of the 2020 targets. A holistic approach is ensured by covering the three sectors: electricity, heating and cooling and transport, but the split of the national target and trajectories between the sectors is left to the discretion of the Member States (apart from a separate mandatory 10% sub-target for the 2020 share of renewable energy in the transport sector).

Figure 2: Based on 2016 Interim Progress Report - Oeko-Institute

With an estimated renewable energy share of 17% of gross final energy consumption in 2015 36 , if the effort continues, the EU and an overwhelming majority of Member States are expected to achieve the 2020 targets set in the RES Directive 37 . More specifically, in the electricity sector (RES-E), 30% of the EU's power was estimated to be generated from renewables in 2015, with 11% of the total EU electricity sourced from variable renewable electricity 38 . In the heating and cooling sector (RES-H&C), the renewables share is estimated to reach 18,5% in 2015 39 . However, in the transport sector (RES-T), with a renewables share of 6,2% in 2015, the EU and the majority of Member States are still estimated at half-way towards the 10% target for 2020 40 .

Figure 3: based on ESTAT Shares 2014

Some provisions of the RES Directive effectively end in December 2020, notably on national binding targets.

Finally the electricity sector is at this stage at an important crossroad with the Emission Trading System being reformed to address the surplus in allowances, the electricity market (including rules on generation adequacy) being redesigned and the new Energy Union Governance to be set up. The renewables electricity sector is also still recovering from abrupt, sometimes retroactive, changes that occurred in the aftermaths of the financial crisis and the biofuels sector need clarity on the post 2020 policies for biofuels. Re-establishing regulatory certainty for renewables producers and investors is therefore paramount at this point in time where the EU is falling behind global competitors in terms of absolute investments. There is equally a need to clarify the future policy on biofuels for investors in that sector.

The question this Impact Assessment aims to address is which additional measures and policies should be included in the RES Directive post-2020 to promote the necessary long-term investments that will allow for further reduction in technology costs and the achievement of the 2030 renewable energy target 41 in a timely and cost effective way.

1.2.Context of the initiative

The 2030 Framework for Climate and Energy 42 and the Energy Union Framework Strategy 43 establish the EU commitment to further reduce greenhouse gas emissions (at least 40% by 2030) in line with the cost-effective pathway described in the 2050 Roadmaps 44 , to increase the share of renewable energy consumed to at least 27%, and to save at least 27% energy by 2030 at EU level compared to 2007 baseline projections as quantitative headline targets of the Energy Union, in particular to increase Europe's energy security, achieve a moderation of energy demand and progress in the decarbonisation of the economy.

The Energy Union Framework Strategy stated the need, inter alia, for an integrated governance and monitoring process, to ensure that all energy-related actions at European, regional, national and local level contribute to the Energy Union's objectives and to secure the delivery of the 2030 Framework for Climate and Energy. This is also in line with the EU commitments at the COP21 Climate Summit in December 2015, which adopted the first-ever global and legally-binding climate agreement with the aim to hold the global warming well below 2°C and to pursue efforts to limit it to 1.5°C.

Integrated National Energy and Climate Plans, together with comprehensive monitoring and reporting at the EU and national levels, and an iterative political process between the Commission and Member States on the implementation of national plans will be essential elements of such a governance framework. These provisions will be reflected in the Commission's initiative on the Energy Union Governance.

In February 2014, the European Parliament called for a 40% cut in CO2 emissions, a 30% target for renewable energy and a 40% target for energy efficiency by 2030, under the EU's long-term climate-change policy 45 ..

With a view to the period beyond 2020, in October 2014 the European Council agreed on a binding EU-level target of at least a 27% share of renewable energy consumed in the EU in 2030. Furthermore, in February 2015 the Commission confirmed the political commitment for the European Union to become the world leader in renewable energy 46 .

The roadmap for delivering the Energy Union, launched in November 2015 as part of the first Report on the State of the Energy Union, foresees a new Renewable Energy Package for the period after 2020, containing a revised Renewable Energy Directive (the "Revised RES Directive"), and including a bioenergy sustainability policy for the period 2021-2030 47 .

1.3.Links with parallel initiatives, approach taken for modelling, data gaps and other limitations

1.3.1.    Links with parallel initiatives

The Commission has already tabled legislative proposals of relevance to an EU policy on renewable energy, such as the revision of the EU Emission Trading Scheme (ETS) for the period after 2020 48 , including, inter alia, a Market Stability Reserve to address the current surplus of allowances and improve the ETS resilience to major shocks by adjusting the supply of allowances to be auctioned. It also made proposals as regards setting national binding emission reduction targets for greenhouse gases (GHG) for the sectors outside the ETS (the so called "Effort Sharing Regulation") 49 and on Land Use, Land Use Change and Forestry (LULUCF) 50 . In addition, legislative initiatives are being tabled as regards the revision of the directives on energy efficiency (EED) 51 and energy performance of buildings (EPBD) 52 , and a policy communication was published on the European strategy for low-emission mobility 53 . Finally, this Impact Assessment has been prepared in parallel with the Impact Assessments accompanying the initiatives on Electricity Market Design 54 , Governance of the Energy Union 55 as well as Bioenergy Sustainability 56 . In relation to the latter, sustainability issues associated to bioenergy, particularly in heating/cooling and electricity, are specifically dealt with in that impact assessment. This Impact Assessment addresses only issues related to the climate performance of biofuels, and in particular indirect land use change impacts of conventional food-based biofuels which are not captured by the sustainability criteria.

As regards electricity in particular, the failures causing an inefficient integration of renewables in electricity markets are analysed in Chapter 2 as they are closely related to renewable electricity deployment. However, for sake of completeness, it should be stressed that policy options related to (i) the priority dispatch and priority access to the grid of electricity produced from renewable sources, (ii) balancing and other market responsibilities imposed on renewable electricity generators, (iii) grid connection charges and grid access tariffs applicable to renewable electricity generators as well as (iv) network planning obligations are assessed as part of the Electricity Market Design Impact Assessment. Various measures aimed at making electricity markets fit for integrating a large share of variable renewable generation, as well as facilitating the participation of renewables in all markets and all timeframes (including as regards the provision of ancillary services) are also assessed in the Market Design Impact Assessment, whereas policy options related to the promotion of renewable electricity will be assessed as part of this Impact Assessment.

For the heating and cooling sector, this Impact Assessment reflects, as appropriate, the Commission's intentions included in its EU Strategy on Heating and Cooling, notably with regard to promoting renewable energy through a comprehensive approach to speed up the replacement of obsolete boilers, including by encouraging the uptake of renewable energy in heat production and increasing the deployment of renewable energy in district heating and combined heat and power generation (CHPs), as well as supporting planning for renewable energy deployment at local level also taking into account the need to reduce emissions of air pollutants such as Particulate Matters (PM) and Nitrogen Dioxide (NO²). In this respect, some relevant measures are included in the Commission's proposal for the revision of the Energy Performance of Buildings Directive (EPBD) and the Energy Efficiency Directive (EED) and assessed in the impact assessments supporting these initiatives 57 .

For the transport sector, this Impact Assessment builds on the work carried out in the Staff Working Document accompanying the Commission's communication on a European strategy for low-emission mobility and additionally takes into account the reduction of the carbon intensity of transport fuels in the framework of the Fuel Quality Directive (FQD) 58 . Furthermore it focuses on the sustainability issues of biofuels, particularly the GHG emissions.

The absence of binding national renewable energy targets as a policy tool in a post-2020 timeframe requires the exploration of other policy avenues to ensure an adequate ambition and distribution of Member States' efforts to contribute to the EU-level target of at least 27% renewable energy in 2030. The legislative initiative on the Governance of the Energy Union aims to contribute to addressing this issue together with the revision of the RES Directive. The general approach is that governance provides the framework for planning, reporting and monitoring the development of renewable energy, whilst corrective measures if required would be part of the RES Directive, which is a simple approach applied with other aspects of climate and energy policy such as the Effort Sharing Regulation and the Energy Efficiency Directive. The interaction between the governance process and the RES Directive and the specific issues to be addressed are further explained in Chapters 2 and 5 59 .

1.3.2.    Approach taken for modelling and limitations

Annex 4 describes in detail the models used for the quantitative analysis presented in this IA, as well as the scenario descriptions. It also presents the interactions in the modelling work undertaken for this Impact Assessment and for the other related Impact Assessments on the 2016 Energy Union initiatives.

The problem definition and the policy options assessed in this Impact Assessment build on the outcomes of energy-system modelling scenarios. More specifically, the starting point for this Impact Assessment, as for all other related Impact Assessments, is the EU Reference Scenario 2016 ("REF2016"), which provides 2030 energy-system projections, based on current trends and policies 60 .

This Impact Assessment makes also use of a central policy scenario also used for the Impact Assessments supporting the proposal for a revision of the Energy Efficiency Directive (as a baseline scenario) and for the proposal on the Effort Sharing Regulation, as well as in the Staff Working Document published together with the EU Strategy on low-emission mobility (as one of the two central policy scenarios - in both initiatives), which are in line with 2030 minimum ambition levels as stated by Heads of States and Governments in October 2014. This scenario (called "EUCO27") projects the expected developments across sectors to reach the 2030 targets and help identify the scale of the economic, social and environmental challenges to cost-effectively reach an at least 27% renewable energy share. The second policy scenario (called "EUCO30" as its only difference from EUCO27 is a more ambitious energy efficiency target of 30%) is also used in analysis of transport sector options.

Building on the REF2016 and the EUCO27 scenario, specific baseline scenarios are then prepared, which highlight the expected implications of the continuation of current policies and practices on the developments in the specific sectors subject to policy interventions, assuming that all other sectors and policies are in line with the central policy scenario.

This approach, building on a common policy scenario and then focusing on 'one issue at a time', was deemed the only operational way to assess the impacts of specific policy options in the general context of various far-reaching initiatives put forward by the Commission as part of the 2016 Energy Union initiatives.

However, this approach has some limitations. First, assumptions have to be made about what the continuation of current practices mean in each sector. Second, the implications of a failure in one sector to deliver on agreed policies or targets on other policies or sectors cannot be directly modelled. Finally, since some of the policy options presented in this Impact Assessment cannot be properly addressed in an integrated energy system model, the analysis is complemented by other modelling or analytical tools and qualitative assessment when necessary, as further elaborated in the document.

2.What is the Problem and why is it a Problem?

2.1.Evolution of the problem and need to act post-2020

The EU and the world are moving towards a more sustainable and renewable energy system. Addressing concerns about greenhouse gas emissions, local air pollution 61 , cost-competitiveness, and security of energy supply are among the main reasons for this global shift.

The Lisbon Treaty enshrined in the treaties of the European Union that "Union policy on energy shall aim, in a spirit of solidarity between Member States, to […] promote […] the development of new and renewable forms of energy" 62 . In this context, the European Council in October 2014 set a binding EU-level target of at least 27% for the share of renewable energy consumed in the EU in 2030. It also invited the European Commission to further examine instruments and measures capable of reducing emissions and dependency on energy imports in the transport sector, including measures for the promotion of energy from renewable energy sources. Taking action to curb energy use and boost renewables in the heating and cooling sector would reduce EU energy costs, help cut the EU's dependence on imported fossil fuels 63 and reduce carbon dioxide emissions, especially if highly efficient heating and cooling systems replace old ones, together with district heating deployment 64 .

REF2016 projects a greenhouse gas reduction of 35% in 2030 compared to 1990 and a renewable energy share by 2030 of 24.3% in 2030 65 . Although this scenario does not assume any additional dedicated renewables policies, the combination of long-lasting effects of current policies, improved cost-competitiveness associated with technological progress, and the continuation of the ETS 66 , lead to an increase in renewables share even post-2020. However, this increase still falls short of the minimum share of renewables agreed, and more generally highlights the potential risk of not reaching the 2030 EU climate and energy objectives, in the absence of additional policies.

The initiatives on the ETS and non-ETS sectors, Electricity Market Design, Governance and Energy Efficiency are expected to contribute to increasing the level of renewables as a share of final energy consumed in 2030. They will also facilitate the integration of renewable energy in relevant markets, and provide economic signals for the uptake of renewable energy in line with the EU's climate and energy objectives, in the context of an improved internal energy market.

However, such initiatives cannot address the full range of specific issues that hamper the needed expansion of renewable energy in all sectors to ensure achievement of the 2030 renewables' target in the most cost-effective, proportionate and least distortive way for the ultimate benefit of the European taxpayers and energy actors, notably the consumers. Moreover, they will not suffice to provide clear signals to Member States, investors, and citizens and address President Juncker's ambition for the European Union to become "the world number one in renewables" 67 .

Against this background, this Impact Assessment identifies the following five problem areas:

2.2.The problem areas and underlying main drivers

2.2.1.    Problem 1 - Investor uncertainty 

Investor certainty will be crucial for attracting the significant private investments needed to reach the at least 27% EU-level target. For the EU, these are estimated around or above EUR 1 trillion from 2015 to 2030 in renewable electricity generation alone 68 . As explained above, the regulatory framework is much wider than the RES Directive only, in particular for electricity.

Driver 1: Uncertainty as to when energy-only market will provide sufficient investment signals

European electricity markets were designed in the past for conventional, centralised power plants. In most Member States, electricity systems and markets are today not fit for a large penetration of variable renewable generation. Certain subsets of the electricity market are not designed to accommodate variable renewable generation. For instance, short term markets such as intraday and balancing do not run as close to real time as necessary 69 and in many cases market rules do not facilitate, or even impede, the integration of renewables (e.g. definition of market products). Existing rules create significant barriers to market entry, especially for new and/or small market entrants (in particular variable generation) and create a non-level playing field in favour of larger incumbents. Furthermore, system service markets are often not designed in a way that allow the participation of variable renewables, nor value and monetise the system services that distributed resources can bring. Secondly, energy systems as a whole lack the required flexibility crucial for the cost-efficient deployment of variable renewables sources. The further cost-efficient penetration of variable renewables depends on a sufficient and timely deployment of all sources of system flexibility, such as interconnectors, demand response, storage, flexible plants, electrical vehicle charging, and power-to-heat or to other energy carriers. System flexibility is crucial in limiting the renewables market value gap – by reducing the occurrence of both low/negative prices when renewables are dispatching and of high prices when renewables are not dispatching – and ensuring that adding variable renewable generation translates into net benefits to the system as a whole, i.e. the avoided costs minus increased costs. At the same time, it should be noted that flexibility measures also tend to suppress price spikes that could be necessary to recoup fixed costs of generating assets. These issues will be addressed in the market design Impact Assessment.

Indeed, variable renewable electricity suffers from a "cannibalisation" effect in the market based on marginal cost financing logic, creating a renewables "market value gap" 70 . Due to the merit order effect pricing mechanisms 71 , prices during hours of peak production of variable renewable sources tend to be lower than average market prices. While this effect is already visible today in certain Member States 72 , it is expected to become even more relevant as renewables penetration further increases 73 . As an order of magnitude, recent research suggests that, in the absence of hydro reservoirs and demand response, when its market share will reach 30% of total generation on a given market, the revenues that a wind plant can get through the market could fall to only 50% to 80% of the average market price. These factors may be reached by solar power when it reaches only 15% of total generation 74 . This is a market indication of the changes in market values of renewables as they are deployed. As renewables are further gaining market shares in the coming decade, the regulatory framework should not only incentivise the deployment of renewables where costs are low (e.g. due to abundant wind or solar resources), but also where the value of the produced electricity is the highest.

The Commission's ambition for the post 2020 context is that renewable electricity generators can earn an increasing fraction of their revenues from the energy markets based on an enhanced market design – where short term markets are fully developed and integrated and flexibility plays a key role in enhancing the market value of renewables – and a strengthened EU ETS.

The incentive provided by the ETS has been limited in recent years due to the large surplus of allowances on the market, resulting from the imbalance between supply and demand for allowances. A large surplus confounds the signal for investments, which are necessary for the transition towards a low-carbon economy, including energy supply. Additionally, the current behaviour of many investors on power generation markets seems to be driven by myopia looking primarily at current price levels. Overall, even though the ETS carbon price can be expected to increase as scarcity in the carbon market will resume, in the short term prevailing myopic views and the uncertainty on long term CO2 price development may remain an impediment for investors to fully factor in future prices in investment decisions.

This imbalance between supply and credit of allowances resulted from several economic and policy factors, such as the reduction in emissions following the economic crisis and the higher use of international credits than was expected. At the same time, specific support for renewables has shown to be a strong driver for investment, and, for a given CO2 cap in the ETS, a fast deployment of renewable electricity can contribute (among other factors) to a lower carbon price by weakening the demand for emission allowances in the EU ETS. In view of such potential impacts, various stakeholders have recently argued that there is a need to ensure that adjustments can be made in the ETS to address the full impact of general economic conditions as well as overlapping EU and national policies on the ETS price 75 .

The strengthened and revised EU ETS, with a functioning Market Stability Reserve (MSR), will play an increasing role in providing a stronger investment signal for lower carbon technologies including renewables, and will ensure that synergies between renewable energy and climate policies are better reaped. However, such impact will only build up gradually.

From 2019, the introduction of a MSR will respond to major changes in the demand of allowances, regardless of whether these are the result of economic factors or due to policy developments. The architecture of the reserve is such that it automatically and in a gradual manner reduces the auction supply if there is a significant oversupply of allowances. However, as the reduction realised by the MSR will be gradual, if, for any reason (including a fast deployment of renewable electricity), the existing imbalance between supply and demand would not be reduced, it might need to be considered as part of the first review of the MSR parameters foreseen by 2021 whether this justifies a change to the parameters (e.g. an increased MSR feeding rate) to preserve the overall policy coherence in delivering the climate objective in a cost effective manner, as agreed by European leaders.

The ETS will provide an increasingly stronger investment signal as the scarcity in the carbon market will gradually resume and a reformed energy only market would support the integration of renewables, but ETS may in itself not ensure that all necessary investments in renewables would occur, in particular for certain non-mature technologies.

Overall, a number of elements, normally beyond the control of renewables producers, will determine the moment when "RES parity" is achieved – i.e. the moment when the levelised cost of electricity (LCOE) decreases to the level of the actual market value of the asset to be financed. Such conditions include: (i) continued decrease in technology costs; (ii) the availability of (reasonably cheap) capital, which is a function of many variables, including project-specific and renewables framework-specific risks, but also general country risks; (iii) social acceptance (which could impact the availability of high potential locations); (iv) sufficiently high and stable fossil fuel prices.

Additionally, the "RES parity" moment will depend on the extent to which and the speed at which the market re-design and the reformed ETS deliver on: (i) addressing the current surplus of carbon allowances that would strengthen the carbon price signal; (ii) reducing the occurrence of low or negative market prices; (iii) reducing balancing costs for renewables producers; (iv) bringing additional revenues to renewables producers in balancing and ancillary services markets; (v) ensuring a timely and sufficient deployment of all sources of flexibility limiting the renewables "cannibalisation effect"; (vi) any electricity over-capacity effectively exiting the market; (vii) renewables market integration not translating in a substantial upward pressure on renewables projects' access to and cost of capital.

Until these conditions are in place, a funding gap for investments in renewables will remain, as evidenced by both the Market Design and this Impact Assessment, and is dependent also on future price expectations that may be uncertain. This is the starting point of the this Impact Assessment, which then will consider the best way of addressing investment uncertainty against this funding gap.

Driver 2: Uncertainty over the post-2020 policy framework for support schemes

Investors, Member States and other stakeholders have called on various occasions for clarity to be provided in the revision of the RES Directive on the future framework for support schemes after 2020 by spelling out framework principles on support schemes that facilitate a Europeanised and market based approach to renewables 76 .

The RES Directive allows Member States to opt for support schemes to facilitate renewables deployment and target achievement, but leaves the choice of support scheme design entirely to Member States, reflecting the consensus at time of adoption that there was no one-size-fits-all system. State aid rules set out general requirements until 2020, but for instance do not contain any principles on the design of tenders (apart from the technology-neutrality principle), nor on cross-border co-operation. They also leave an element of regulatory uncertainty as assessment is done on a case-by-case basis after a state aid scheme has been put in place.

Support for renewable energy may conflict with system-friendly and market-responsive dispatch, investment decisions and technological designs – in particular through insufficient exposure to market price signals that, together with an adequate definition of bidding zones, reflects the value of generation to the system depending on time and location. The type and level of support needed to promote emergent technologies representing a small share of the power generation mix, such as what was required to promote initial deployments of wind onshore and solar PV in the second half of the last decade, is not justified anymore when such technologies become much more mature and deployment reaches a significant scale. This is all the more true in view of the negative impact this might have on market functioning and investment incentives across power generation markets, including downward pressure on ETS prices.

Retroactive changes and retrospective moratoria on renewable-related support have taken place in several Member States 77 . These changes took place for several different reasons but often led to uneven fees and subsidies distribution, loss of confidence in the sector, sometimes even bankruptcies and employment losses. This insecurity in the renewables sector and the lack of access to finance for new renewables installations may similarly not only endanger achievement of the binding 2020 national renewable energy target of the respective Member State and the overall renewables target of the EU, but make it more expensive. These measures also resulted in numerous lawsuits at national, European and international level 78 .

Several Member States were able to negotiate with investors a deal which diminished the amount of support provided in exchange for regulatory stability, while other Member States made changes that eventually led to a complete stop of any new investment in renewables on their territory, due to the uncertainty they created.

Rules on renewables support finally have to consider the type and nature of all categories of investors.

Currently, most renewables communities remain small-scale, either in terms of numbers of projects, members, turnover or capacity installed. This leads to specific issues, such as difficulties to face grid connection costs, especially for non-shallow costs 83 . In addition, some specific elements of support schemes design such as tendering support might create some barriers to the development of community-owned energy, and therefore reduce local acceptance of projects 84 . There is even a downwards tendency in the share of community-owned renewable energy in the system, mostly due to competitive tendering process where community schemes have difficulties in competing on equal footing with other projects 85 .

This has been confirmed by the results of the public consultation where 31% of respondents agreed upon the fact that support schemes, levies and/or administrative procedures should be adapted to the size of local projects and access to finance facilitated to enable cooperatives to compete on equal footing with other projects in the market. This analysis was mostly shared by cooperatives (91%), NGOs (69%) and public authorities (43%).

Driver 3: Uncertainty around individual Member States' contributions to the EU level renewables target and future governance

Whilst currently national targets provide a clear indication on each Member State's development, it is unclear how the collective effort for post 2020 will be shared among Member States. The absence of binding national renewable energy targets as a policy tool in a post-2020 timeframe requires the exploration of other policy avenues to ensure an adequate ambition and distribution of Member States' efforts to contribute to the EU-level target of at least 27% renewable energy in 2030. Also detailed rules for the governance set up between the EU and Member States and monitoring are still being defined (the latter in the parallel Governance IA).

The general approach is that governance provides the framework for planning and monitoring the development of renewable energy, whilst corrective measures if required would be part of the Revised RES Directive, which is a simple approach applied with other aspects of climate and energy policy such as the Effort Sharing Regulation and the Energy Efficiency Directive. The interaction between the governance process and the Revised RES Directive and the specific issues to be addressed are further explained in Chapter 5.

Driver 4: Uncertainty regarding the sustainability rules applying to biofuels, including the role of food-based biofuels post-2020

As both the REFIT evaluation and the public consultation demonstrates, the policy discussion on Indirect Land Use Change (ILUC) associated to food-based biofuels and the prolonged adoption process of the ILUC Directive have negatively affected investments in biofuels, including in advanced biofuels. There is now a need to provide regulatory certainty and predictability concerning the role of food-based and advanced biofuels in general and, specifically, regarding the sustainability rules applying to bioenergy post-2020, including the role of conventional biofuels (see more below).

Regarding the sustainability rules, there is a need to improve the sustainability criteria and the traceability rules in order to improve their effectiveness. In this respect, the European Court of Auditors found in an audit 86  that the way biofuel sustainability is currently verified entails weaknesses for instance regarding the supervision of voluntary certification schemes. The competences of the Commission and the Member States in this area are not set out clearly in current legislation. Furthermore, some provisions of the sustainability scheme and the traceability rules have proven to be difficult to implement and may need to be improved in a view to facilitate their implementation.

Driver 5: Uncertainty regarding actions in the heating and cooling sector

Even if the situation is quite homogenous at EU-level, with 18 Member States having heating and cooling shares representing more than 40% of total energy, there is currently an absence of promotion of heating and cooling measures across the sector in EU legislation, contrary to electricity and transport. In the absence of additional and coordinated policies, the current slow rate of progress in Member States is incompatible with a cost-effective achievement of the EU renewable energy target by 2030 87 and long-term decarbonisation goals 88 .

From the analysis of the public consultation, lack of integrated energy strategy and planning at the national and local level, lack of targeted financing and lack of supportive policies for decentralised energy, self-consumption and thermal storage in buildings and district systems are perceived as the three most important barriers to renewables expansion in the heating and cooling sector (respectively, mentioned in 84%, 80% and 74% of the public consultation replies).

2.2.2.    Problem 2 - Need to improve cost-effectiveness of deployment of renewable energy

The importance of a transition towards fully-market based and self-eliminating support of renewables has already been addressed in the previous chapter. In addition to that, there remain substantial benefits to be reaped by adapting the way in which renewables are currently deployed in the EU.

Driver 1: Projected contribution of heating and cooling and transport sector not in line with cost-effective decarbonisation path

Renewable technologies are being deployed across the three sectors - electricity, heating and cooling, and transport. Over the past decade, a lot of emphasis was put on the development of reneable electricity, possibly driven inter alia by the parallel efforts to open up EU's electricity markets. The 2030 and 2050 decarbonisations scenarios require however also accelerated reneables deployment in heating and cooling, and transport.

Heating & cooling

In the REF2016, renewable heating and cooling shares fall 2.3% points short of what would be needed for an overall cost effective path to 2030. Heating and cooling currently represents the most important single energy sector in the EU, with around half of the European energy demand. As explained in Section 2.2.1, there is currently an absence of promotion of heating and cooling measures across the sector in EU legislation, contrary to electricity and transport.

Therefore, while the share of renewable energy in electricity has increased by more than 8 percentage points (pp) between 2009 and 2015, the share of renewables in the heating and cooling sector has only expanded by less than 3 pp in the same period 89 . In the absence of additional and coordinated policies, the current slow rate of progress in Member States is incompatible with a cost-effective achievement of the EU renewable energy target by 2030 90 and long-term decarbonisation goals 91 . In the absence of additional policies in heating and cooling, there might also be a risk that the entire burden would be transferred to the electricity and the transport sectors, which might jeopardize the cost-effective achievement of our 2030 target.

Transport

Energy efficiency, electrification and the use of renewable energy in transports have all been identified as important elements in order to contribute towards the reduction of the EU oil import dependency and of transport decarbonisation in a cost-effective manner 92 . Modelling looking at options to achieve the 2030 climate and energy targets 93 indicates the share of biofuels in transports is projected to increase up to 7.8% 94 of total transport energy demand by 2030 (from 3.7% in 2010). Beyond 2030, modelling suggests the share of biofuels in liquid and gaseous transport fuels will need to increase significantly further, reaching around 46% by 2050 (equal to 36-37% of total transport energy demand). This also requires substitution of food-based biofuels by advanced biofuels with low effects on indirect land use change (ILUC) emissions. In particular, advanced biofuels are required to decarbonize the heavy duty, waterborne transport and aviation sectors that cannot be electrified with current technologies 95 .

Respective contributions from the various sectors 

As described under the EUCO27 scenario 96 , the challenge for the renewable energy sector is to increase the share of renewables in all the RES-E, RES H&C and RES-T sectors, compared to 2020 levels. Compared to projected developments under the REF2016, the increased use of renewables in the electricity sector would be substantial contribution to the overall increase in renewables. Contributions from the heating and cooling and transport sectors would also be necessary in absolute terms, and are will have to take place in the context of significant reductions in final consumption in these sectors, mainly driven by improved energy efficiency. These reductions imply that increases in RES-H&C and RES-T shares will not only come from additional assets (as is partly the case for RES-E), but also from replacement of incumbent technologies that will be pushed out of their respective markets through a mix of demand reduction and fuel-switching.

In terms of evolution of energy consumption (Mtoe), this shows that: i) it is in the electricity sector that renewables consumption is projected to increase the most in absolute terms; ii) in the heating and cooling and transport sectors, in the context of an overall significant decrease in final consumption, an increase in renewables is still needed in absolute terms to reach the at least 27% target; iii) in the transport sector, the evolution presented in the table below also reflects the formula used to measure renewable energy consumption in transport, including double counting for renewable electricity for instance.

Source: PRIMES

To conclude, this short descriptive analysis confirms that all renewable energy sectors are expected to contribute to the increased use of renewables by 2030, but in a differentiated manner, as this contribution is also influenced by the projected evolution of final energy demand.

Driver 2: RES-E support not fully responsive to different technology potential and maturity

Renewable technologies and potentials vary significantly. Ignoring these differences - e.g. by applying a strict technology-neutral approach - might result in either underinvestment or overcompensation.

Certain long-established (e.g. biomass co-firing) or fast-growing (e.g. onshore wind, solar photovoltaic) renewable electricity technologies have now reached a considerable share of market thanks to the inductive regulatory framework. They may be considered as technologically mature according to certain metrics, for instance being broadly commercially available and their share of total installed capacity 97 . It might however be sub-optimal for other reasons such as the energy system as a whole or land use concerns to only have these technologies as the winning tender.

Other renewable technologies, like offshore wind and concentrated solar power, are increasing their market share, or are still in an earlier stage of the innovation chain, like tidal stream energy, ocean wave energy, deep geothermal, highly performing advanced PV and building-integrated PV. The same applies to most technologies capable of storing electric power. As these technologies have the potential, in a medium- to long-term perspective, to largely contribute to a decarbonised, secure and cost-efficient energy system, the combination of public support (in line with the priorities identified in the SET Plan and coordinated with the Member States' support) and private support is geared towards bridging the cost gap and pushing further technological and system innovation in Europe. The new renewable support framework will need to ensure that less mature technologies can continue their path towards market integration without abrupt stops.

Driver 3: RES-E support not fully responsive to different potentials across Member States/regions

There are clear benefits to be reaped from a more regional approach to renewables support.

Energy systems, and electricity systems in particular, were historically built on a national or even sub-national basis. From an infrastructure point of view, this has translated into limited interconnections between, or within, Member States. Insufficient transmission grid capacities limit the flexibility of energy systems, and hinder further renewable penetration. From an institutional and political point of view, this is one of the reasons that have contributed to policies supporting renewables being largely developed on a national basis. Financial support for renewable generation, in particular, has taken the form of national support schemes. This has led to a situation where renewables are deployed where support is the strongest and the most secure, rather than where the most cost-effective potential from an EU perspective is available. What is more, the fragmentation of markets leads to higher transaction costs, as developers and investors have to apply substantially different models for investments across Europe and build the related capacity.

The cooperation mechanisms introduced by the RES Directive allowed Member States to agree on cross-border support of renewables and to take advantage of another country’s more cost-efficient potentials in renewables and achieve efficiency gains in view of their renewable energy targets. However, Member States have so far not engaged in joint support schemes with the exception of Norway and Sweden. This is due to a number of reasons ranging from administrative complexities (regarded as important or very important by 74% of respondents in the public consultation 98 ) to political considerations, such as Member State reluctance to see their taxpayers money used for investments outside their country (94% - by far the most important consideration mentioned in the RES Directive public consultation 99 ). In particular, it is especially difficult to ask consumers to support renewables deployment in a different country when they do not see a direct benefit out of it.

The opportunity given by the RES Directive of sharing the effort of the renewable energy targets more cost-effectively was, therefore, as of the time of this Impact Assessment, not yet utilised, despite ongoing negotiations between several Member States 100 and declared intentions to finalise these negotiations in 2016 and 2017.

However, a number of Member States are in the process of partially opening up their support schemes to cross-border participation 101 . Within the context of a reformed market design, a more interconnected and integrated electricity market, all of which are important components for the further deployment of renewables, the renewables policy framework should facilitate a more cost-effective deployment of renewable electricity across the EU. This process of regionalisation of renewable policy is further underpinned by the political dialogue of Member States at regional level through, inter alia, the High Level Groups such as BEMIP and North Seas.

Driver 4: Differences in cost of capital, national approaches to grid connection fees and administrative procedures undermine optimal RES-E allocation across EU

There are significant benefits to be reaped from reducing national differences with regard to rules beyond support schemes affecting overall project cost, in the case of renewables mainly cost of capital, grid connection fees and administrative procedures. These differences can effectively undermine joint support schemes as was shown for the example of the NO-SE joint scheme in the evaluation. Addressing them for renewables specifically could be justified given the technologies' capital-intensity and linked higher risk premiums.

Cost of capital

Renewable electricity technologies face a number of factors that may make it hard for them to attract sufficient and affordable funding from investors, including but not limited to: capital intensity, resource risk, real or perceived technology risk, under-recognition of the long-term value of reducing variable fuel cost exposure. In the absence of perfect foresight (leading to myopic requirements for short term returns) and/or the presence of poor or asymmetric information or understanding (leading to overestimation of risks), renewables typically only have access to scarcer and/or more expensive capital than more conventional energy technologies. Such failures can apply to both large-scale and small-scale investors (e.g. households).

Additionally, in the post-2020 context with high shares of renewables and deeper market integration, renewables should be increasingly integrated into the market and face obligations similar to those of conventional generators. This entails additional costs and risks for renewables investors (balancing costs, market price volatility), as these costs have so far been transferred to other entities, which translate into higher cost of capital, higher LCOE for the individual investor, and higher renewables deployment costs – all elements to be taken into account when assessing the benefits of better market functioning 102 .

Only in a limited number of Member States some of the most mature renewables technologies have today access to capital at a cost that is comparable to that of more conventional technologies, although investments conditions for fossil fuel power plants have also been affected by higher operating costs and combined effect of low carbon and low wholesale electricity prices 103 . Funding remains limited and/or costly for mature technologies in many Member States as well as for a number of less-mature technologies. As way of illustration, recent research 104 estimated that the weighted average cost of capital (WACC) of a typical onshore wind project varied in 2015 from 3.5% to 12% depending on Member States 105 . Given the capital-intensity of most renewable technologies, a higher WACC significantly increases the overall cost of a given renewable project.

Figure 5: Diacore

Additionally, it should be noted that significant variations in the level of WACC across Europe may hamper the deployment of renewables in the EU where the economic potential is otherwise the highest. A mere 1% WACC difference can increase the total cost of the project by 5%.

Finance also typically remains scarce for the fragmented, smaller-scale renewable projects, which face high transaction costs relative to the amount of funding required – in addition to often facing split incentives between tenants and owners.

The estimation of the required amount of capital expenditure in RES-E capacity to reach European targets varies a lot depending on the source and scope of the research 106 . For instance, Bloomberg New Energy Finance estimates investments in new renewables electricity generation capacity to amount to USD 1.0 trillion over 2015 to 2030 (around EUR 57 billion per year) 107 , while the World Energy Investment Outlook concludes that roughly USD 1.2 trillion is required in the EU between 2014 and 2035 (around EUR 52 billion per year) 108 .

Currently, there are no EU-level facilities dedicated to providing debt or equity financing to renewables generation projects only. The EU budget is supporting certain demonstration projects of new technologies under the Secure, Clean and Efficient Energy Challenge of Horizon 2020 109 . European Structural and Investment Funds (ESIF) have a strong focus on low-carbon investments in the 2014-2020 period, including support for renewable energy projects and related research and innovation, which can take the form of grants or financial instruments (e.g. loans, guarantees or equity). Additionally, the NER300, funded through the sale of 300 million emission allowances from the ETS, is a funding programme for the development of innovative low carbon energy demonstration projects, including innovative RES technologies in the EU 110 . For the period after 2020, an Innovation Fund would be set up through the sale of 450 million emission allowances that could fund innovative RES projects 111 . The EU is also indirectly investing in renewable generation projects via facilities such as the Marguerite Fund and the European Energy Efficiency Fund. Finally, the European Investment Bank (EIB) is providing debt and equity for renewable energy generation and grid projects, across all Member States – and the European Fund for Strategic Investments (EFSI) is providing the EIB with additional risk-bearing capacity 112 .

Public support in the form of debt or equity support is mostly taking place at national or sub-national level. Some Member States have developed specific renewables financing programmes, often through their National Promotional Banks (NPBs)..

Existing funds such as the Marguerite Fund and the European Energy Efficiency Fund currently have their investment strategy defined not only by the EU, but also by their other sponsors (national public banks or private investors). EIB's renewables investments are driven by the EIB's sectorial strategies and credit policies. As for the EFSI guarantee, while renewable projects have to date represented a large share of total EFSI funding, its use is governed by the overall economic recovery-focused objectives of the EFSI; importantly, the EFSI is currently not foreseen to exist post-2020.

Costs related to administrative procedures

Administrative costs vary between Member States but non-economic barriers can be costly. They currently account for around 15% of the overall development costs of wind projects in the Member State analysed 113 . Administrative barriers 114 bring uncertainty and delay to investors, artificially increase the costs of renewable energy projects, create distortions in the allocation of investments within the EU, and therefore hamper building a single integrated market for renewable energy and reaching a cost-effective deployment. Given that the Revised RES Directive will not feature binding national targets but only a binding European target, enablers for a cost-effective deployment of renewables also at national level become more relevant.

Article 13 of RES Directive mandates streamlining, expediting and coordinating administrative procedures but more progress in the EU needs to be made. There is overwhelming support for a further reduction of administrative barriers among stakeholders. 79 % of respondents to the public consultation who expressed an opinion on the issue identified the creation of a one stop shop as the centrepiece of this simplification and 85% are in favour of fixed time limits. The REFIT Evaluation of the RES Directive found that depending on the Member State, region or technology, issuing of renewables permits can take from less than 5 weeks in one Member State to 7 years in other Member States 115  

Additionally, the current Article 13 of the RES Directive does not take into account the repowering of existing projects, which will become of key importance in the next decade, especially for wind power. As 76 GW of today’s 142GW installed capacity will need repowering between 2020 and 2030, repowering can offer a cost-effective solution and its facilitation could be sensible.

On the other hand, stakeholders' responses to the public consultation and the REFIT evaluations of both the RES Directive and the energy acquis emphasised the positive role played by the national plans for ensuring investment certainty and target achievement and the administrative cost reduction achieved by having a binding uniform template for renewables planning.

Differences in grid connection charges

Other costs applicable to renewables generators, in particular grid connection fees, may lead to investment distortions. Some Member States apply a "deep" model, where the renewables generator bears the costs of grid connection, grid reinforcement and extension. Other Member States apply a "shallow" model, where the generator only bears the costs of grid connection, while grid reinforcement and extension are built into the grid tariffs (and thus paid in the end by customers). Such differences have an impact on the costs of the projects and increase the distortion in allocation of investments across the EU. This issue will be addressed in the market design Impact Assessment.

2.2.3.    Problem 3 - Absence of functioning markets 

Well-functioning internal energy markets are crucial for the deployment of renewables. However, markets in the electricity, transport and heating and cooling sectors are at different phases and require different measures to ensure their functioning.

In the case of the electricity sector, where renewables are expected to reach around 50% market penetration, the market is being redesigned to support the integration of renewables. In the heating and cooling market, the challenge is to ensure access and sufficient incentives for the expansion of renewables. In some of the segments of the transport sector, new markets for renewable fuels have to be created.

Heat markets are inherently local, but across the EU are not fully functional due to the following main drivers.

Driver 1: External costs of competing technologies not properly internalised

Heating & cooling

The negative externalities of the fossil fuel use in the heating and cooling sector 116 are not internalised and reflected in the energy prices for most parts of the heating and cooling sector, which hinders market uptake of highly efficient renewable energy technologies at centralised (district heating) and decentralised (building) level. When the vast majority of individual heating is based on fossil-fuel solutions, out of which more than 40% on gas only, renewable alternatives are not able to compete on equal footing with existing solutions, which often leads to technology lock-in at individual level. The market, as currently designed, does not provide sufficient incentives for fuel-switching and therefore hampers the fulfilment of the objectives above.

Transport

Road transport sector is not covered by the EU Emission Trading Scheme. The Energy Taxation Directive stipulates minimum rates for excise duties for unleaded petrol of €359 per 1000 litres and €330 per 1000 litres for diesel (gasoil) used in transport. Excise duty rates differ between Member States 117 . In 2011, the European Commission proposed a revision of the Energy Taxation Directive, which distinguished a CO2-related component and an energy-related component in the excise duty. Applying this principle would have implied a minimum rate on diesel of €390 if the minimum rate on petrol would have been €359 per 1000 litres, in addition Member States would have been asked to mirror the Commission's minima in their national rates. The analysis accompanying this Commission proposal showed that CO2-based taxation drives consumption away from fossil energy sources. However, in 2015 the European Commission decided to withdraw its proposed revision of the Energy Taxation Directive, given that the draft compromise text was de facto void of all constituting elements of the original Commission proposal. This shows the difficulties in moving forward on relatedissues which require unanimity in the European Council.

Driver 2: Transition towards renewables can in many occasions only be done at sector/system level

Heating & cooling

The lack of an EU-wide strategy has led to very fragmented local markets, where consumers have difficulties in making choices based on their preferences and lack of regulatory policies creating incentives for decentralised energy, self-consumption and thermal storage in buildings and district systems.

At EU-level, natural gas with a share of 45% is by far the most important heating fuel. Other energy carriers are relatively equally distributed: electricity with 12%, heating fuel oil with 12%, biomass with 12%, coal with 9% and district heating with 8%. Less important are ambient heat and waste non-renewables with about 1% and solar energy, waste renewables and geothermal energy, all with below 1%.

The picture is a lot more diverse when looking at the heating fuel mix at Member State level (see Figure 6). Member States are sorted according to their total final energy demand for heating and cooling, starting with the largest consumer on the left, i.e. Germany. Natural gas is the major energy carrier in many Member States, reaching up to 68% in the United Kingdom, 66% in the Netherlands and 59% in Hungary. Countries with a natural gas share of below 5% are Finland, Sweden (and Norway and Iceland), plus Malta and Cyprus. Poland has an exceptionally high share of coal with 38%, followed by Slovakia (20%) and the Czech Republic (17%). On the other side, in 24 out of 31 countries the share of coal is below 10%.

Figure 6: Final energy demand for heating and cooling
in the EU28+3 countries by energy carrier in 2012 [TWh] 118

While natural gas suppliers are mostly large-scale and concentrated 119 , the European heating oil market is predominantly supplied by around 12,500 small and medium-sized enterprises 120 , the coal market being even more heterogeneous 121 . About 10,000 district heating systems were operating across the EU-28 for district heating in 2015 122 . However, since several district heating suppliers run more than one system, the total number of district heating systems represents the upper limit of suppliers in the EU 123 .

An EU intervention in this sector might help create an integrated EU market for renewables in heating and cooling, especially for gas suppliers that represent more than 40% of the total supply.

Transport

Aviation and maritime sectors pose particular challenge as with current state of technology only biokerosene and biomethane are a viable decarbonisation pathway. These two sectors contribute an increasing share to the total transport emissions over time, going up from 19 to 23% during 1990-2014. Direct emissions from aviation account for about 3% of the EU’s total greenhouse gas emissions. Furthermore, international aviation and shipping are the transport sectors where emissions of air pollutants have actually experienced the strongest increase since 1990 (except for SOx and PM from shipping). Since the start of 2012, emissions from all flights from, to and within the European Economic Area (EEA) have been included in the EU Emissions Trading System. These emissions form part of the EU's internal 20% and 40% greenhouse gas (GHG) emission reduction targets for 2020 and 2030 respectively.

The development of alternative and renewable fuels for these two sectors has been hampered by the a) lack of commercial viability of such fossil fuel alternative; coupled with b) over-supply of fossil fuel-powered shipping and aviation in recent years and the related depressed investment market. In aviation, the traditional fuel is a hydrocarbon, almost exclusively obtained from the kerosene fraction of crude oil. Fuel specifications for aviation fuels are also very stringent. In this context, advanced liquid biofuels appear to be the only low carbon option for substituting kerosene, as they have high specific energy content. However, advanced biofuels are today significantly more expensive to produce compared to the cost of kerosene today. An additional challenge in the maritime sector is given by the existence of split incentives between ship owners and operators resulting in limited motivation for deployment of clean energy solutions in this sector.

Driver 3: No incentives for district heating systems to become more efficient and no access rights to the infrastructure for new entrants (including RES)

District heating currently provides around 10% of the EU's heating, with natural gas (40%) and coal (29%) being the main fuels used for district heating, followed by 16% of biomass 124 . However, the share might be substantially higher for single Member States, as illustrated in figure 7.

Figure 7: District Heating and renewables in the EU 125

The EU Strategy for Heating and Cooling clearly identifies the cost reduction potential for the EU energy system, by improving the performance of district heating and cooling systems. According to Fraunhofer ISI et al. (2016), 53% of the total capacity of CHP plants exceeding 1 MWth was installed before 1992; while 26% was installed between 1992-2002; and 21% after 2002. The older district heating and cooling systems must evolve to accommodate the increase of renewable energy supply.

District heating and cooling have also the potential to contribute to balancing the electricity grid. According to Eurostat in 2013, about 72% of district heating and cooling systems were fuelled by combined heat and power plants, which means that most of heating and cooling systems are linked with the electricity network. Measures such as targeted urban planning and integrated heat mapping, which facilitate the move towards an integrated energy system approach and local heat markets, received wide support (88% of stakeholders in the public consultation 126 ).

Neither the current RES Directive nor the EED directly empowers consumers to prompt district heating or cooling systems to improve their efficiency and/or increase the use of renewable energies. There is currently also no access for new entrants (including renewables) to the infrastructure in several Member States.

2.2.4.    Problem 4 - Need to update the regulatory framework 

Driver 1: Current RES Directive built on national targets and to be adjusted to ensure collective RES target attainment

Current legal provisions and monitoring set up were developed for an EU instrument underpinned by national binding targets not in order to equip the Commission with the best tools for facilitating most cost-effective collective attainment.

The European Council concluded that the European Union needs to achieve at least a 27% share of renewable energy sources and that it will be based on an EU level binding target as opposed to the existing EU and national binding targets in the current framework.

In the absence of binding national targets for renewable energy post-2020, one main challenge is how the at least 27% share in 2030 will be delivered in a cost-effective way through EU, regional and national level actions, taking into account differing national capacities to produce renewable energy, whilst building on the renewable shares achieved in 2020.

In this context, Member States' Integrated National Energy and Climate Plans, to be developed as part of the initiative on Energy Union Governance, will play an important role, as they will include national contributions to the EU-level 2030 target for renewable energy. This part will be addressed by the parallel initiative on Energy Union Governance. However certainty for all Member States the other Member States also deliver with their post cost effective potential can be further enhanced.

Despite the approach taken under the Governance process, an ambition gap might emerge if Member States' collective contributions eventually fell short of the at least 27% target. This is a special issue requiring consideration given the fact that the target is binding at EU level. A similar issue arises in the case of a delivery gap, which would occur if the Member States do not manage to meet their planned national trajectories. The issue of ambition and delivery gaps do not arise under the current legislation that foresees national binding targets. Therefore there is no mechanism in place to avoid such gaps happening. The Energy Union Governance initiative aims, inter alia, via an iterative dialogue with Member States, at addressing those issues. However, there is a question on whether additional and specific mechanisms should also be included in the revised RES Directive to complement this work by providing a backstop and to make sure that the target is delivered in a timely manner. Such mechanisms should be key to ensure investors certainty as regards a continued project pipeline and also by providing Member States with the right incentives to contribute appropriately to the EU level binding target.

A specific issue in this overall context concerns the fact that, in the absence of an adequate legal framework, Member States may decide to reduce their efforts to encourage renewable energy from 2021, the year after the end of the binding 2020 requirements. This could jeopardise the collective achievement of the 2030 EU renewable energy target and it also disincentives the use of cooperation mechanisms in the form of projects rather than statistical transfer to meet the 2020 targets. It could also be in contradiction with the European Council conclusions of October 2014 which reconfirmed that the 2020 targets needed to be fully met.

Another question concerns the potential trajectory of efforts to be considered between 2020 and 2030. The RES Directive contains an accelerating, non-linear, trajectory for each Member State and at EU-level for achievement of the 2020 national targets. This implies that greater amounts of renewables need to be produced in the years close to the targets' year, relative to the early years. An accelerating trajectory at EU-level is appropriate in an era where renewable technology is fast developing and significant cost reductions can be anticipated over time. From 2021 to 2030, many renewables technologies will be mature with much smaller potential for significant cost reduction 127 potentially requiring a different approach to define the trajectory.

The options under consideration aim to create together a comprehensive framework for achieving the EU wide at least 27% renewable energy target. A framework that is transparent and which provides positive incentives for Member States to further develop renewables. It seeks to do this in a way that does not involve mandatory national targets for Member States.

Driver 2: Lack of specific RES-transport target post-2020 and uncertainty regarding future demand for alternative fuels (including renewable fuels)

The REFIT evaluation on the RES Directive and the public consultation highlighted that the uncertainty about the policy framework for renewables in transport after 2020 is a significant barrier for future investments in renewable fuels, particularly in capital intensive advanced biofuels. Without a clear and predictable EU policy framework, the required economies of scale and technology learning effects needed to bring technology costs down while ensuring robust GHG savings are unlikely to materialize within the next 15 years.

Key advanced biofuel technologies such as lignocellulose ethanol, synthetic Bio DME, Bio-Methane and pyrolysis oils are ready to be deployed at commercial scale (see box below). The EU has been investing significant funds in research and development of these innovative technologies through Horizon 2020 programme, and its predecessor the 7th Framework Programme for Research and Innovation. This has been complemented by national R&D programmes and private research performed by traditional fuel suppliers and new market entrants. As a result, in 2015 the EU accounted for 9% of global installed capacity of advanced biofuels (130.83 million litres). Current production plants of advanced biofuels are located in Finland, Germany, Italy, Sweden and the Netherlands. This capacity has to develop further and timely for transport to contribute to 2030 targets and 2050 decarbonisation objectives. Timely development at a right scale will enable to lower the costs in the long term.

Box 1: Advanced biofuels – state of play

Biofuels and biomethane are the main option for transport decarbonisation but other alternative energies have also role to play. Electrification of transports is, today, mainly taking place in non-road transport, most notably in rail transport. Due to recent technology improvements in batteries, the limited range of battery electric vehicles (BEV) is becoming today less of a constraint to their use. Also a minimum infrastructure coverage is to be provided under Directive 2014/94/EU, and some Member States have ambitious national strategies for the deployment of electric vehicles and dedicated infrastructure for the coming years. However, several barriers need to be addressed in order to enable widespread electrification of road transport, including improvements in battery costs, Vehicle-to-Grid communication, payment issues and broader integration of electric vehicles within the electricity grid.

The use of hydrogen in transport is today almost negligible. Major car manufacturers have announced that fuel cell propelled cars are to be produced at commercial scale in the future and few models are already available now. However, their high price and the lack of availability of refuelling infrastructure are representing major barriers for the widespread use of hydrogen in transport. It should be noted that a minimum infrastructure provision is optional under Directive 2014/94/EU, and some Member States have national strategies for the deployment of hydrogen infrastructure for the coming years. Hydrogen is currently projected to grow significantly beyond 2030 albeit maintaining a limited share of transport fuels.

Driver 3: Variable climate performance of conventional biofuels (due to ILUC)

Conventional biofuels have been promoted to both increase the EU energy security and contribute to reduce GHG emissions in transport compared to fossil fuels. According to the EU biofuels sustainability criteria (laid down both in the RES Directive and the Fuel Quality Directive), existing biofuel plants need to reduce direct GHG emissions by at least 35% and new by at least 50% compared to fossil fuels. While these criteria address only direct emissions from cultivation, transport and processing, in recent years, research has shown that, due to market mediated effects, food based biofuels can also lead to significant Indirect Land Use Change (ILUC) emissions that can off-set their direct GHG savings (see table below).

In particular the increase in demand for crops for biofuels can contribute indirectly to growing pressure on forests and other carbon-rich ecosystems, and therefore increase emissions from land use change. Such emissions are mostly expected to take place in third countries, where the additional production is likely to be realised at the lowest cost. The GLOBIOM study 130 carried out for the Commission has indicated that ILUC emissions can be expected to be much higher for biofuels produced from vegetable oils compared to biofuels produced from starch or sugar. This is due to the specific characteristics of global vegetable oil markets, which are highly integrated. As result increasing demand for vegetable oils in Europe for biofuel production can lead to increased palm oil imports and, therefore, in an extension of palm oil plantations in South-East Asia. Typically, these developments take place on organic soils, which can result in a significant release of GHG emissions. On the contrary, research has pointed out that advanced biofuels from non-food crops have generally very low or no ILUC emissions.

Table 2: ILUC emissions from GTAP 131 , MIRAGE 132 , GLOBIOM 133

To mitigate this issue, the ILUC Directive 134 has introduced a cap of 7% on the contribution of food-based biofuels towards transport energy consumption, and Member States have the ability to apply this cap to their FQD targets. Member States are also required to set out by 6 April 2017 an indicative target for advanced biofuels, with a reference value of 0.5% of transport energy consumption in 2020 135 . In addition, the ILUC Directive aims at promoting the use of other, non-ILUC renewable energy options in transport, such as biofuels not based on food crops, and renewable electricity.

The ILUC Directive also introduced the concept of "low indirect land-use change-risk biofuels and bioliquids". The idea behind this concept is that ILUC risks of conventional food-based biofuels can be avoided if measures are taken that compensate for the increase in demand for crops e.g. by applying measures that increase crop yields through improved inputs and management practices or by expanding agriculture on previously non-agricultural land with low carbon stocks and low biodiversity value. In a recent study from Ecofys a methodology for certification of low indirect land-use change-risk biofuels was developed 136 . The practical implementation of this concept, however, is still largely untested and uncertainty concerning the related costs and the robustness of approach remain. Therefore, the approach cannot be considered as a viable solution at this stage but the further exploration of the concept for instance by voluntary certification schemes could be encouraged.

In its July 2016 Low-emission mobility strategy, the Commissions reaffirms that that food-based biofuels have a limited role in decarbonising the transport sector and should be gradually phased out and replaced by low emission alternative energy, including advanced biofuels. Research suggests that advanced biofuels can lead to significant direct GHG savings of 76-95% 137 compared to fossil fuels and are not associated with significant ILUC risks 138 . Modelling work that underpins the strategy shows significant role of advanced bio-fuels, especially in achieving 2050 decarbonisation targets.

The production of biofuels from non-land using feedstocks in the EU is increasing, the majority of which is produced from used cooking oil or waste animal fat. The share of food crop-based biofuels in the EU market is decreasing. However, the biofuel industry argues that double-counting provisions have so far only assisted the deployment of inexpensive conversion of used oils and waste fats.

Furthermore, it should be recalled that the REFIT evaluation on the RES Directive and the public consultation results highlighted that regulatory uncertainty remains problematic for many stakeholders in the transport sector. In fact, the main barrier to investment in the sector as identified by industry, investors, associations and other stakeholders was the uncertainty about the policy framework for biofuels after 2020 and the long-led debate before adopting Directive (EU) 2015/1513 (ILUC Directive).

2.2.5.    Problem 5 - Lack of citizen-buy in during transition 

Driver 1: Risk that small scale investors are disadvantaged in market-based renewables support (tendering) and thus result in lower public acceptance

If renewable energy benefits from an overall positive opinion by most European consumers 139 , some specific renewable energy projects face strong opposition at local level. In Wallonia for instance, in 2014, 37 wind projects, representing 215 wind mills and 592MW 140 were challenged by opponents 141 . In Denmark, there are more than 200 local groups opposing wind power 142 . In France, around one third of wind projects are brought to the court, creating lengthy procedure (between 6 and 8 years) and increasing costs of development 143 .

This lack of public acceptance therefore leads to an untapped use of the most cost-efficient renewable potential (both in terms of locations and feedstocks), creates lengthy and uncertain procedures, increases overall cost and hinders access to cheap capital. Among the factors influencing local acceptance of renewables, lack of access to project ownership or finance, lack of information and lack of participation for local communities (including municipalities) have been identified as key issues 144 .

In several Member States, the creation of energy communities has been a solution to enhance social acceptance of renewable technologies at local level 145 and diminished opposition 146 . In Germany, a case study has shown that, in the absence of local participation, negative opinions towards additional wind energy could reach 60%, while this share would drop to 12% in case of the presence of energy communities 147 .

Reinforcing local acceptance, e.g. through the promotion of local energy communities, is therefore a fundamental precondition for deploying renewable energies in a cost-effective way 148 .

However, even if local involvement of communities is proven to substantially increase public acceptance of renewables and often reduce costs as co-owners do not demand same returns as classic investors, their specific situation is currently not reflected in renewables support rules. Administrative barriers are particularly relevant for communities and prosumers, who often lack the critical mass and knowledge to overcome them. In addition, such actors may have difficulties integrating in the market or participating in competitive bidding processes, especially for energy cooperatives and small-scale projects 149 .

Driver 2: Lack of consumer empowerment in the energy transition

Self-consumption of renewable electricity is expected to be the main driver for the uptake of roof-top PV. With decreasing feed-in tariffs, around 50 % of the roof-top PV capacity could be driven by self-consumption.

Renewable energy self-consumption, mostly driven by the deployment of residential solar PV, and to a lesser extent small wind power systems, has become an important trend since the implementation of the RES Directive. With an 80% drop in PV module prices in five years 150 , the installed residential PV capacity has quadrupled since 2009 in the EU 151 and it is expected to continue to increase thanks inter alia to further reductions in technology costs. As a result, businesses and households, either individually or collectively in apartment blocks, could be able to produce and consume, some or all of, their own electricity, either instantaneously or in a deferred manner through decentralised storage. Passive consumers are therefore becoming active 'prosumers' (i.e. producers and consumers of renewable energy).

Member States have addressed this phenomenon in different ways which has led to a fragmented market, different degrees of consumer empowerment across the Union and a high degree of regulatory instability. In particular, nine Member States do not yet have a legal framework for self-consumption 152 . In 8 Member States the regulatory framework was established within the last three years 153 ; and 7 changed their rules at least once since 2013 154 , in certain cases retroactively. This situation led high regulatory uncertainty among investors across the EU 155 and generates market fragmentation across the EU. In some Member States consumers are effectively not able to self-consume their own renewable electricity and it is often difficult or impossible for tenants to benefit from self-consumption. In addition, retroactive changes in regulatory and financial schemes for prosumers have led to an unreliable investment climate. This has a negative impact on the deployment of renewables at local level and its contribution to target achievement, especially because with lowering feed-in tariffs self-consumption is expected to drive 50 % of rooftop solar capacity 156 .

Driver 3: Lack of clear, comparable and credible information to energy customers

Renewable energy sources are subject to significant information failures: new technologies that are applied at plant and household level (e.g. solar water heating, heat pumps) can be slow to find public acceptance, and the market for installation and maintenance services is often inadequately informed and trained, resulting in technology breakdowns and a perception of unreliable technologies. In the case of biomass, users are often unaware of how to operate the heater in such a way that emissions of air pollutants are minimised.

The poor information flows can also occur during production, when energy suppliers are unaware of quality standards, regulators fail to create the right legal or institutional framework (e.g. municipal planning rules), and capital markets fail to acknowledge technology learning and reductions in risk. Such failures can also result in poor supply chain development.

Under Article 15 of the RES Directive, the Guarantees of Origin (GO) system provides a means of demonstrating the origin of renewable electricity to consumers. It is a virtual "book and claim" system where the renewable attribute of energy trades separately from the physical energy. With electricity such certification systems are desirable as it is not possible to track electrons from renewable sources through the power grid. Disconnecting GOs from the physical flow of electricity is a less complicated approach than tracking the supply of renewable electricity through contract based tracking and allows for trade in large volumes of renewables across the EU. The GO system is not intended to be a support scheme for encouraging new renewable generation capacity or be used as a means of achieving national renewable energy targets.

Requirements for energy companies to disclose sources of electricity, and the associated emissions and waste to consumers are contained in the existing Electricity Market Directive. Consumer bills have to include that information. However it is not mandatory in the Electricity Market Directive for energy suppliers to use the GO system for renewable energy disclosure purposes. This has led to the GO system covering less than half of the total renewable energy production. Furthermore, the GO system does not currently include data on emissions and waste.

Many electricity suppliers offer "green" contracts to consumers offering environmental benefits relative to regular electricity. When these tariffs are based on renewable energy, sometimes the renewable content is demonstrated by purchasing GOs. Corporate consumers often source renewable electricity to meet corporate sustainability objectives. This can be through direct investment in renewable electricity production, but many are increasingly focused on using such GO systems for corporate reporting purposes and to quantify their GHG emissions 157 .

Evidence so far suggests that the GO and disclosure systems in place are not consistent between all Member States as the legislation provides wide discretion as to how national systems are designed and implemented 158 . Furthermore, GOs do not apply to all energy sources only to renewable energy and high efficiency CHP 159 . There have been mixed views as to the functioning of the GO systems amongst stakeholders. Many support the system in principle, but some consider that the system can result in greenwashing 160 , as it enables consumers to use renewable electricity far away from where it is produced. For example, there is a large trade in hydropower GOs from Norway to other parts of Europe which is seen by some as unrealistic given the distances involved. Many Norwegian consumers have typically not bought GOs to demonstrate use of renewable power. As a consequence of this, there is an effective transfer of renewables consumption in that it results in Norwegian consumers having a residual mix of fossil and nuclear power which is not popular locally 161 .

With the GO system there is also a risk of double counting the production of renewables in the absence of reliable tracking systems and concerns that a poorly designed and implemented system could be susceptible to such issues 162 . This risk arises as in theory, it is possible that Member States could issue GOs for renewables under the RES Directive, but then may not require their use for disclosure purposes under the Electricity Market Directive, allowing other methods to be used. This could mean that the GOs generated are exported to another country, whilst the energy supplier is still able to claim use of that same volume of renewables under the national disclosure system.

Given some of the issues associated with the GO system, one approach could be to abolish the system entirely. Such a deregulation would mean that there would be no EU mechanism for recognising the renewable origin of electricity. In such circumstances it is likely that energy companies would continue to offer green tariffs, based on renewables, to consumers. Similarly, some businesses and corporations would still like to demonstrate publically that they consume renewables in their operations. The consequence is that parallel systems would likely develop as a way of tracing consumption of renewable energy. These could be a series of national GO system, or perhaps greater use of bilateral contracts between consumers and generators. It is possible that these systems would have no common standards and would not operate very effectively across borders; it is therefore hard to see benefits for taking such an approach in increasingly integrated energy markets.

In most Member States the GO system applies for renewable electricity only. Austria and Sweden have extended the system to all sources of power generation, including nuclear and fossil sources. Some observers have noted that the narrow scope of the system as provided by EU legislation means that the cost of disclosure is put on renewable generators only, many of which are small installations. Other less sustainable forms of electricity production, often large installations, do not participate in the energy disclosure system and therefore do not share its associated overhead cost.

The current system of GOs applies only to renewable electricity. There is no equivalent EU wide system for guaranteeing the origin of renewable gaseous fuels (in particular, biomethane) that are injected into the natural gas grid, although the case is similar to electricity.

The lack of a robust tracking mechanism could be an obstacle for cross border trade of renewable gaseous fuels. Levels of trade should increase over time as European gas grids become more integrated and production of biomethane rises or if injection of renewable hydrogen becomes common. Challenges have been encountered so far with regard to cross border trade, in the implementation of the sustainability scheme for biofuels, which has proved to be complex for injected renewable gaseous fuels. This is because the rules for the mass balance system that is currently applied to ensure traceability of biofuels were developed primarily for liquids biofuels, leaving a degree of uncertainty regarding the implementation for gaseous fuels.

In some Member States systems that are similar to GOs have been developed for gaseous fuels partly as private initiatives. There are also initiatives to facilitate cross-border trade of biomethane by mutually recognising each other's national GO systems. A number of stakeholders are also developing an EU wide approach to design a GO scheme for green hydrogen 163 .

Liquid renewable fuels are also not covered by the GO system or a similar centralised tracking system 164 . Private initiatives have also developed systems for guaranteeing the origin of liquid fuels, however they are not widely used as they are not mandatory.

The need to have in place resilient tracking mechanisms for liquid renewable fuels can be considered to increase in the future, since volumes used are likely to increase in the future. For liquid fuels the main problem is an increasing risk of fraud. There is a political agreement that the focus of the development of renewable transport fuels should shift towards non-food biofuels with a low impact on indirect land use change (ILUC) and food security 165 . However, advanced renewable fuels are initially expected to be more expensive than conventional food based biofuels but will in most cases by physically identical. In absence of a solid mechanism that allows tracing these advanced renewable fuels it cannot be excluded that economic operators make false claims on the characteristics of renewable fuels e.g. regarding the feedstock which was used to produce the fuel.

The following problem tree summarises the identified problem areas across all sectors their main underlying drivers and consequences:

2.3.The EU dimension of the problem

As the European Union needs to achieve at least a 27% share of renewable energy sources in final energy consumption in 2030 for reasons of climate change mitigation, security of supply and competitiveness, as well as to promote the EU as a global leader in the renewables industry, this effort necessarily needs to have an EU dimension. The new framework for the post 2020 period will be based on an EU level binding target as opposed to the existing national binding targets in the current framework. This fundamental change makes the problem necessarily "European", opening new challenges and new opportunities in addressing it. And this is not only a question of ensuring a collective and timely delivery of the target but doing so cost-effectively which makes the need to address the problem at EU level even more critical.

This commitment has been re-confirmed through the EU joint submission with its Member States in the proposed contribution towards COP21 with an ambitious legally binding commitment of GHG emission reductions of at least 40% by 2030 below 1990 levels 166 .

Many provisions of the current EU framework effectively end in December 2020. The uncertainty about renewable energy market volumes post-2020 in the entire Union and the support schemes for renewables may therefore lead to commercialisation problems for new capital intensive renewables technologies where investments are marked by long lead times.

Decarbonising the economy - and particularly the energy system - is crucial for the achievement of the EU-wide GHG emission reduction targets and combating the effects of climate change and renewable energy is an essential part of this effort. Additionally, the renewable energy sector contributes to the overarching goal of the European energy policy strategy to ensure secure, affordable and sustainable energy for all EU citizens and businesses by taking full advantage of the opportunities offered by a powerful internal energy market. The development of the internal electricity market and the additional deployment of renewable energy in the power generation sector are two challenges that can only be addressed in conjunction.

2.4.Who is affected and how

The Revised RES Directive (jointly with the initiative on Governance for the Energy Union) should reflect the new character of the EU-wide renewables 2030 target and the new balance established between the overall target on the one hand, and regulatory measures to achieve the target on the other hand.

Annex 6 to this Impact Assessment elaborates in detail the impact on stakeholders 167 .

2.5.REFIT Evaluation of the RES Directive

A regulatory fitness programme (REFIT 168 ) evaluation of the RES Directive was carried out between 2014 and 2016. The results of this evaluation are submitted in a separate REFIT evaluation Staff Working Document presented together with this Impact Assessment and are used as input for the present section on the problem definition.

Annex 9 to this Impact Assessment illustrates in detail the conclusions of the evaluation.

3.Subsidiarity and the diverse situations in Member States

3.1.Legal base

Article 194 TFEU states that "Union policy on energy shall aim, in a spirit of solidarity between Member States, to […] promote […] the development of new and renewable forms of energy. […] the European Parliament and the Council, acting in accordance with the ordinary legislative procedure, shall establish the measures necessary to achieve the objectives in paragraph 1. Such measures shall be adopted after consultation of the Economic and Social Committee and the Committee of the Regions".

3.2.Necessity of EU action

EU level action is needed to ensure that Member States' contributions to the at least 27% EU level binding renewable energy target is collectively and cost-effectively met and the Union can deliver on the commitments it made at the COP21 Climate Summit in December 2015. Experience has shown that uncoordinated actions at Member State level can lead to a more limited and more expensive renewable energy sources development and the fragmentation and distortion of the internal energy market.

An EU wide European market for renewables, set in the context of a more integrated electricity market, can facilitate the balancing of the electricity system, reduce the need for back-up capacities and encourage renewables production where it economically makes most sense. Large scale investments necessitate big markets which also justify one EU wide market. A bigger market can also better encourage development of innovative products and systems.

EU level action can help ensure achievement of the at least 27% EU renewable energy target through increasing investors certainty in an EU-wide regulatory framework. It will also enhance a consistent development of EU renewable energy policy across the EU leading to a more cost-efficient renewable energy deployment and a smooth and efficient operation of the internal energy market whilst fully considering the differing capacities of the Member States to produce different forms of renewable energy. Together with the Electricity Market Design legislative proposal, this initiative should enable the further integration of renewable energy sources into the internal energy market alongside other generation technologies.

Sole action at Member States' level would likely lead to a more limited deployment of renewables and create additional costs that can be reduced through complementary EU-level action. It would also lead to more fragmentation of, and distortions in, the energy internal market and put the achievement of the EU target at risk.

As regards the electricity sector, the EU has set up a single integrated power market where main principles, rules for common problems and rules regarding cross-border aspects are being established at EU-level. It follows that rules on renewables touching upon market functioning also need to be addressed at EU level. The same rationale applies to self-consumption, as prosumers, either individually or collectively, could be able to produce and consume their own electricity reducing their energy costs and participating to the electricity markets. Since Member States have addressed self-consumption adopting divergent policies, a significant number of energy consumers in the EU currently do not enjoy clear rules on production of their own electricity and self-consumption. This undermines the empowerment and increasing involvement of European citizens, who would not be able to reap the benefits from being market players of energy markets. Moreover, lack of clear rules on self-production and self-consumption would undermine prosumers ability to contribute to the effort to achieve the 2030 EU target for renewables. This effect is significant as self-consumption is expected to be the main driver for the uptake of roof-top PV. With decreasing feed-in tariffs, around 50 % of the roof-top PV capacity could be driven by self-consumption.

Heating and cooling consumes half of EU's energy and 75% of the EU's fuel needs for heating and cooling still come from fossil fuels. As such, decarbonising the heating and cooling sector is necessary if the EU is to stay on the path of our long term decarbonisation objectives and improve security of supply. Heating and cooling consumption patterns are already directly affected by EU legislation, such as the EED or the EPBD Directives. In addition, the EU Strategy on Heating and Cooling 169 provided a framework for integrating efficient and sustainable heating and cooling into EU energy policies. This should focus the future EU and Member State action on stopping the energy leakage from buildings through a comprehensive approach to speed up the replacement of obsolete boilers with efficient and clean renewable energy heating and a commitment to increase the deployment of renewable energy in district heating and CHP. In this respect, EU-level action can trigger the necessary confidence of investors for a mass roll-out of heating and cooling technology cost-effectively.

Transport consumes a third of EU's total energy demand and this demand is almost entirely met by liquid fossil fuels. Whilst electrification seems a good way forward to replace fossil fuels for light duty vehicles, motorbikes and rail, current technology development pathways suggest that electrification on its own cannot address all the decarbonisation challenges, in particular as regards aviation, waterborne and heavy duty transport. Advanced renewable fuels will need to contribute to achieve our long term climate and energy objectives. The EU has heavily invested into research and technology development of advanced biofuels, which resulted in the operation of first-of-a-kind plants. Incentives for early commercialization can pull technologies further down the learning curve. National measures cannot guarantee market volumes that are sufficiently large to both achieve economies of scale and spoor manufacturing innovation. The introduction of a promoting measure at EU level is more likely to create such a market pull, while ensuring that the costs of technology innovation and development are sufficiently shared across European economies. A common EU action will also ensure that that the objectives of the policy (e.g. making advanced fuels cost-competitive) are achieved at least costs. An EU approach can better prevent market distortion and fragmentation, that is more likely to result from national measures.

EU-level action is also needed to remove administrative barriers 170 as these bring uncertainty and delay to investors, artificially increase the costs of renewable energy projects, create distortions in the allocation of investments within the EU, hampering to build a unified EU market for renewable projects and reaching a cost-effective deployment of renewable energy.

Member States are free to develop the renewable energy sector that corresponds best to their national situation, preferences and potential, provided they collectively reach the at least 27% target. Important national prerogatives, such as the Member State's right to determine the conditions for exploiting their energy resources, their choice between different energy sources and the general structure of their energy supply, remain untouched. The following graph illustrates the use of renewables in the different energy sectors.

Figure 8: Gross Final Renewable Energy Consumption per sector (ktoe),
based on “Renewable Energy Progress Report”, Öko Institute [to be published]

Additionally, proportionality will be ensured by striking a balance between objectives of competitiveness, security of supply and sustainability, and by considering the long term benefits beyond 2030 of the proposed course of action– and not only be based on short to medium term impacts.

The level of constraint is thus proportionate to the objective aimed at.

3.3.EU added-value

In January 2014, the European Commission presented its policy framework for climate and energy in the period from 2020 to 2030 (COM/2014/015) which complements GHG reduction policies with a powerful internal energy market, a self-standing chapter on energy security of supply and reinforced emphasis on R&D and innovation. The analysis at the time indicated that the least cost pathway to achieve greenhouse gas reduction targets in 2030 and 2050 is for the entire EU to attain a share of at least 27% of energy consumed from renewable sources in 2030, without differentiating between the electricity, transport or heating and cooling sectors.

Due to the existence of specific market failures and barriers, the impact assessment that underpinned the 2030 policy framework for climate and energy 171 pointed out to the risk of not reaching this target in a business as usual scenario, and therefore not being able to reap of the economic, social and environmental benefits of renewables. Therefore the impact assessment of the 2030 framework concluded on the benefits of a specific target be set for the deployment of renewables at EU-level in 2030.

An EU-wide energy and climate framework for renewable energy in 2030 will also contribute to steer Member States energy policies to achieve a sustainable, secure and affordable energy system for European citizens. With a predictable EU regulatory framework leading the renewables' sector towards 2030, Member States can better design national policies towards the 2020 target if EU-wide headline targets are agreed on, which ensures that renewable energy policies are coherent with other energy and climate objectives, namely the ETS, the Effort-Sharing Regulation and the EU energy efficiency target for 2030. An EU-level framework for support schemes would also provide investor certainty, which may have been impacted in the past by the stop and go policy – and sometimes retroactive measures – taken by certain Member States.

By acting at EU-level, several barriers to public and private investments (e.g. related to authorisation procedures) could be tackled, addressing the lack of coordination between various authorising bodies at national level and stimulating the administrative capacity to implement cross-border projects and support schemes.

The cost-effective deployment of renewables until 2030 can thus best be achieved by a combination of action at Member States-level and at EU-level. Uncoordinated renewables' support policies at Member State level bears the risk of increasing the cost of reaching at least 27% renewables by 2030 for the consumers, for the investors and for the system as a whole.

To sum up, EU level action is needed to ensure that the at least 27% EU-level binding renewable energy target is collectively met by Member States, and is met in the most cost-effective and least distortive manner.

4.Objectives

4.1.General objectives

Contribute to "the development of new and renewable forms of energy" as stipulated in Article 194 TFEU, having in mind the Commission's political ambition to be global leader on renewables;

contribute to the EU's climate change commitments in the context of COP 21;

contribute to the energy security ambitions set out in the Energy Union strategy;

ensure cost-effective deployment of renewables and the functioning of the internal energy market.

4.2.Specific objectives

Address investment uncertainty, along a path that takes account of medium and long term decarbonisation objectives;

ensure cost-effective deployment and market integration of renewable electricity;

ensure collective attainment of the EU-wide target for renewable energy in 2030, establishing a policy framework in coordination with the Energy Union Governance that avoids any potential gap;

clarify role of food-based biofuels post 2020;

correct heating & cooling market failures;

ensure citizen buy-in for the post-2020 period, empowering consumers to receive clear, comparable and credible consumer information on all energy sources and to self-consume the electricity they generate, while respecting the principle of cost-efficiency.

5. Policy options

The present chapter describes and assesses the policy options which have been developed to address the problem described in Chapter 2 172 .

The options are grouped according to the following areas:

electricity sector (RES-E);

heating and cooling sector (RES-H&C);

transport sector (RES-T);

empowering and informing consumers of renewable energy;

achievement of at least 27% renewable energy in 2030.

Each group of policy options is assessed in detail, with an analysis of the impacts in accordance to key indicators.

5.1.Options to increase renewable energy in the electricity sector (RES-E)

The table below summarizes the group of options that are discussed in this section.

The assessment of options is structured as follows:

A starting point: the REF2016 – lessons learned for the electricity sector

Baseline scenario: the continuation of current national Member States' policies and of currently differentiated access to capital for RES electricity projects

Options about the potential need and design of support schemes

Options about the potential geographical scope of support schemes

Options about addressing the various access to capital conditions for RES-E projects

Options aimed at reducing administrative barriers

All specific policy options are compared to the baseline scenario. Discussions on these options compared to the central policy scenario results (EUCO27) are also included. Where relevant, the implications of a 30% energy efficiency target are also presented.

Table 3: Interaction logic between scenarios and policy options

Starting point: the EU Reference Scenario 2016

Overall, REF2016 falls short of the overall ambition level in terms of renewable energy share by 2030. Still, some important lessons can be learned in terms of renewable electricity developments.

By 2020, renewables in power generation are projected to increase to 35.5% (RES-E indicator 173 ) or 37.2% of net electricity generation, of which 52% are projected to be variable renewables – wind and solar. Beyond 2020 support schemes are assumed to be phased out and further investments in renewables are more limited (reaching 43% in 2030), driven by market forces such as the ETS and the improvement in the techno-economic characteristics of the technologies.

While renewables provide growing shares in electricity generation, the contribution of variable renewables (solar, wind as well as tidal/wave in the definition used here) remains significantly lower. These variable renewables reach 19% of total generation in 2020, and 25% in 2030. Wind off-shore capacities stagnate, as in the absence of support schemes this technology is not projected to be competitive.

Wind provides the largest contribution from renewables supplying 14.4% of total net electricity generation in 2020, rising to 18% in 2030. A share of 24% of total wind generation is produced from wind off-shore capacities in 2020 (33GW installed capacity), but the share of offshore wind declines thereafter. Total wind capacities increase to 207 GW in 2020, and 255 GW in 2030, up from 86 GW in 2010. Wind onshore capacity and generation increases because of exploitation of new sites but also because of the progressive replacement of wind turbines with newer taller ones which are assumed to have higher installed capacity and higher load hours. Generation from PV contributes 4.8% in net generation by 2020. Beyond 2020, PV generation continues to increase up to 7% in 2030. PV capacity is projected to reach 137.5 GW in 2020 and 183 GW in 2030, up from 30 GW in 2010. Investment is mostly driven by support schemes in the short term and the decreasing costs of solar panels and increasing competitiveness in the long term, in particular where the potential is highest, i.e. Southern Europe. The use of biomass and waste combustion for power generation also increases over time, both in pure biomass plants (usually of relatively small size) and in co-firing applications in solid fuel plants. Biomass attains a share in fuel input in thermal power plants of 17.3% in 2020, and 22% in 2030 174 . Pure biomass/waste plant capacities (excluding co-firing) reach 51.6 GW in 2020 and 53.2GW in 2030, up from 21.7 GW in 2010. The relative contribution of hydro generation remains rather constant at 10-11% of total net generation, with small hydro slightly increasing.

The Baseline scenario: the current renewables arrangement (CRA) scenario

The first assumption that this scenario considers is that Member States continue supporting renewable electricity projects, on a national basis, with no additional provision considered in the Revised RES Directive. Potential provisions would be left entirely to the revised, post-2020 State Aid guidelines. Therefore, a continuation of nationally-based support schemes is assumed, while complying with the current State-Aid guidelines provisions. The second assumption made is that Member States support renewable electricity projects in such a way that the overall 27% RES target is achieved. The third assumption made for the preparation of this baseline scenario is that current distortions in the financing cost of renewable electricity projects across countries 175 remains in place up until 2030. Regarding other assumptions, this scenario assumes, as in the central policy scenario (EUCO27) an improved functioning of the ETS, in line with the Commission's proposal for a revised ETS for the period after 2020, as well as efficient energy market functioning 176 . In other words, this scenario differs in its design compared to the EUCO27 scenario via two main features: i/ the cost-effective incentives for renewables reflected by the use of similar RES-E values across Member States in the EUCO27 scenario is replaced by explicit, nationally-based and differentiated support schemes; and ii/ financing conditions for RES projects differ per Member State.

Under this scenario, the RES-E share reaches 49% in 2030. In terms of installed capacity, this means about 733 GW of renewables capacity installed, and 245 GW of additional installed capacity over the 2021-2030 period. In terms of investment, this corresponds to annual investment expenditures of about EUR 40 billion per year over the 2021-2030 period, higher than for the EUCO27 and EUCO30 scenarios. This can be explained by a series of factors. First, there are fewer investments in RES-E in 2020 in the baseline scenario than in EUCO27, as financing costs distortions as well as impacts of different support schemes among Member States are reflected for 2020 in the baseline scenario, as opposed to EUCO27. Therefore, a catching up effect takes place post-2020. In addition, the RES-E share in 2030 in CRA is higher than in EUCO27 177 . Finally and importantly, the RES-E generation mix changes, as continuation of differentiated nationally-based support schemes and different financing conditions lead to RES deployment that is less efficient, and therefore more costly, than in EUCO27. This scenario also implies an increase in average electricity prices, by 25% in 2030 as compared to 2010. It must also be noted that this analysis does not consider the fact that the absence of provisions on support schemes would provide less visibility to Member States and investors as to the framework applicable post-2020, with possible negative impacts on investments.

Some renewables investments can be financed without public support, while others require some. The CRA results show that 59% of renewables investments over the 2021-2025 and 51% of investments over the 2026-2030 (as measured in % of GW installed) are financed via some support covering at least a fraction of total project costs 178 .This result is influenced by the initial assumption that Member States would continue supporting RES-E projects, in line with past practices. This support is reflected in final electricity prices, as it affects the power generation mix, as well as in the renewables supporting costs component of electricity prices passed on to consumers, which is estimated at 24.9 EUR per MWh in 2030.

The use of more direct support for renewables than in EUCO27 also leads to lower ETS carbon price (EUR 38 in 2030 in CRA compared to EUR 42 under EUCO27), reducing incentives for decarbonisation within the other parts of the power sector and in other economic sectors covered by the EU ETS, such as energy intensive industry, overall leading to a more costly delivery of GHG emission reductions.

The overall average increase in annual energy system costs compared to the Reference of this scenario over the 2021-2030 is estimated at €24 billion while for the EUCO27 scenario this is only €15 billion, resulting in a significant increase in costs to achieve the overall targets.

An important element of this scenario concerns the distribution of renewables deployment across Member States and technologies. First, regarding technologies, 35% of the overall RES-E generation in 2030 comes from on-shore wind, 22% from hydro, 17% from solar, 16% from biomass and waste, and 15% from off-shore wind. About 70% of the necessary investments to reach the renewables target in this scenario are investments in wind technologies; only 18% of overall investments are in solar and 8% in biomass-waste.

Second, regarding the geographical distribution of investments, 67% of total RES-E investments are concentrated in three countries, while in the EUCO27 scenario this is only 47%, with investments being more widely and cost-effectively distributed across Member States. This ratio increases to 74% for wind investments. Conversely, the combined share of investments in the ten Member States investing least over the period is only 0.6% of total investments.

A set of policy options is then compared against this baseline.

Key results from the central policy scenario (EUCO27)

It is important to recall the main results for renewable electricity embedded in the central policy scenario, as it corresponds to a cost effective deployment of additional renewables investments, compared to REF2016.

This scenario leads to a lower share of renewable electricity in the overall mix than the baseline scenario. The contribution of on-shore wind is more important than under the baseline, while it is the opposite for offshore wind. The average electricity prices as well as electricity generation costs are also lower. In this scenario, the ETS carbon price is higher than in the baseline, indicating that sub-optimal direct support to RES investments has a negative impact on CO2 prices. This would reduce profitability for all power producers as well as limiting incentives for decarbonisation within the power sector and in other economic sectors covered by the EU ETS, such as energy intensive industry. Total average annual energy system costs over the period 2021-2030 increase in the EUCO27 scenario (central scenario) by €15 billion compared to REF2016 while the baseline (CRA) sees costs increase by €24 billion.

This scenario also leads to overall lower investments in renewable electricity projects than in baseline over the 2021-2030 period. This is partly explained by the fact that in 2020 this scenario achieves a bit less RES-E in 2020 compared to EUCO27. It is also explained by the fact that financing conditions for RES-E projects are assumed to reflect more explicit existing support schemes and associated country risks in the baseline CRA projection than in the EUCO27. RES-E investments are also much more widely and cost-effectively distributed across the EU, as the share of the top 3 Member States in overall investments only represent 47% of total investments, as opposed to 67% in the baseline. Renewables supporting costs passed on to final consumers is also lower than in baseline, while industry also benefits from lower electricity prices.

Looking now at the implications of higher energy efficiency levels, it can be seen that the implications of moving to 30% energy efficiency for the electricity sector are relatively limited. Although the overall renewable energy share in electricity increases compared to the central scenario, overall investment levels remain broadly similar in the electricity sector. It has also no major implications on the renewable electricity mix or the geographical distribution of investments.

Overall, the EUCO27 scenario offers a good benchmark when testing policy options in the electricity sector, as policy options which help moving from a baseline scenario towards the central policy scenario would help achieve a cost-effective deployment of renewable electricity.

5.1.1.    Consolidating a framework for cost-effective, and market-oriented and Europeanised support to renewable electricity to promote regulatory certainty

Option 0: Baseline - No provisions on support schemes in the revised RES Directive

The current approach would be kept, i.e. the Revised RES Directive would not include specific provisions on the design of support schemes beyond allowing the possibility for Member States to opt for having support schemes. This would be left entirely to the revised, post-2020 state aid guidelines and the 2013 Guidance (or any new guidance) for the design of renewables support schemes.

Option 1: No support for renewable electricity - investments only spurred by market mechanisms

The Directive would contain a provision effectively prohibiting any form of operating or investment aid in support of renewable electricity projects. Member States would not be able to opt for renewable support schemes in order to foster deployment of renewables electricity. Investments would only be spurred by a revised market design and a strengthened ETS framework.

Option 2: Include strengthened market-based design principles through an EU toolkit

Building on the principles expressed in the 2013 Guidance for the design of renewables support schemes, as well as the Guidelines on State aid for environmental protection and energy 2014-2020 (EEAG), the Revised RES Directive would provide for the 2021-2030 period a toolkit for the design of RES-E support schemes. The principles expressed would be without prejudice to State aid rules that apply to Member States.

Such European toolkit for market-based and cost-effective support would provide framework principles for Member States to use in designing support schemes including inter alia the possibility for Member States to use market-based support schemes, the obligation to tender support in order to achieve value for money or the technology neutrality principle for tenders unless a technology specific approach is preferable (e.g. for technology with long term potential).

It would also include provisions to enable the emergence of community-owned schemes in the electricity market and through competitive bidding processes, in order to fully exploit the untapped local potential for the deployment of additional renewable capacity. This would require the introduction of principles aiming at promoting renewable energy communities, including a definition with a minimal set of objective and subjective criteria, the empowerment to consume and produce renewable electricity, specific procedures and grid connexion, and the participation of energy communities in market-based supports schemes (e.g. tenders), including e.g. simplified administrative procedures enabling them to compete on equal footing with other generators.

Importantly, the framework would enshrine in legislation and expand the requirement to tender support; it would define tender design principles, based on emerging best practices, to ensure the highest cost-efficiency gains. The framework would thus strengthen the use of tenders as a natural phase-out mechanism for support, by which a competitive bidding process determines the remaining level of support required to bridge any financing gap – such level of support being expected to go to zero for the most mature technologies over the course of the 2021-2030 period.

Additionally, the Revised RES Directive would explicitly enshrine the principle that support schemes designed in line with EU indications cannot be revised in a way that retroactively impact the rights related to the level of support received by renewables projects, taking into due account the falling production costs and the need to avoid over-compensation or to address unforeseen technological developments.

The framework would be effective as it would define design principles (i) that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where needed) of market-based and cost-effective schemes based on emerging best practice design (including principles that are not covered by the current state aid guidelines). At the same time, the framework would be proportionate by leaving actual implementation to the state aid guidelines (e.g. for the definition of thresholds applicable for any foreseen exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment of individual schemes by the services of DG Competition.

Option 3: Mandatory move towards investment aid

In addition, the Revised RES Directive would require Member States to design support schemes in such a way that support is not linked to the amount of electricity being generated. Possible investment-based supports include (i) direct capex subsidies per MW or (ii) loan subsidy/guarantee schemes. A progressive transition could be designed, e.g. Member States would be required to provide a minimum share of renewables support in the form of investment aid by a certain date. Such support should also be conditional on the actual production of the capacity installed to avoid stranded assets.

5.1.1.1.    Introduction to the assessment

Currently, the RES Directive leaves the choice of support scheme design entirely to Member States, subject to Article 107-108 TFUE. In practice, convergence in design occurs, as Member States learnt from each other, and as support schemes need to comply with State aid rules, in particular the Guidelines on State aid for environmental protection and energy 2014-2020 179 .

The Commission's ambition for the post 2020 context is that renewable electricity generators can earn an increasing fraction of their revenues from the energy markets based on an enhanced market design – where short term markets are fully developed and integrated and flexibility plays a key role in enhancing the market value of renewables – and a strengthened EU ETS. At the same time, it has to be assessed to what extent energy and carbon market revenues alone will be sufficient to attract renewable investments at the required scale, in a timely manner.

It is established that a growing penetration of renewables, while not leading to a failure of energy-only markets as such, can aggravate underlying market conditions potentially detrimental to investment incentives, in two ways 180 . First, higher low-marginal-cost variable renewable shares lead to lower average prices (due the so-called "merit order effect"). Second, large shares of variable renewables increase price volatility, in particular leading to the more frequent occurrence of very high as well as very low or even negative prices.

Research also suggests that the behaviour of renewables in electricity markets – and thus their impact on market functioning – is determined by the kind of support they receive 181 . The degree of price exposure determines the trading behaviour of renewables generators, but also plant design and investment decisions 182 .

Additionally, empirical evidence (of past tenders) shows that the way support is allocated impacts the cost-efficiency of support. The analysis of past auctions in eight EU-countries and four non-EU countries showed that all those auctions schemes reported efficiency gains in terms of the contracted price or discounts achieved: E.g. a price of €84.9/MWh was applied in the second round of the German auction (led in 2015 on ground-mounted solar PV), which is significantly below the ceiling price of €112.9/MWh. 183 Recent auctions for offshore wind in the Netherlands and in Denmark have resulted in strike prices of, respectively, €72.7/MWh 184 and €60.0/MWh 185 – yielding significant reductions in the level of support relative to support awarded in other recent comparable projects.

Against this background, the Revised Renewables Directive could set out framework principles for the design of support schemes in the post-2020 context, laying down common principles ensuring that, when and if support is needed, such support be provided in a form that is (i) cost-effective, (ii) as little distortive as possible for the functioning of electricity markets, and (iii) fosters regional approaches through greater convergence in the design of support.

5.1.1.2.    Detailed assessment

Against this background, detailed modelling work was undertaken to assess whether renewables will be able to finance themselves in the energy-only market over the period 2021-2030, taking into account (i) the revised ETS framework, (ii) the market re-design foreseen as part of the Market Design Initiative, (iii) expected further declines in the levelised cost of energy (LCOE) of renewables technologies, and (iv) forecasts of wholesale prices. As regards the ETS framework in particular, modelling results presented in the paragraph below assume an increase of ETS linear factor to 2.2% for 2021-30 and implementation of the Market Stability Reserve. This translates into an ETS price reaching 15 EUR/t in 2020, 25 EUR/t in 2025 and 42 EUR/t in 2030 in the EUCO27 scenario, and lower prices of 15 EUR/t in 2020, 22.5 EUR/t in 2025 and 38 EUR/t in 2030 in the baseline (CRA) scenario. Results are presented in more details in Annex 4.

Under Option 1, the implications of the absence of support schemes on the viability of investments in RES-E generation are tested 186 . First, it can be recalled that the EU Reference Scenario 2016 models, inter alia, renewables developments post-2020 in absence of dedicated support schemes for new projects. Under this scenario, RES-E developments are below the ones necessary to reach the overall at least 27% target by 2030. However, REF2016 does not reflect the potential impacts that reformed electricity markets, or a reformed ETS including the Commission proposal on a revised linear reduction factor, could have on renewables developments. It also does not consider additional energy efficiency policies needed to achieve 27% energy savings.

As opposed to REF2016, the EUCO27 scenario was constructed with a cost-effective achievement of the 2030 climate and energy targets in mind. This scenario suggests that under the right framework conditions, in particular a reformed ETS, good electricity market functioning, a cost effective set of energy efficiency policies, and equal financing conditions across the EU, it is possible for the majority of renewables investments to develop such that they effectively contribute to the overall achievement of the renewables target. Least cost options are selected, and all costs are recuperated. However, some support is still needed, reflected in the model by the use of RES-E values, which corresponds to a set of unspecified cost-effective incentives promoting investments in renewable electricity projects.

This scenario demonstrates that little support would be needed, and that renewable technologies may be competitive, under the right framework conditions.

It should additionally be noted that the PRIMES model simulates emission reductions in ETS sectors as a response to current and future ETS prices, taking into account, in particular, a perfect foresight of the carbon price progression in the period 2025-50.

It also assumes that investment decisions can be based on a power generation portfolio approach, where profitability of investments is assessed on a portfolio rather than a project by project basis. Because of this portfolio approach, the EUCO27 scenario may not capture that some investments cannot be recuperated when income is only dependent on wholesale markets where high renewable penetration exactly tends to lower the wholesale price.

Therefore, a complementary analysis is provided below, looking more specifically at potential profitability issues for the renewables investments projected to be necessary (in the EUCO27 scenario) to reach the renewables target, when looked at on a project per project basis, and assuming revenues are only based on the wholesale market.

First, this can be assessed by making use of the results of the WESIM model. This model was used to assess investment profitability of RES projects, but did not consider implications of RES developments on other power generation technologies, which is the object of the MD IA. The analysis performed with this model concludes that the investment gap (aggregated capital expenditure for RES-E projects that are not viable without support) would amount to c. EUR 13 billion in 2020, EUR11 billion in 2025 and EUR9 billion in 2030 187 . For the whole 2020-2030 period, this means a cumulative investment gap of about EUR 116 billion. This investment gap represents the amount of investments that would require some support, in case renewable electricity projects are to only receive market revenues from the wholesale electricity market only. It does not mean that public support would need to cover all the investment costs, as it could be that only a marginal support would be sufficient to complement electricity market revenues to make those investments profitable.

More specifically, the WESIM model results show that while only 40% of investments in 2020 as projected in EUCO27 could be financed by wholesale electricity market revenues only, this share increases to 66% in 2030. Onshore and solar PV become gradually profitable and by 2030, and could be financed entirely by the markets. Conversely, technologies such as offshore wind investments cannot be yet fully financed on the markets by 2030. It should be noted at the same time that rapid penetration of renewables has a decreasing effect on both the wholesale price as well as on the CO2 price (for a given number of ETS allowances on the market), thereby reducing the ability of the market to act as the driver for investments in both renewables and flexible generation.

Table 4: Evolution of required annual investment and investment gap
over the 2020-2030 period

Such figures are affected by changing some key assumptions. As explained in Annex 4, removing priority dispatch tends to decrease this investment gap, as overall market functioning improves; also increased investors' confidence vis-à-vis ETS price developments decrease it. In fact, the PRIMES model simulates emission reductions in ETS sectors as a response to current and future ETS prices, taking into account, in particular, perfect foresight of the carbon price progression in the period 2025-50. Sensitivities have been performed with the WESIM model to try and capture the impact of imperfect foresight on renewables generators anticipated revenues, which results in a lower share of investments in renewables being viable without support – see Annex 5 for detailed results.

Second, the issue of whether wholesale electricity market revenues would be sufficient to finance investments in power generation is addressed in detail in the Market Design Impact Assessment. First, the MD IA simulates market revenues taking as a constant the level of investments provided by the EUCO27 scenario (PRIMES/IEM). Focusing on the most important results from a RES generators perspective, the analysis shows first that onshore wind across the EU from 2025 and solar PV in the South Europe (excluding small scale) from 2030 make profits on energy-only markets. However, this is not the case of the other RES technologies.

To complement this analysis, it is important to also look at the dynamic behaviour of markets and how markets can also provide investment signals. A different model was used, PRIMES/OM. It confirms that mature RES technologies are among the profitable technologies by 2030. Conversely, less mature technologies, such as wind offshore or solar thermal, remain unprofitable. 189 .

All modelling approaches therefore confirm that support needs will gradually phase out over the 2020 decade, once sufficiently high ETS prices and better market functioning are in place, but that for some technologies, even this will not be sufficient.

Under Option 2, a toolkit for market-based and cost-effective support would be defined. These principles would be without prejudice to State aid rules that apply to Member States. The principles would include, inter alia, the possibility for Member States to use support schemes, the obligation to tender support in order to achieve value for money, the facilitation of participation of energy communities in the electricity system and in tendering schemes, the technology neutrality principle for tenders unless a technology specific approach is preferable and the protection for investors against 'retroactive' changes.

In particular, the framework would enshrine in legislation and expand the requirement to tender support; it would define tender design principles, based on emerging best practice, to ensure the highest cost-efficiency gains. The framework would thus strengthen the use of tenders as a natural phase-out mechanism for support, by which a competitive bidding process determines the remaining level of support required to bridge any financing gap – such level of support being expected to go to zero for the most mature technologies over the course of the 2021-2030 period (see above).

Additionally, the Revised RES Directive would explicitly enshrine the principle that support schemes designed in line with EU indications cannot be revised in a way that retroactively impact the rights related to the level of support received by renewables projects. 

Although the direct impacts of implementing this toolkit have not been tested via modelling scenarios, the framework is expected to be effective as it would define design principles (i) that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where needed) of market-based and cost-effective schemes based on emerging best practice design (including principles that are not covered by the current state aid guidelines). At the same time, the framework would be proportionate by leaving actual implementation to the state aid guidelines (e.g. for the definition of thresholds applicable for any foreseen exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment of individual schemes by the services of DG Competition.

To support this assessment, one can make use of existing analysis. Recent research has evaluated the impact of various support scheme designs on the dispatch of renewables generators, based on the case of Germany. It found that moving from a feed-in-tariff (FIT) to schemes exposing producers to short term and long term price signals (feed-in-premia and, more so, capacity-based support) resulted in (i) higher average market prices, (ii) lower price volatility, and (iii) a higher market value of renewable – especially in markets characterised by high renewables penetration and low flexibility 190 . These three factors combined can contribute to reducing the need for support for renewables – and missing money issues in general.

At the same time, it is also well documented 191 that support schemes exposing producers to market risks translate, all else equal, into higher cost of capital and thus higher renewables deployment costs. Modelling using the WESIM model shows for instance that moving from support in the form of feed-in tariffs (FIT) to support in the form of floating feed-in premiums (FIP) increases the total cost of support by 5% to 6%, while moving from FIT to fixed FIP increases to total cost of support by 9% to 13% 192 . Overall, the net impact on both total system costs and renewables support costs is difficult to quantify. However, such an analysis does not consider the overall positive impacts on electricity market functioning, and therefore other types of power generation producers, that more market-oriented support schemes would have as opposed to fixed feed-in-tariffs.

As regards tendering, analysis of past tenders suggests that tenders can yield significant cost-efficiency gains 193 - to the extent that they are well-designed. As an increasing number of Member States are introducing tenders, best practice is emerging 194 . Introducing certain best practice principles would (i) support the use of efficient tender designs, while respecting the need to ensure sufficient flexibility, and (ii) through partial harmonisation facilitate the design of joint tenders. The extension of tendering to investment aid would expand such benefits beyond operating aid.

Research also suggests that the behaviour of renewables in electricity markets – and thus their impact on market functioning – is determined by the kind of support they receive 195 . The degree of price exposure determines the trading behaviour of renewables generators, but also plant design and investment decisions 196 .

Additionally, empirical evidence (of past tenders) shows that the way support is allocated impacts the cost-efficiency of support. The analysis of past auctions in eight EU-countries and four non-EU countries showed that all those auctions schemes reported efficiency gains in terms of the contracted price or discounts achieved: e.g. a price of €84.9/MWh was applied in the second round of the German auction (led in 2015 on ground-mounted solar PV), which is significantly below the ceiling price of €112.9/MWh 197 . Recent auctions for offshore wind in the Netherlands and in Denmark have resulted in strike prices of, respectively, €72.7/MWh 198 and €60.0/MWh 199 – yielding significant reductions in the level of support relative to support awarded in other recent comparable projects.

Against this background, the Revised Renewables Directive could set out framework principles for the design of support schemes in the post-2020 context, laying down common principles ensuring that, when and if support is needed, such support be provided in a form that is (i) cost-effective, (ii) as little distortive as possible for the functioning of electricity markets, and (iii) fosters regional approaches through greater convergence in the design of support.

The RES Directive and the baseline do not open up the potential that could empower energy communities across the EU. Until today energy communities have only developed in a few countries: around 75% of all energy cooperatives are located in AT, DE, DK.

In addition to wider benefits for the local economy, energy communities could increase local acceptance of renewable energy projects and help mobilise the private capital that is needed for the energy transition.

In order to enable energy communities to develop across the European Union, measures are considered to balance the competitive disadvantages that energy communities face in a competitive market. Often energy communities as groups of engaged citizens are less professionalised than commercial project developers. Generally, they only develop one project that could participate in public tenders for support, and by nature they are linked to one geographical location.

Therefore, energy communities might face difficulties competing on equal footing with large-scale players, i.e. competitors with larger projects or portfolio 200 . Such tendencies are already observed, e.g. for small-scale community power 201 . The trend in renewable support schemes towards market-based mechanisms is most likely to create an increasingly difficult economic environment for community energy projects, severely hampering their development conditions 202 .

Measures to offset these disadvantages include enabling condition for energy communities, facilitating participation of energy communities in open, transparent and non-discriminatory tenders for support schemes, and facilitated market integration.

Such regulatory and legislative provisions require precise definitions. These should be as inclusive as possible to prevent excluding actors that should be supported, but as exclusive as necessary to prevent abuse 203 . This is made difficult by the fact that energy communities vary significantly in size and legal form which depends on the company or association laws of the Member States. For this reason the definition considered proposes a list of criteria of which a minimum number needs to be met in order to qualify as an energy community. In any case, only energy communities for energy generation are considered. Supplier cooperatives are not within the scope of these measures. The definition would be based on existing entities (such as SMEs) and for the only purposes of creating an enabling framework. Member States will still have freedom to have their own definition of energy communities.

By 2030, more than 50 GW wind and more than 50 GW solar 204 could be owned by energy communities, i.e. respectively 17% and 21% of installed capacity 205 , bringing a substantial additional amount of local capital to renewable projects. Opening markets and creating enabling framework for energy communities could therefore help exploit this potential.

Under Option 3, the possibilities for support would be more limited and would require all future support to renewable electricity to be provided in the form of investment support (capacity-based support), not linked to production which would be fully supportive to the new market design. Such an approach would maintain the pricing signal in line with the new market design, and provides incentives for renewables production to fully support the energy market. It may however increase the need for administrative controls to avoid abuse and ensure that assets are properly maintained, and does not provide incentive to maximise renewables production – making reaching a production-based target more difficult. It would also result in significant budgetary implications for Member States, as payments would have to be frontloaded. There is finally also little actual experience with supporting renewables through upfront investment aid.

Social impacts

Under Option 1 (prohibition of support), RES-E investments would be insufficient to reach the overall at least 27% target by 2030. It is likely that not reaching the 27% target would have negative social impacts in terms of job creations, growth and security of supply, as compared to the other policy options, and notably the baseline.

As explained above, net impacts on total costs of support are unclear under Option 2 and Option 3, making it difficult to quantify the social impacts implications of such scenarios.

Environmental impacts

In terms of environmental impact, missing the at least 27% target by 2030 will result under Option 1 to a lesser GHG reduction in the power sector from renewables than under Options 0, 2 and 3. At the same time, since the EU ETS cap sets a binding ceiling on the emissions within the sectors covered by the system, missing the RES target would not impact in absolute terms the EU level GHG emission reductions, which would be achieved in any case. It will lead to higher ETS carbon prices to achieve the overall GHG target, which will reduce emissions in other sectors.

However, some environmental impacts are to be expected depending on the type and location of RES-E power generation being deployed. A concentration of RES-E investments in specific countries or regions might create issues in terms of land availability for such projects, or could even in some cases put additional pressure on environmental protection rules for dedicated areas 206 . In the case of the baseline scenario, it projects an increase in electricity generation from biomass, notably as compared to the central policy scenario. Such results can be explained by the assumption of dedicated Member State support included in the baseline scenario. As such, this might create specific environmental issues.

Political feasibility /opportunity

Option 1 would not seem politically feasible, since the prohibition of support schemes would prevent Member States from bridging the funding gap of RES-E and seriously jeopardise the achievement of the 2030 target. Other Options seem to respect the principles of subsidiarity and proportionality.

Stakeholders' opinion

Respondents to the public consultations largely considered that support mechanisms should encourage greater market responsiveness, resulting in gradually decreasing support levels as technologies become mature. Several respondents regard regional cooperation and consultation as a useful method to reduce differences and facilitate convergence amongst national support schemes.

Discarded options

Option 1 can be discarded as it would materially jeopardise the attainment of the EU-level at least 27% target by 2030, and additionally raises subsidiarity and proportionality issues.

5.1.2.    A more coordinated regional approach to renewables support

Option 0: Baseline

The Revised RES Directive would still leave it to Member States to decide the extent to which they want to open their support schemes to cross-border participation, and to enter into joint support schemes or joint projects. However, because such options have not been significantly used to date by Member States, the modelling work conducted in the baseline scenario makes the assumption that no use is made of such cross-border participation, or joint support schemes or projects.

Option 1: Mandatory partial opening of support schemes to cross-border participation

The Revised RES Directive would make it mandatory for Member States to partially open their national support schemes to cross-border participation, up to a level to be defined but representative of the level of physical cross-border interconnections.

Under this option, the general principles for such opening would be set out, e.g.: (i) reciprocity, (ii) no double-compensation, (iii) cooperation agreement to allocate support towards each Member States' renewables pledges. A more detailed "blueprint" laying down possible forms of cross-border participation (joint auctions, mutually-opened auctions) could be provided in an annex to the Revised RES Directive (similar to the approach followed for capacity mechanisms).

Option 2: Mandatory regional support schemes

The Revised RES Directive would stipulate that only regional support schemes are allowed and possibly define such regions.

5.1.2.1.    Introduction to the assessment

The rationale for "regionalising" support schemes is that a more regional approach limits negative impacts on the energy market and can help Member States to achieve the EU target cost-effectively.

The current Renewables Directive foresees the possibility of cooperation mechanisms in the form of joint support schemes, but such possibility has not been used to date, at the exception of the joint scheme between Sweden and Norway. The current Directive also leaves it to Member States to decide to which degree they want to open their support schemes to non-domestic production. Certain Member States are however working on opening their support schemes to the participation of project developers located in neighbouring countries, also to ensure compliance with other Treaty provisions 207 . In the absence of a common framework for such cross-border access, Member States may implement different solutions, possibly leading to market fragmentation.

5.1.2.2.    Detailed assessment

Two options for further regional cooperation are assessed, namely (Option 1) a mandatory partial opening of support schemes to cross-border participation (CRA_crossborder), and (Option 2) mandatory regional support schemes (CRA_regio). Both options have been modelled using as starting point the baseline (CRA) scenario. The WESIM model was also used to test the impacts of cross-border participation. The full description of these scenarios is presented in Annex 4 of this Impact Assessment, while Annex 5 presents detailed results.

This assessment is also based on results from a recent Ecofys study 208 that considers three different scenarios for the development of regional support schemes, i.e. (i) limited cooperation, (ii) moderate cooperation and (iii) strong cooperation 209 .

Economic impacts

Fostering cross-borders cooperation could lead to a decrease of capital expenditures, thanks to geographical shifts towards better sites that require less renewables capacity to produce the same amount of electricity 210 , as shown by several case studies. According to Ecofys, a joint quota system in Scandinavia, which would extend the existing joint quota system between Norway and Sweden to Denmark and Finland, could for example lead to a reduction in capital expenditures of about EUR 680 million over 2015-2020 211 . Optimisation of resource allocation in the case of a joint feed-in premium system in Central and Eastern Europe could reduce capital expenditure by about EUR 325 million over 2015-2020 212 .

Modelling based on the WESIM model 213 also confirmed the reduction in support costs allowed by a partial opening of support schemes to cross-border participation. The study simulated the impact of France partially opening floating feed-in premium support to Germany for projects completing construction in 2025 214 . The study finds an annual cost saving in the French auction of EUR 90 million over the fifteen-year life of the subsidy.

Comparing PRIMES scenarios, the first element to be observed concerns the change in the renewable energy mix. The 'CRA_crossborder' scenario, and even more 'CRA_regio', scenarios lead to a significant shift between offshore wind investments and solar investments. This is due to the relatively cost-effective potential, under the right framework conditions, e.g. financing costs, for solar investments. By further regionalising support schemes, and by harmonising the financing conditions for investments in RES-E projects within a region, more cost-effective investments can be financed, as opposed to the baseline scenario, where each Member State supports its own projects, with its own financing conditions. Yet, the impacts of these changes in the power generation mix are rather marginal when looking at the average electricity prices and average cost of electricity generation. The ETS price remains stable in CRA_crossborder while it increases in CRA_regio 215 .

In terms of energy system costs, it can be observed than both scenarios lead to lower system costs than the baseline scenario. CRA_cross border leads to an average reduction of energy system costs of EUR 1.0 billion annually, for the period 2021-2030. Under CRA_regio, the reduction reaches EUR 1.3 billion annually. These benefits continue post-2030, although they slowly fade away in 'CRA_crossborder' while they keep increasing in 'CRA_regio'. Two main factors influence the results: i) first, an allocation of investments where they make more economic sense, as support to RES is harmonised within regions and therefore optimises investments over the availability of RES resources; ii) second, the creation of broad markets at regional level implies broadening the funding, procedures and guarantees at regional level, which can lead to economies of scale and slightly lower access to finance conditions.

Focusing now on the distributional issues, across countries and across technologies, the first element that can be mentioned is that 'CRA_Regio' and 'CRA_crossborder' provide a more balanced renewables power generation mix than the baseline scenario. This is notably visible in the case of 'CRA_regio', where significant solar PV investments take place, as mentioned above. The distribution of investments across Member States is also more balanced than in EUCO. The top three Member States represent 67% of investments in the baseline scenario. This share decreases to 58% in 'CRA_regio'. Conversely, the share of the smallest contributors increases.

Finally, it can be expected – although the impact has not been explicitly quantified – that regionalisation of support would limit the "cannibalisation" effect, by allowing greater flexibility in the operation of the electricity system and thus reducing the number of low or negative hours when renewables are producing. All else equal, this would reduce the need for support for renewables.

Social impacts

Member States may be reluctant to enter into cooperation mechanisms due to – anticipated or actual – low public acceptance, in particular difficulties in explaining to national taxpayers or consumers that part of their funds may be used to support renewables projects in other countries 216 . Thus, opening schemes may lead to public acceptance issues.

On the other hand, enhancing regional cooperation would have a positive impact on the total cost of support passed on to the final customers. Support cost reduction could be tangible 217 . For instance, the Central and Eastern European joint FIP system could generate cumulative support cost savings of EUR 400 million (2015-2020) 218 . Overall, the need for support at a EU-level between 2011 and 2020 would be reduced by 5.8% in a moderate cooperation scenario and by 10,8% in a strong cooperation scenario, compared to a limited cooperation scenario 219 . This decrease in financial support would enable a decrease in the charge passed on to end-customers.

The comparison of the various scenarios performed using PRIMES does show overall lower renewables supporting costs passed on to consumers in 'CRA_crossborder', and even more so in 'CRA_regio', compared to the baseline scenario. In the case of 'CRA_crossborder, this is reinforced by the fact that the share of investments financed by the market increases compared to baseline, while it does not change significantly in the case of 'CRA_regio'. This is in part because the scenario considers that further regionalisation of support schemes lead to a reduced country risk for investors, and therefore easier access to finance for renewables project developers. However, the additional renewables investments in power generation still need to be financed, and will generally interact and compete with other power generation technologies to determine prices. In the case of the 'CRA_regio' scenario, this translates in an overall increase in electricity prices for households.

Environmental impacts

Regional cooperation is likely to encourage renewables deployment in countries with large fossil fuel shares in their energy mix, resulting in a reduction of fossil fuels and CO2 emissions in those countries. According to the Ecofys scenario 220 , a strong cooperation (resp. moderate) would lead between 2011 and 2020 to a fossil fuel avoidance by 0.4% (resp. 0.3%) and a CO2 emission avoidance by 0.7% (resp. 0.2%) in the power sector 221 , without taking into account the impact of the EU ETS. Regional cooperation may also reduce pressure on environmentally protected areas, as mentioned in the previous section, by providing a larger pool of potential sites for RES investments projects than what would be possible if based on national approaches only.

Political feasibility /opportunity

Options 0 and 1 seem politically feasible as they respect principles of proportionality and subsidiarity. Due to its enlarged scope, Option 2 may be more challenging politically and may be seen as contradicting Member States' right to decide on their energy mix. Importantly, additional interconnections could facilitate the political feasibility of moving towards more regionalised support schemes.

Other impacts (competitiveness, markets, innovation…)

No significant impact on SMEs. Nevertheless, they could benefit from some positive impact if part of the projected solar deployment is based on small-scale installations.

It is possible to compare the impact of the various scenarios on electricity prices and energy costs for industry. The impacts of the various options compared to baseline are relatively marginal for industry. Although electricity prices slightly decrease for industry, the energy related production costs slightly increase.

Stakeholders' opinion

Regarding the geographical scope of support schemes, there is a wide variety of opinions across the stakeholder community. While the preferred option by stakeholders (34 %) is a gradual alignment of national support schemes through common EU rules, there is some willingness (17 %) to move further and consider a progressive opening of national support schemes to energy producers in other Member States under some conditions such as, for instance, obligation of physical delivery of the electricity, or having a bilateral cooperation agreement in place. The reasons given to sustain this position generally lie on the fact that the natural conditions of the location in terms of abundancy of the resource (wind or solar) are only one element to be looked at to minimize the cost of deployment of renewable energy (e.g. grid issues, market development). As for Member States, those generally believe that cross-border participation to support schemes should be on a voluntarily basis. Overall, the development of a concrete framework for cross border participation is generally welcomed.

Moving towards even further integration by introducing a EU-wide level support scheme, or a regional support scheme, is supported by 24 % and 12 % of the respondents respectively, while keeping national level support schemes that are only open to national renewable energy producers is the preferred option for 13 % of the respondents. Several respondents highlight some possible risks and political sensitivities associated with schemes entailing further integration, as those could imply citizens in one Member State having to contribute to renewables' development in another Member State.

Discarded options

Option 2 may raise issues of proportionality and can be regarded as politically unfeasible.

5.1.3.    Reducing the cost of capital for renewable electricity projects

Option 0: Baseline

No specific financial instrument in support of renewables generation projects. Public investment support would continue to be provided in certain Member States through national or sub-national programmes (using national and sub-national budgets and/or structural funds), and through any EU-level facilities and instruments having an investment period going beyond 2020.

Option 1: EU-level financial instrument with wide eligibility criteria

An EU-level financial instrument would be created or, preferably, existing instruments would be prolonged post-2020 (in particular EFSI), which would support investments in renewables projects. As under current EFSI, renewables would (i) compete against other sectors for funding, and (ii) eligibility criteria for support would be defined widely and allow for a large variety of technologies and all Member States to benefit from support.

Option 2: EU-level financial instrument in support of higher-risk renewables projects

As under Option 1, but support would go to various "high cost of capital" renewable projects, which may be (i) projects using less mature technologies, (ii) projects in Member States facing a high cost of capital, and/or (iii) projects of regional dimension. Option 2 could be stand-alone, or, preferably, come in addition to Option 1 – for instance through a dedicated "high risk" guarantee and different eligibility criteria.

As an optional feature, access to such guarantee could be limited to certain Member States having ambitious renewables national commitments – according to criteria to be defined.

5.1.3.1.    Introduction to the assessment

Renewable electricity projects are capital intensive - they require large upfront capital investments combined with low operation and maintenance costs. Given this frontloaded cost structure, the weighted average cost of capital (WACC), which reflects the perceived risk of a project from an investor point of view, is decisive to the viability of a RE project 222 . A high cost of capital thus materially increases the overall investments required to meet a given deployment target.

WACCs of renewables projects are driven by several risk factors that could be classified into three main categories, namely (i) country-specific risk, (ii) sector-specific risk and (iii) project specific risk 223 . Significant differences in WACC for renewables projects are found across the EU. WACC of onshore wind projects, for example, were estimated in 2014 to vary between 3.5% (in Germany) and 12% (in Greece) 224 . Country-specific and sector-specific risks explain a large share of this gap.

Currently, investments in renewables tend to focus in mature renewables technologies in countries with low perceived risks corresponding to low cost of capital, with only two Member States (the UK and Germany) receiving over two thirds of all investments into RES-E new investments as well as mergers, acquisitions and refinancing activity in 2014 and 2015 225 .

Figure 9
Source: Bloomberg New Energy Finance / Hg Capital

The risk is twofold: (i) overall investments into renewables generation projects may be discouraged by high cost of capital and thus be insufficient to meet the 2030 target; (ii) and/or investments may concentrate in mature technologies in low perceived risk countries, leading to a sub-optimal medium- and long-term deployment at EU-level and a lack of exploitation of the potential of higher WACC countries.

Financial instruments can help lower the WACC of renewables projects, decreasing the overall investment cost required to meet the 2030 target. As way of illustration, a recent study found that risk-sharing schemes could reduce the WACC of offshore wind projects by 14% to 23%, depending on Member States 226 – which in turn would translate into material investment cost reductions.

Options related to the creation of renewables-focused financial instruments have been primarily assessed using variants to the baseline scenario.

5.1.3.2.    Detailed assessment

Economic impacts

The impact of Option 1 (regional projects) is difficult to assess quantitatively as this may only concern a limited number of projects and installed capacity. Therefore, results would very much depend on overall funding available and on the pipeline of projects being developed. Still, projects of cross-border dimension tend to have higher administrative complexities and costs (in relation e.g. to environmental permitting and grid connection), typically translating into higher cost of capital relative to similar, non cross-border projects. As such, they would be expected to benefit materially from a guarantee scheme.

Option 2 considers a scenario where a subset of riskier projects (see Annex 4 for more details) can benefit from an EU-guarantee for part of the project financed through debt. It has been declined in two variants and assessed in detail via modelling work. In the first variant ('CRA_countryspec'), the modelling assesses the impacts of concentrating access to the EU financial instrument to a subset of Member States, the ones with the initial highest cost of capital for renewables projects, for all technologies. In the second variant, ('CRA_techspec') the focus is put on a limited number of riskier technologies having a high cost of capital 227 , but in all Member States. In both cases, a reduction in the WACC for indivdual projects benefiting from the guarantee of 15% 228 compared to the baseline is assumed and put as an exogenous change in the model.

Regarding the power generation mix, at EU level, the changes are marginal in the 'CRA_countryspec' scenario as compared to the baseline (CRA) scenario. Average costs of electricity generation are slightly lower. The share of wind onshore and biomass slightly decreases. The decrease in the share of wind is confirmed when observing investment cost patterns, since such investments decrease as well. However, the dispersion of investments across Member States is more balanced, when compared to CRA scenario.

Changes are more significant when considering the 'CRA_techspec variant'. This scenario leads to significantly more investments in wind offshore, which translate into an important increase in the overall RES-E share. However, this has no major impact on electricity prices or on average cost of electricity generation. In terms of investments, this scenario generates much more RES-E investments than the baseline scenario, in particular in the areas where dedicated support is concentrated, namely wind offshore and tidal. It also leads to much more concentration of investments in specific countries, the ones with the highest wind offshore potential. Finally, it should be noted that the ETS price is significantly negatively affected by the deployment of additional RES technologies under these conditions, if we are to keep the same overall GHG emission reductions in the ETS sector. This would limit the role of the energy-only market to drive investments in renewables.

The 'CRA_countryspec' scenario leads to lower energy system costs than in baseline. On average, energy system costs are EUR 1.5 billion lower in this scenario than in CRA. This result is also confirmed by looking at developments post-2030. Conversely, the CRA_techspec scenario translates into significantly higher energy system costs. This is the result of a combination of factors: i) a significant increase in RES-E investments compared to baseline; and ii) a concentration of such investments in more expensive technologies. It must be noted that the potential benefits of such concentration of investments on technological progress and cost reduction, notably if this leads to technological breakthrough, may not be fully captured by the model. For instance, as regards offshore wind in particular, recent tenders have cleared with a cost of support of around 80€/MWh, which is below the cost assumptions made under REF2016 and other policy scenarios conducted for this and other related Impact Assessments.

Finally, it is also worth comparing the RES-E shares across Member States between the baseline and CRA_country spec. As expected, the RES-E share increases in the countries benefitting from the support, to the detriment of other Member States with better initial financing conditions but lower renewables potential. In other words, this scenario achieves a more balanced deployment of renewables across the EU at a lower cost than continuation of purely national-based practices.

Figure 10 – Percentage points difference in RES-E share between CRA_country spec and CRA (2030)
Source: PRIMES

Under all options, it should be noted that unconditional access to financial instruments may reduce the need for Member States to improve financing conditions via better framework conditions, and would therefore question the initial assumptions considered in the modelling of a clear reduction in the WACC for all projects financed. Such underlying framework conditions are essential for the results to hold. This may imply that access to the funds is made conditional upon Member States delivering on certain measures (e.g. administrative procedures for renewables).

Social impacts

'CRA_countryspec' shows overall lower renewables supporting costs passed on to consumers. This is also explained by the fact that a higher share of investments can be financed by the markets. As some countries receive additional guarantee to finance investments, the need to rely on operational support becomes of course more moderate. The overall impact on electricity prices is also positive, as prices for households slightly decrease compared to the baseline. Financial tools that reduce the WACC of the project would decrease the need for direct financial support, alleviating the financial cost of support for end costumers. Net gain would however depend on the exact structure and cost of the guarantee scheme itself (capital cost of opportunity, portfolio losses, and administrative costs).

'CRA_techspec' shows overall much higher renewables supporting costs passed on to consumers. The impact is however much more limited on electricity prices, due to the overall factors influencing the electricity mix and therefore price formation.

Environmental impacts

The option of support chosen will have an impact on the renewables energy mix by unleashing investment in certain resources abundant in higher-cost of capital Member States. However, no impact can be observed on GHG emissions since all scenarios reach a 40% GHG emission reduction by 2030.

Political feasibility /opportunity

All options can be seen as respecting the principles of proportionality and subsidiarity. Political feasibility however depends on the amount of funding foreseen, without pre-empting discussions on the future multiannual financial framework of the Union.

Other impacts (markets, innovation…)

The options designed will not have a significant impact on SMEs at EU level. Nevertheless, they could benefit from some positive impact if part of the solar deployment is based on small-scale installations 229 . No significant impact was identified as regards impacts on energy costs and electricity prices for industry.

5.1.4    Administrative simplification

Renewable Electricity Directive 2001/77/EC and the RES Directive oblige Member States to streamline administrative procedures for renewable energy. However, administrative barriers remain an obstacle to the deployment of renewables. With the upcoming revision, the issue becomes even more relevant on EU level, as the Revised RES Directive will not contain national targets. The options proposed in the section build on Article 13 of the RES Directive and on Article 8 of Regulation 347/2013 (the "TEN-T" Regulation) for projects of common interest. Article 13 obliges Member States to clearly define permitting procedures with transparent timetables, provide comprehensive information, streamline and expedite administrative procedures and provide facilitated procedures for small projects.

Option 0: Baseline

This option consists in the extension of current Article 13 (1) rules on administrative procedures (no-change) until 2030. With such an option, the subsidiarity principle will be respected, since Member State will be free to find the most effective way of streamlining administrative procedures for renewables. However, the current provisions have been too vague to be enforced effectively and administrative barriers continue to exist.

Option 1: Reinforced provisions with "one-stop-shop", time ranges and facilitated procedures for repowering

This option consists of a reinforced Article 13(1). In addition to the current obligation to ensure that ‘certification and licensing procedures … are clearly coordinated and defined, with transparent timetables’ this option proposes a maximum time range is specified after which the competent authority needs to give a decision on the application. Furthermore, this option requires Member States to designate a single administrative contact point (one-stop-shop) for permit granting similar to the provisions of the TEN-E Regulation. In order to respect the subsidiarity principle, Member States would nevertheless have the freedom to choose the most appropriate implementation rules. Moreover, this option proposes facilitated procedures for the repowering of renewable energy projects in order to ensure that assessments that have been conducted do not need to be repeated.

Option 2: Reinforced provisions with "one-stop-shop" and time limits, automatic approval, and compulsory simple notification for small projects

This option would consist of all the elements of Option 1. However, instead of a time range for the permitting process, this option prescribes a fixed deadline. A “defined maximum time-limit for permitting procedures, and effective consequences if deadline is missed” as called for by 85% of stakeholders who expressed a view on this topic in the public consultation. In order to improve the enforceability of this deadline, the option also includes an automatic approval if no answer is received by the end of the deadline. The option also includes simple notification (instead of authorisation process) for household-size renewable energy projects and facilitated procedures, such as shorter time limits, for medium-size renewable energy projects.

5.1.4.1.    Introduction to the assessment

Article 13 (1) of the current RES Directive mandates simplified, streamlined, expedited and coordinated administrative procedures. However, the current directive was only partly successful in reducing these barriers and streamlining the various elements of the permitting process. The REFIT evaluation and the Renewable Energy Progress Report of the European Commission found that several administrative barriers continue to exist across Member States and have a negative effect on the costs and the deployment of renewables. It is concluded that greater administrative simplification is needed.

Administrative costs contribute significantly to the overall project cost: In France, for instance, the administrative costs of a wind project account for 15% of project costs 230 . Project delays are also expensive: a one-year delay results in 50 % of additional regulatory costs and a 0.25 % increase in the cost of debt when feed-in tariffs are digressive. Reducing administrative burden through simplification (based on best practices and existing legislation) can therefore reduce the costs for the deployment of renewables.

Figure 11: Administrative barriers present in European Member States in 2014 231

Figure 12: Lost revenue due to administrative delay 232

5.1.4.2.    Detailed assessment

The proposed options precise requirements that already exist in the current article 13: it requires Member States to provide comprehensive information (addressed through development of manuals) and streamlining, coordinating and expediting the permitting process (addressed through one-stop-shops). Similar requirements exist in the TEN-E Regulation (EU) No 347/2013: Article 8.3 proposes one-stop-shops and Article 9.1 requires manuals.

Both measures are regarded as best practice for permitting procedures across sectors by other EU legislation 233 and by OECD publications 234 and are requested by stakeholders in the public consultation. Yet, several Member States have not implemented them for the permitting of renewable energy projects 235 . Manuals are a low-cost no-regret option as the knowledge required for such a manual should already exist in the administrations of Member States.

Time limits for authorisation projects exist in more than half of the Member States and are regarded as best practice for administrative procedures generally 236 . They can also be found in Article 10 of the TEN-E Regulation (EU) No 347/2013. In particular in combination with an automatic approval after the deadline, they are the most effective way to limit the time for permit granting.

The automatic approval under Option 2 would only be possible when it does not collide with requirements rooted in other European legislation, such as the potential need for an environmental impact assessment 237 . Even though automatic approval does not necessarily improve certainty for project developers who might see their project challenged in courts after a permit is granted automatically, such a provision would set clear performance standards for national administrations and would increase the enforceability of time limits. However automatic approval is questionable with regards to subsidiarity.

Economic impacts

The experience of introducing a one-stop-shop for so-called ICPE projects 238 in seven French regions in 2014 shows the effects of a one-stop-shop on permitting times. The one-stop-shop reduced the average permitting duration for ICPE projects to 259 days compared to 431 days for projects without this measure 239 .

Simple notification for household-sized projects and tighter deadlines for medium-sized projects as proposed in Options 1 and 2 are expected to facilitate the uptake of distributed generation. The impact of these particular measures is expected to be felt in Member States that do not have measures in place for small-scale projects yet. According to the RES Report, this was the case in Bulgaria, Estonia, Latvia, Slovenia and Slovakia in 2014 240 .

Simplified procedures for repowering, as proposed in Option 1 and 2, should make repowering projects less costly. According to industry estimates up to 76GW of the EU’s onshore and offshore wind energy capacity will come to the end of their operational life between 2020 and 2030 (of today’s installed capacity is 142GW) 241 showing that there is significant potential for the continued deployment of renewables when repowering is simplified. The business as usual option does not contain any specific provisions on repowering.

Social impacts

It is expected that a more efficient administration will not have an immediate social impact.

The maximum time limits for permit granting are not expected to have a negative social impact. Time limits already exist in 23 Member States and a limit of 3.5 years allows sufficient time to consult stakeholders also for large projects.

Environmental impacts

Administrative simplification is expected to contribute to a favourable environment for renewable energy projects. However, it is difficult to relate the direct impact of administrative measures proposed to environmental results, such as the replacement of fossil fuel generation with renewable energy generation.

Political feasibility /opportunity/subsidiarity

The options are in line with existing legislation (article 13 of the current RES Directive, TEN-E Regulation) and with common practice in a number of Member States. Administrative simplification was supported by a large majority of respondents in the public consultation, including some Member States.

All options, with the exception of an automatic permit granting in Option 2, respect the subsidiarity principle. The measures do not require changing the content of the permitting process but they oblige Member States to set up coherent administrative structures at the appropriate level. This leaves Member States room to develop measures that are best suited to local circumstances while at the same time specifying the existing provisions and thus making them more enforceable.

Action needs to be taken at European level since the EU RES target for 2030 is mandatory for the EU as a whole and because the reduction of administrative burden can contribute significantly to achieving this target. The existing measures were not specific enough to be enforced effectively.

Impact on SMEs

A simpler permitting procedure is particularly helpful for small actors which have fewer resources and less experience in dealing with different administrative responsibilities.

5.1.5.    Overall comparison of the options to increase renewable energy in the electricity sector (RES-E) 

5.2.Options to increase renewable energy in the heating and cooling sector (RES-H&C)

The table below provides an overview of the options discussed in this section.

5.2.1.    Mainstreaming renewables in heating and cooling supply

The purpose of the proposed measures is twofold: on the one hand, address persisting market failures in the area of heating and cooling, and on the other hand, contribute as a 'gap-avoider', and ultimately (following mid-term review of EU progress towards 27% target) as a 'gap-filler', to the achievement of at least 27% renewables share at the EU level by 2030.

The following options are closely interrelated with measures on energy efficiency and energy performance in buildings, which are respectively addressed within the initiatives for the revision of the Energy Efficiency Directive and the Energy Performance of Buildings Directive. However, as detailed below, the impact of these legislations on renewable deployment has so far remained limited, and is not expected to substantially increase post-2020. Therefore a complementary initiative targeted on heating and cooling across all energy users (industrial, residential and tertiary) is deemed necessary.

Option 0: Baseline

The RES Directive requirements with regard to renewable heating and cooling as well as information and training (Article14) are included in the Revised RES Directive and continue after 2020. The provisions of revised EED and EPDB concerning renewables as currently proposed are implemented, therefore renewable energy technologies in buildings will be indirectly promoted through legal requirements on building energy performance, including nearly zero energy buildings, methodologies for calculating the energy performance of buildings and building renovation and energy efficiency measures as included in the initiatives for the revision of the Energy Efficiency Directive and the Energy Performance of Buildings Directive.

Specific support for RES-H&C technologies that were present in 2020 at national level continue to be in place, with however a slight decrease in volume due to the absence of post-2020 targets. Renewable energy technologies will need to compete with fluctuating fossil fuel prices and distortive subsidies for fossil fuels with no corrections through ETS in this sector.

Option 1: Renewable energy obligation on fossil fuel and fossil fuel based energy suppliers for heating and cooling 

A renewables heating and cooling obligation could be included in Revised RES Directive, requiring that each Member State oblige their designated energy suppliers who sell fossil fuels or fossil energy for heating and cooling to achieve a mandatory share of renewables in the total fuel/ energy sales volume for heating and cooling.

However, given that energy and fuel suppliers who already have renewables in their portfolio would not be required to be part of this obligation, this could lead to fictive renewables share claims in order to gain exemption from the obligation scheme. Eventually this might not lead to increased renewables consumption volumes in a given Member State as energy and fuel suppliers who already partially sell renewables and could trade their renewables component with fossil fuel suppliers would not necessarily be motivated to continue to expand their renewable production or deployment.

If the renewables heating and cooling obligation addressed only the non-renewable part of the heating/cooling market, about 83% 252 of the total EU final energy demand for heating and cooling (excluding electricity) could be potentially covered.

Option 2: Renewable energy obligation on all fuel and fuel based energy suppliers for heating and cooling, including those already supplying renewables

A renewables heat and cooling obligation could be included in Revised RES Directive, requiring that each Member State oblige their designated energy suppliers for heating and cooling to achieve an increase in the share of renewables in their total annual sales volume by 2030. Unlike in Option 1, in Option 2 every supplier would in principle be obliged with the exemption of those supplying 100% renewables.

If all non-renewable and mixed portfolio (including renewable fuel and technology) suppliers would be covered in the renewable energy obligation scheme, about 98% 253 of the EU heating and cooling market (excluding electricity) could be potentially addressed.

For both options, two variants of this obligation could be envisaged:

Variant 1 Gradual obligation: fossil fuel or fossil fuel based energy suppliers would be required to ensure that each year from 2021 to 2030, an additional share 254 of the fossil fuel part of the energy sold or distributed to end-consumers for heating and cooling come from renewables;

Variant 2 Universal obligation: fossil fuel or fossil fuel based energy suppliers would be required to ensure that by 2030 at least a certain 255 share of the energy sold or distributed to end-consumers for heating and cooling comes from renewables.

Under both approaches, energy suppliers in Member States could comply with these obligations either through:

(i) physical incorporation of renewable energy, including bioenergy made from waste, in the energy supplied for heating and cooling 256 ,

(ii) direct mitigation measures such as installation of highly efficient renewables heating and cooling systems in buildings and/or renewable energy use for industrial heating and cooling processes or

(iii) indirect mitigation measures proven by tradable certificates (carried out by another economic operator such as independent renewable technology installer or ESCO providing renewable installation services).

With natural gas representing more than 40% of the total EU heating and cooling supply in 2012 257 , the physical incorporation option (i) would allow suppliers to gradually increase their share of biogas injected into the network and tackle the untapped potential of the sector.

For the technology implementation options, a methodology is required to calculate the amount of heat a RES-H&C installation is delivering into the obligation scheme. The mechanism applied must ensure that the calculated or metered output of a RES-H&C installation is accurate, replicable and not open to abuse. This will be vital for protecting the scheme from gaming and fraud.

5.2.1.1.    Introduction to the assessment

With the current legal requirements as set out in Articles 3(1) to (3), 4, 13(3) to (6) and 16(11) of the RES Directive, the EU is expected to achieve around 22% of RES-H&C share by 2020.

In EUCO27 scenario, a cost-effective level of RES-H&C deployment by 2030 is projected to be around 27%. Under a continuation of current practices, including additional renewables-at building level (option 0), the EU might only reach around 25% renewables in H&C in 2030 258 . The assessment of potential impacts on renewable energy deployment of Option 0 is based on REF2016, on which the contribution of EPBD measures in the field on renewables has been added. On the basis of the assessment presented in 5.2.1., RES-related measures in the EPBD could potentially tackle between 6% and 10% 259 of the total heating and cooling supply.

Energy efficiency can also play a role in increasing the share of renewables in heating and cooling by lowering the overall demand. However, energy efficiency alone will not be sufficient to reach a cost-optimal share of renewable in heating and cooling in the residential sector 260 . Between 2021 and 2030, energy efficiency could tackle around 50% of the additional effort needed to reach cost-efficient renewable deployment in the heating and cooling sector 261 . Energy savings should mostly affect non-renewable heating, while the overall consumption of renewables in final heat should remain constant. The rest of the effort will be supported mostly by heat pumps. Therefore additional measures will be needed to ensure that renewables will gradually replace fossil fuels in heating and cooling, and address the untapped potential in terms of electrification and heat pumps deployment. The role of heat demand savings would obviously increase in case of more ambitious energy efficiency target, as explained in Annex 4. However, the influence of a 30% target in energy savings by 2030 would not substantially change the cost-effective share of renewables to be reached by 2030 262 , therefore the level of suppliers' obligation should not be affected.

The proposed renewable energy heating and cooling obligation scheme (HCOS) will therefore provide additional incentives to fuel-switching from fossil to renewable energy mostly at the building level and also at the industrial, currently not sufficiently stimulated by the EU energy efficiency framework. The total intended volume of the obligation should result in 27% renewables share in the heating and cooling at EU level, which is deemed the most cost-effective deployment to reach the at least 27% overall renewables target by 2030 263 .

Level of the obligation

In order to determine the required level of the obligation to reach a cost-effective target of 27% renewables in heating and cooling by 2030, the following methodology was used:

For variant 1, the share of renewables in heating and cooling would have to increase by 5% 264 between 2021 and 2030. Given that 50% of the heating and cooling supply could be exempted; the remaining eligible parties would have to increase their RES-shares by 10% in 10 years, i.e. by 1 percentage point (pp) every year 265 .

For variant 2, the EU as a whole will have to reach 27% renewables in heating and cooling by 2030. Taking into account, on the one hand, early achievers 266 , and on the other hand, exempted parties, the level of the obligation would be 27% by 2030 for each obligated party.

5.2.1.2.    Detailed assessment

Social impacts

Impact on small-scale suppliers

Due to the extremely fragmented nature of the heating and cooling supply across Europe, the mitigation of the impact on small-scale suppliers is one of the priorities when considering the design of different options.

In order to simplify the analysis, our calculation assumes all natural gas suppliers are large-scale and 50% of coal, gas, district heating and biomass are small-scale 267 . Electricity and heating and cooling generation at residential level (solar thermal, geothermal and heat pumps) are not eligible under the obligation schemes. Since option 1 only includes fossil fuel suppliers, the share of potentially eligible parties is lower than in option 2.

In order to minimize the impact on small-scale suppliers, each option introduces the possibility for Member States to exempt parties from the obligation as long as these exempted parties do not exceed a 50% of the heating and cooling supply.

With these assumptions, the heating and cooling supply profile can be broken down as shown on Figure 14 and Figure 15. These figures represent the assumed breakdown of heating and cooling suppliers in terms of shares of total heating and cooling supply.

Figure 14: breakdown of suppliers in H&C (Option 1: fossil fuel only)

268

Figure 15: breakdown of suppliers in H&C (Option 2: all suppliers)

From the figures above, it clearly appears that Option 1 (fossil fuel only) could have a substantial impact on small-scale suppliers, where for some Member States, potentially all or the majority of small-scale suppliers might fall under the obligation 269 .

Considering all of the above, and even factoring in possible exemptions, it is likely that the potential burden of Option 1 would be too high compared with the expected results, therefore this option will not be considered in the rest of the analysis.

On the contrary, Option 2 (all suppliers) could have a more limited impact on small-scale suppliers. Under this option, the most impacted Member States would be Malta and Cyprus, due to a small and oil-dominated market. The overall impact across the EU should however remain limited, all the more as Member States will benefit from a range of mitigation measures, as described above.

Impact on retail prices 270

Another potentially important impact of additional measures in heating and cooling would be the energy prices for households. A first analysis on the expected evolution of energy prices at household level shows an overall increase of energy prices between 2021 and 2030 (around 19% on average 271 - see Figure 16). This increase is partially due to market developments, and partially due to climate and energy policies. In order to insulate the effect of heating and cooling measures, we have to assume constant energy prices from 2021 onwards.

Figure 16: end user energy prices for households (based on PRIMES EUCO27 results)

With this assumption, the overall impact of measures has been assessed by multiplying the energy price by the final energy consumption of household per energy carrier. The positive influence of energy efficiency has also been eliminated, by considering the overall energy consumption of households constant between 2020 and 2030. With these assumptions, the change in fuel mix (assumed to be triggered by measures in the heating and cooling sector) will be the only driver of price evolution. The result is the overall energy expenditures per household as shown in Figure 17.

Figure 17: energy expenditure for households 272

As shown in Figure 17, if prices are assumed constant and if energy efficiency measures are eliminated, the impact of additional renewables on household energy expenditures would remain limited (+ EUR 11/year/household between 2020 and 2030). In this case, the increase of electricity expenditures due to higher electrification is compensated by the decrease in fossil fuel use. However, if we consider an increase in fuel and electricity prices as expected 273 , the impact on household expenditures would be higher, but mostly due to external factors.

Economic impacts

In the absence of a detailed modelling of the heating and cooling supply chain 274 , the economic impacts have mostly been measured assessing the gap between heating and cooling deployment at EU-and Member State-level triggered by the obligation scheme, and cost-effective deployment 275 , outcome of the main scenarios used in this Impact Assessment.

For this assessment, the focus has been on the progression of additional RES-H&C deployment at Member State level (as renewables share in the total H&C consumption) compared to cost-effectiveness, and especially the standard deviation of additional effort in terms of RES-H&C shares at Member State level compared to the central scenario, i.e. how the obligation could divert from a balanced approach across Member States.

The following two figures illustrate the modelled impact of 2 variants of proposed Option 2 of HCOS (option 1 has been disregarded for the reasons stated above). The following options and variants are assessed:

Variant 1 stands for yearly increase of 1% of addition renewables for each supplier by 2030,

Variant 2 stands for universal obligation of 27% renewables share in the total volume of heating and cooling fuel/energy sold to end consumers in 2030.

Figure 18: Renewable heating and cooling shares under the HCOS vs. EUCO27

Figure 19: Standard deviation of additional effort in H&C share at MS level 276

The analysis of the figures above shows that variant 2 (universal obligation of 27% of RES-H&C in 2030 for each supplier) is the most distortive approach. This is explained by the absence of inclusion of any starting point: in variant 2 obligated parties will have to reach 27%, regardless if their share in 2020 is 0% or 20%. Therefore option 2 would be detrimental to suppliers with a low starting point 277 , and variant 1 (gradual increase) will guarantee higher proportionality and cost-effectiveness compared with variant 2.

On the other hand, the impact of variant 1 on early achievers 278 (i.e. Member States that were already above EU average in 2020) would be higher than in option 2. This is explained as the gradual obligation (variant 1) would apply to every supplier equally, i.e. the renewable energy share in heating & cooling would have to increase by 1% between 2020 and 2030 independently from the starting point. On the other hand, a universal obligation (variant 2) would have no effect on suppliers which are already reaching 27% of renewables in heating and cooling. Figure 20 below summarizes this distributional effect.

Figure 20: Sum of additional efforts for early achievers

On the top of it, additional administrative costs may occur, including costs for the management of potential funding programs, motivation campaigns to incentivise RES-H&C installations, costs for audits and verification or costs associated to establishing regional networks delivering RES-H&C installations. Since a certain share of the administration costs are fixed costs that are independent from the size of the obligated company, small companies might have a systematic competitive disadvantage. This fact justifies an exemption for small scale companies. For the variable administrative costs large companies might have a further competitive advantage due to potential scaling effects, e.g. regarding the search for eligible RES-H&C projects.

Environmental impacts

The HCOS have been considered to have no or very limited influence on the rest of the energy system. This assumption allows isolating the impact of the HCOS while every other parameter is being kept equal.

However, a potentially significant environmental impact of the HCOS – together with other measures targeted at renewable heating and cooling – is biomass deployment. Depending on the technologies used, biomass might have potential adverse impacts e.g. on air quality, that should not counterbalance the benefits in terms of renewable energy deployment and GHG reduction. In order to assess the impact of the set of RES-H&C-targeted policy options 279 on biomass deployment, we have used the EUCO27 scenario, which mirrors cost-effective deployment of renewables in heating and cooling at Member States and EU-level.

The focus has been put on the final energy use for heating and cooling demand in the residential sector, given its importance in overall heating and cooling consumption. Figure 21 depicts the potential evolution of the fuel mix used at residential level. The outcome of this analysis is that the biomass use remains constant (and even decreases in absolute terms) between 2020 and 2030, while oil and solid fuel use substantially decrease. This is mostly due to additional energy efficiency measures and overall electrification in the heating and cooling sector. On the top of it, without prejudice to the outcome of the bioenergy sustainability initiative, the remaining biomass used for heating and additional post-2020 might need to comply with enhanced sustainability criteria.

Hence, the overall combined impacts of policies targeting heating and cooling on the environment is expected to be positive.

Figure 21: Final Energy per energy use (Ktoe)
in residential heating and cooling demand – EUCO27 scenario

Source: PRIMES

Political feasibility /opportunity

The subsidiarity is ensured through the freedom left to each Member State to define obligated parties, as long as they encompass a certain share of the heating and cooling supply. For this reason, there will be no EU-wide obligation scheme: each MS will have the possibility to design its own scheme, as long as the design corresponds to the minimum set of common principles defined at the EU level. Also the obligation leaves it up to the Member State/obligated party to choose the most cost-effective measure in its given context, hence the instrument adapts to specific conditions. The possibility for Member States to choose between a range of mitigation measures also allows flexibility at national level and ensures proportionality through the mitigation of impacts on smaller suppliers. However, each option will have different effect on the RES-H&C deployment at MS-level. As assessed in the economic impacts section, variant 2 (universal obligation) has a higher impact at Member State-level than a gradual obligation, especially on Member States with a low starting point in 2020.

Of the options under consideration, it is difficult to see how Option 0 of continuing with current practice should be selected. Given the importance of the heating and cooling sector in reaching the EU target for renewable energy, a measure accompanying the increase in the renewable share in the sector is desirable.

5.2.2.    Facilitating the uptake of renewable energy and waste heat in district heating and cooling systems 

As elaborated in 5.2.1, most of the district heating suppliers at EU-level are considered small-scale, and therefore might not fall under the heating and cooling obligation scheme. This option is therefore considered complementary to the HCOS.

Option 0: Baseline

The RES Directive requirements with regard to RES-H&C are not included in the Revised RES Directive and expire in 2020. Member States decide individually if and how they wish to promote the increase of renewables in the district heating and cooling systems. Financial support, if put in place at national level, will need to comply with State aid rules. Renewable energy technologies will need to compete with fluctuating fossil fuel prices and distortive subsidies for fossil fuels. The obligations under Article 14 EED will remain.

Option 1: Continuation of current requirements, with best practice sharing

The RES Directive requirements on promotion of urban planning and renewables integration in the district heating and cooling infrastructure (e.g. Articles 13(3) to (6) and 16(9) and (11)) are extended to 2030. Best practice sharing on measures facilitating integration of renewables in the urban heating and cooling infrastructure, integration of local electricity and heating and cooling systems and best practice in financing of sustainable urban energy projects is further encouraged.

Option 2: Energy performance certificates and access rights to local H&C systems

The RES Directive requirements on promotion of renewables integration in the district heating and cooling (DHC) infrastructure (e.g. Articles 13(3) to (6) and 16(9) and (11)) would be reinforced and amended, requiring Member States to subject their district heating systems to energy performance assessment 280 thus supporting the energy performance framework developed to support EPBD and RES Directive implementation. A European standard for district heating systems is currently under approval by the CEN 281 . This methodology should be used, to the extent possible, for district heating performance assessment. This performance assessment should be made available to end-consumers.

Open access rights to local heating and cooling systems for residual/waste heat/cold and for producers of renewables heating and cooling (as appropriate also from variable renewable electricity producers especially for balancing purposes) would be established, along with such rights for third parties acting on their behalf (e.g. aggregators, traders). Temporary exemptions could be considered for new district heating or cooling systems with a high energy performance. National Regulatory Authorities would be tasked to oversee access rights. These reinforced provisions would also require Member States to oblige district heating/cooling companies, electricity and gas DSOs and providers of infrastructure for electric mobility (if relevant) to make common investment plans (or consult each other on investment plans). National Regulatory Authorities (NRAs) would be tasked to ensure that investment plans of DSOs and district heating and cooling's are optimised in terms of overall costs, result in increase of renewables and improvement of overall energy (system) efficiency (e.g. by using district heating/cooling systems to help balancing variable renewable electricity production). In case no district heating/cooling is in place, the DSO shall, based on the assessment according to Article 14 EED, analyse the business potential for a district heating and/or cooling network.

Option 3: Option 2 + further reinforced rights for consumers

As described in Option 2. In addition, consumers would have a right to disconnect from the district heating and cooling system if the system's energy performance is lower than what a consumer could achieve by alternative means e.g. renewables on-site or through energy communities formed in neighbourhoods. The comparison should be allowed by disclosure of district heating performance assessment to the end-consumer. This would allow neighbourhoods or individual owners of buildings to take responsibility for their own sustainable heat/cold supply. Reinforced provisions would propose a strengthened role of NRAs in ensuring that renewable and waste heat based suppliers have non-discriminatory access to the district heating/cooling network and the protection of consumers, in particular in relation to connection to and disconnection from networks. Consumers would have the right to fair and competitive prices/tariffs in line with the potential energy performance of the system while incentivising investments in highly efficient district heating and cooling and fuel switching from fossil to renewable energy.

5.2.2.1.    Introduction to the assessment

District heating and cooling represent around 8-10% of the total H&C energy supply, out of which around ¼ are renewables 282 . The situation varies substantially across Member States, as illustrated by Figure 22.

Figure 22: District Heating and renewables in the EU 283

Option 0 relies on the Directive on Energy Efficiency 284 , which requests Member States to carry out, by 31 December 2015, a comprehensive assessment of the potential for efficient district heating and cooling, which is defined as ‘a district heating or cooling system using at least 50 % renewable energy, 50 % waste heat, 75 % cogenerated heat or 50 % of a combination of such energy and heat". These assessments need to be updated every five years and Member States are requested to include strategies, polices, and measures to realise the potential.

The rationale for option 1 to 3 is to support action at EU-level. The rationale for option 1 is to allow for collaboration and information sharing among Member States regarding the opportunities to support higher shares of renewable energy and waste heat in district heating and cooling systems. For option 2 and 3, the rationale is to develop an enabling framework for consumers and energy suppliers that would complement the provisions of the EED by allowing effective fuel-switching at district level.

Figure 22 shows the large variations across Member States in terms of heating and cooling shares in the district heating sector. Based on market shares of district heating and cooling and the level of renewables in district heating and cooling, Sweden, Denmark, Finland and the 3 Baltic States are frontrunners in renewables deployment in the district heating and cooling. On the other hand, a number of Member States have less than 5% of renewables in their district heating and cooling systems.

Option 1 is a continuation of the current requirements upon Member States to assess the need to build new infrastructure for renewable district heating and cooling in their national renewable energy action plans and provide guidance to relevant actors to consider the optimal combination of renewable energy resources, including those provided through district heating and cooling, in the planning, design, building and renovation of industrial or residential areas. As outlined in the EU strategy on Heating and Cooling 285 , option 1 could be strengthened by promoting sharing experiences and best practices across Member States, support for local authorities in preparing strategies for heating and cooling, and setting up a website with price comparison tools on lifetime costs and benefits of heating and cooling systems. Some small initiatives to exchange best practices are already on their way 286 .

Option 2 consists of the introduction of district heating and cooling Energy Performance Certificate compliance requirement and creating open access rights to local district heating and cooling infrastructure. The rationale is that district heating and cooling network infrastructure provides an opportunity to integrate heating and cooling from independent renewable energy producers (incl. biomass, geothermal, solar thermal), waste heat from industry and municipal waste, renewable electricity (through heat pumps), in a flexible way. Furthermore, flexible district heating and cooling systems provide a cost-effective option to integrate the heating and cooling sector witht he electricity sector. Requirement for district heating and cooling system operators to certify the energy performance of their district heating system, using a CEN standard 287 , will provide additional incentives to district heating and cooling system operators to improve the energy performance and reduce the CO2 emissions from their district heating system, through improved system efficiency and higher share of renewables in the district heating and cooling fuel mix.

The requirement of district heating and cooling energy performance certificates for district heating and cooling operators would be particularly relevant for improving the overall energy system efficiency and promoting circular economy by engaging independent renewables and waste heat producers, industry and industrial clusters located in vicinity of urban areas with high heating and cooling demand. Industrial clusters often foresee energy efficiency and renewable energy programmes as part of overall sustainability and circular economy objectives. The requirement for district heating and cooling operators to certify their district heating and cooling systems, based on standard methodology included in the CEN standard for district heating and cooling energy performance 288 that is currently in approval stage, would contribute to increased competition on the local heating and cooling markets and provide transparent and comparable data on energy performance of district heating and cooling systems, enabling households and industry to make informed choice on most appropriate energy solutions for their heating and cooling needs.

District heating and cooling energy performance certificates would also provide the financing sector with a benchmark to support the upgrading, expansion or construction of the most efficient district heating and cooling systems. This would also complement the national strategies for efficient district heating and cooling developed under the energy efficiency directive, by providing more granular data on the opportunities for increasing the share of renewables at a local level.

Option 3 would support a more active role of consumers in promoting high shares of renewable energy in district heating and cooling through consumer right to compare the district heating and cooling energy performance data (based on district heating and cooling energy performance certificates) with building level energy performance certificates, and disconnection rights from district heating and cooling at building level. This option is relevant for incentivising the competition between most efficient energy performance solutions at the energy system or building level. Such competition is increasingly relevant as consumers are encouraged to invest in local renewable heating solutions, such as solar thermal systems, wood-pellet systems or heat pumps, under the energy performance of buildings directive 289 . These local solutions could be complemented with renewables-based district heating and cooling systems to provide additional flexibility.

5.2.2.2.    Detailed assessment

Economic impacts

Given the fragmented markets of the district heating and cooling supply in Member States, the main concern regarding potential economic impacts will be the effect of the options on small-and medium-scale suppliers and the overall cost-efficiency and business case for district heating investments . While option 1 would leave progress up to the discretion of local and regional administrative bodies, options 2 and 3 might affect local district heating and cooling suppliers and district heating and cooling system operators, either through the integration of new generation (technical adaptation costs, competition between independent producers and incumbent district heating companies and owners of the district heating and cooling network, business case for new investments and upgrades of existing district heating and cooling networks) under option 2 or through potential disconnections (loss of revenues, questionable incentives for investments) under option 3.

Regarding the integration of new generation, considering the rather long lead times for planning and licensing new district heating and cooling systems and high upfront investment costs, in the short-term the impact of the measure would be restricted to existing district heating and cooling systems which make up for about 10-15% of the current European heat market for buildings in the residential and service sector while the corresponding market share for the industrial sector is about 9%. Assuming that the measure would trigger the renewables increase in existing district heating and cooling systems to be increased by 20 % roughly in 10 years, additional 2 Mtoe RES-H&C would enter the heating and cooling market by 2030 290 .

Regarding potential disconnections, the estimate of the potential impact of introducing a district heating and cooling disconnection right is mainly based on data provided by Fraunhofer ISI et al. (2016), Eurostat and Euroheat&Power, although there are considerable differences between the figures provided by these sources. 291  

According to Fraunhofer ISI et al. (2016) in 2012 district heating and cooling was contributing about 480 TWh to the final energy demand in the heating sector, corresponding to a district heating and cooling share of about 7.6% of the total heating and cooling market 292 ;

According to Eurostat in 2013 about 28% of all district heating and cooling was produced by heat only plants while the remaining 72% were contributed by CHP;

According to Fraunhofer ISI et al. (2016) 53% of the total capacity of CHP plants > 1 MWth was installed before 1992 while 26% of the capacity was installed between 1992-2002 and 21% after 2002.

Since no data is available on how different district heating and cooling systems can be distributed among different efficiency categories (incl. the efficiency of production in the heat only and CHP plants as well as the efficiency of the distribution) and the CEN methodology only provides a standard calculation methodology, but does not include minimum energy performance thresholds, we need to do an assumption on how many district heating and cooling systems would fall in the category of low performing district heating and cooling systems and could thus be affected by wave of disconnection requests. For reasons of simplification we assume that all heat only plants and all CHP plants that have been installed before 1992 (these plants are now older than 24 years) would underperform. This would correspond to a maximum disconnection potential in the range of 320 TWh.

If we further assume that per annum about 1% of all customers that are connected to district heating and cooling systems that underperform will use their right to disconnect in favour of a more efficient decentralised heating system, in the first year in principle a heating and cooling volume of about 3.2 TWh could potentially be open to be replaced by on site-building level RES-H&C solutions. Between 2020 and 2030 this potential would sum up to 32 TWh.

If we finally assume that about 25% of all disconnected costumers will decide for a RES-H&C technology (e.g. a heat pump or wood pellet boiler instead of a gas or fuel oil boiler), this would result in additional RES-H&C of about 0.8 TWh (= 0.07 Mtoe) in the first year. Between 2020 and 2030 this would sum up to 8 TWh (0.7 Mtoe) additional RES-H&C compared to a scenario without disconnection right 293 .

The total estimated ratio of such disconnections shall therefore remain below 2% of total district heating supply in the EU, which is deemed limited at the EU level, but could vary significantly at the Member State level. Higher disconnection risk and impacts could be expected in those Member States that proportionally have higher district heating and cooling market shares and lower energy efficiency of such systems 294 . In comparison, district heating and cooling networks will be proportionally more affected by the reduction in final heat demand that have been envisioned under the EED. The creation of flexible district heating and cooling systems is therefore important for both the future of district heating and cooling systems as well as renewable energy integration.

To conclude, the much higher economic impacts and higher upfront investment costs on district heating operators are therefore assumed due to integration of renewable generation at district level (option 2 and 3) rather than from the possible fuel-switching and therefore loss of revenue form the disconnected district heating and cooling customers. However, the magnitude of this impact shall be counterbalanced by the positive effects at energy consumer level, most notably in resulting reduction in heating and cooling prices and enhanced energy consumer choice and possibilities to require better quality service.

Social impacts

In a number of Member States, more than 50% of the citizens are connected to district heating and cooling systems 295 . At the same time, low awareness of alternative RES-H&C systems and lack of transparent and comparable data and energy performance indicators of such systems with district heating and cooling energy performance prevent energy consumers and other relevant stakeholder groups such as installers, builders, architects from making informed choices on best performing, most suitable and least cost heating and cooling solutions. Options 2 and 3 would engage both potential suppliers of heat and consumers, and provide them with the relevant information to make informed decisions about the use of district heating and cooling to support higher shares of renewable energy. Availability of transparent energy performance data will become increasingly important as district heating and cooling network systems move towards higher flexibility and integration within the overall energy system, integrating multiple renewable heating sources, and residual heat and renewables electricity from buildings. Option 3 will also enable consumers at building level to make a choice between producing their own renewable energy at the building level or relying on efficient and renewable energy based district heating system.

In cities, the planning of key infrastructure is rarely coordinated with other urban planning aspects that could be used to deploy renewable energies and energy efficient heating and cooling, e.g. when building refurbishment programmes are implemented and/or new district heating and cooling and electricity distribution system investments are being undertaken. Sustainable energy programmes targeting the decarbonisation and energy efficiency of buildings and the heating and cooling supply are often overlooked during the urban planning and design phase. Also decisions on investments in infrastructures and buildings at municipal or commercial levels may take place in an isolated manner without any consideration of the feasibility of long term sustainable solutions and without performing a life cycle cost analysis to assess the long-term cost-competitiveness of a portfolio of options. In addition, new built and refurbishment rate of buildings are low, around 1% and 1.4% per annum, respectively, which is not conducive to a more rapid diffusion of these technologies.

Environmental impacts

The proxy used to measure the potential environmental impact is the influence on RES-H&C deployment. The main trigger to enhance RES-H&C deployment is the disconnection from fossil-fuel based district heating and cooling to individual renewable solutions.

One other potentially significant environmental impact is the effect of measures targeted at renewable heating and cooling on additional biomass deployment. The assessment of the overall combined impacts of policies targeting heating and cooling on the environment has been presented in 5.2.1.2.

Political feasibility /opportunity

Option 0 has no additional administrative burden, and Option 1 could actually make the accounting requirement at a Member State level more efficient by disseminating the information to the relevant stakeholders.

Options 2 and 3 would rely on the requirement for district heating and cooling system operators to certify their systems based on standard CEN methodology. Obtaining such energy performance certificates and regularly renewing them will result in compliance costs for establishing such certification scheme and carrying out regular system audits. However, there are possible synergies in linking the energy performance certification with existing systems for energy performance certificates for buildings. This would substantially reduce the administrative burdens.

Of the options under consideration, Options 0 and 1 should be discarded, as they would have a negligible to minor impact on the effort to make district heating and cooling part of the cost-efficient renewable uptake leading to 2030 EU-wide target.

5.2.3.    Overall comparison of the options to increase renewable energy in the heating and cooling sector (RES-H&C)

5.3.Options to increase renewable energy in the transport sector (RES-T)

The table below provides an overview of the options discussed in this section.

5.3.1.1. Introduction to the assessment 

The baseline scenario (REF2016) shows that national action alone will lead to some deployment of renewable fuels in the transport sector which will be, however, insufficient to reach the EU 2030 RES target and the 2050 decarbonisation objective. National measures cannot guarantee market volumes that are sufficiently large to both achieve economies of scale and spur manufacturing innovation to further lower the costs. The introduction of a binding measure at EU level is more likely to create such a market pull, while ensuring that the costs of technology innovation and development are sufficiently shared across European economies and market fragmentation is avoided.

The promotion of renewable energy in the transport sector can be pursued through two alternative policy instruments:

A renewable energy incorporation obligation, such as those introduced already by 25 Member States in order to meet the 10% renewable in transport target set by the RES Directive. According to the REFIT evaluation report, the 10% target has been very effective to increase the share of renewable energy in the transport sector which reached 5.9% in 2014.

A GHG emission reduction obligation, such as the one implemented thus far only by one Member State (i.e. Germany) in order to meet the Fuel Quality Directive requirement, according to which Member States shall require fuel suppliers to reduce the GHG intensity of the fuel they supply by 6% in 2020.

In the public consultation on the revised renewables Directive, the majority of stakeholders expressed the view that energy obligations are effective, or very effective, in promoting renewable fuels in transport and in increasing the uptake of electric vehicles. NGOs did not support an incorporation obligation including conventional biofuels. Furthermore, a number of industrial stakeholders and Member States highlighted that, in the period after 2020, the increase of low-carbon and renewable energy in transport should be promoted through only one EU-wide policy instrument, with the view to avoid double regulation and minimize administrative burden.

In this Impact Assessment, apart from option 0 (baseline) which is common to both instruments, options 1, 2 and 3 would be implemented through the Revised RES Directive, while option 4 would be implemented through the revised FQD approach.

Description of identified policy options

Option 0: No additional EU action (Baseline)

This Option foresees that the 2030 EU climate and energy targets are achieved. The renewable transport target expires in 2020 and so it does the double-counting rule, currently applied to electric vehicles and advanced bio-fuels. The 7% cap for contribution of food-based biofuels in the overall national renewable "contribution" continues. Similarly, the FQD GHG intensity reduction target would not be prolonged post-2020. Member States would decide individually if and how to promote renewable energy in transports, in compliance with the relevant EU state aid rules. The EU biofuels sustainability criteria continue to apply post-2020. The EU research and innovation policy would continue to support non-mature technologies, along with national programmes. This option is described by the EUCO30 scenario (see Annex 4).

Energy-based policy options (1-3)

Option 1: EU incorporation obligation for advanced renewable fuels

Option 1 foresees the introduction of an EU-level incorporation obligation, whereby Member States oblige fuel suppliers to include a minimum share (e.g. 4% by 2030 296 ) of renewable fuels, including advanced biofuels, renewable electricity use din road transport and CCU and e-fuels in the fuels they place on the market 297 . As fuel suppliers would be best suited to supply electricity at the pump or along roads the contribution of renewable electricity is limited to road vehicles charged at publically accessible charging points. The obligation would increase over time and would be tradable. In case of non-compliance, Member States would apply financial penalties on fuel suppliers. In order to support advanced biofuels and electro-mobility, technology banding would be applied 298 . Apart from the 7% cap and the sustainability criteria, policy on food-based biofuels would be left to the Member States.

Option 2: EU incorporation obligation for advanced renewable fuels plus phase-out of food-based biofuels

Option 2 would imply an EU-level incorporation obligation for advanced renewable fuels that is structured in the same way as Option 1 but would ensure the gradual replacement of food-based biofuels by an annually decreasing cap. This option includes three variants:

A.Partial phase-out: the cap for food-based biofuels is gradually reduced to pre-2008 level, by 2030.

B.Full phase-out: the cap on food based biofuels is reduced to zero by 2030.

C.Hybrid approach: option 2A plus a faster phase-out of vegetable oil biofuels and a higher GHG savings threshold (e.g.70%) for new biofuel installations, respectively in order to reduce ILUC emissions and increase direct carbon savings. Furthermore, the existing EU sustainability criteria are streamlined and improved 299 .

Option 3: Option 2 plus a specific incorporation obligation for advanced renewable fuels suitable for aviation and maritime

Option 3 would consist in Option 2 plus a specific EU-level incorporation obligation on renewable fuels consumed in aviation and maritime such as biokerosene and biomethane  300 . These sectors need a dedicated approach given that it is more costly and complex to replace fossil fuels.

Emissions-based option (4)

Option 4: GHG emission reduction obligation

Option 4 would imply a continuation of the current approach of the FQD where Member States oblige transport fuel and energy suppliers to reduce the GHG intensity of the fuel and the energy they supply 301 . After 2020 a narrower approach would be taken to the fuels that are supplied, with different variations (described below) depending on which objective is maximised. Under all of the variations Upstream Emissions Reductions (UERs), LNG and CNG would be excluded.

a)Option 4 A: No additional EU policy (same as option 0);

b) Option 4 B: Continue the approach of the current FQD, supporting liquid and gaseous fuels and electricity. 

This option consists of continuing the current approach of the FQD while narrowing the focus by excluding the contribution of lower GHG fossil fuels and Upstream Emissions Reductions (UERs) 302 .

c) Option 4 C: Continue the approach of the current FQD with a focus on advanced fuels and electricity.

These options seek to maximise the achievement of objectives on driving innovation, supporting the uptake of electric vehicles and avoiding ILUC. They seek to maximise the support for innovation and electrification by focusing the mandate on 'advanced fuels' as defined by Annex IX(a) of the RES Directive (as amended by the ILUC Directive), including electricity. Three sub-options were assessed, 4C1, with a 2% GHG reduction and 4C2 and 3 which have a 2% GHG reduction but also allow Member State levels mandates for food based biofuels at 6% or 3% respectively. Within these options, option 4C3 was selected as the preferred option as 4C1 was too restrictive, while 4C2 allowed a very high contribution of crop biodiesel with high ILUC risks.

d) Option 4 D: Continue the approach of the current FQD with a focus on advanced fuels, electricity and low GHG first generation fuels when ILUC impacts are taken into account.

These options seek to maximise the achievement of objectives on driving innovation, supporting the uptake of electric vehicles and avoiding ILUC by focusing the mandate on 'advanced fuels' as defined by Annex IX(a) of the RES Directive (as amended by the ILUC Directive), including electricity and on those biofuels from food crops believed to have the lowest ILUC emissions, i.e. crop ethanol, while biodiesel is excluded. 4 D1 has a 2.5% overall GHG reduction target, 1.6% GHG reduction sub-target for advanced fuels, while 4 D2: 3% overall GHG reduction target, 2.3% GHG reduction sub-target for advanced fuels. 4D2 was selected as the preferred option as it has a higher level of ambition which is needed to drive the uptake of advanced fuels.

5.3.1.2. Detailed assessment

The following modelling tools have been used to assess the impacts of energy-based policy options 0, 2 and 3 (see further information in Annex 4):

The PRIMES model was used to model impacts of options 0, 2 and 3. Option 1 was not quantitatively modelled as the outcome would depend on the policy choices of the Member States regarding food based biofuels. PRIMES is an energy model used for modelling all policy elements of the RES Directive included in this Impact Assessment and also e.g. Market Design Initiative and Energy Efficiency Impact Assessments.

The GLOBIOM model 303 was used for assessing the ILUC impacts of the sub-Options 2A and 2C e.g. a gradual or full phase out of conventional biofuels. GLOBIOM is a global recursive dynamic partial equilibrium model with a bottom-up representation of agricultural, forestry and bioenergy sectors used also in the Impact Assessment on Bioenergy Sustainability.

Bespoke analysis undertaken by the ICCT 304  was used to assess the impacts of Option 4 based on a GHG saving obligation.

Due to the significant differences in the assessment tools and underlining assumptions, the results are not directly comparable and therefore the impacts of options 0 to 3 (energy obligation) are presented separate from the assessment of option 4 (GHG reduction obligation).

Energy impacts of options 0 to 3

Under Option 0, by scenario construction, advanced biofuels would reach a 1.9% share of all liquid and gaseous fuels by 2030, compared to approx. 1% in 2014 305 . Under Options 2A, 2C and 3 (gradual phase out of food-based biofuels), advanced biofuels would reach respectively approximately a 4.0% share by 2030 (approximately 12 Mtoe). This would represent a significant increase compared to the projected level in 2020. Option 2B (full phase out of food-based biofuels) would require a quite significant growth in the deployment of advanced biofuels, which would increase to 21 Mtoe to reach a share of 6.8% of all liquids and gaseous transport fuels by 2030.

The share of biofuels has a direct impact on the amount of oil products consumed in transport. A decrease in oil imports of almost 2.0% is projected under the energy-based Options 2A, 2C and 3 and 0.9% under Option 2B. While renewable fuels can be both produced in Europe and imported, the economic modelling indicates high potential for the domestic production of ligno-cellulosic stocks used for advanced renewable fuels. As oil prices are assumed to grow steadily in a long-term perspective, savings in oil consumption would have increasingly beneficial effect for the European economy.

Table 5: Impacts on EU energy demand of options 0-3

Source: PRIMES, 2016

Energy impacts of option 4

Figure 23 shows the share of renewable fuels under option 4 according to the ICCT analysis. The 4C sub-option examines the impact of a focused advanced fuel target at EU level, with and without Member State mandates that would support biofuels from food crops. The different sub-options of 4D examine the impact of supporting biofuels with lower ILUC emissions. These options exclude crop-based biodiesel but allow crop-based ethanol. As a result both options show a significant proportion of advanced fuels and electricity.

Figure 23: Share of total road transport energy by alternative fuel type under option 4

Environmental impacts

The environmental impact of the policy options is assessed according to their Climate performance taking into account both direct emission savings and indirect effects

Direct GHG emission impacts of options 0 to 3

Table 6 shows the impacts on WTW GHG emission savings of options 2 and 3, compared to the baseline. Options 2A, 2C and 3 have similar direct GHG savings (around 1.5% reduction compared to the baseline). This is due to the same overall share of biofuels.

Option 2B (rapid phase out of food based biofuels) has a lower share of biofuels. However this option still leads to under 1% reduction in direct GHG emissions compared to the baseline due to higher savings of advanced biofuels (in production and processing).

Table 6: Direct GHG emissions (% change vs EUCO30 scenario) 306

Source: PRIMES

Indirect GHG emission impacts of options 0 to 3

The Table below and Figure 24 show the GHG emission impacts of Options 2A and 2C (gradual phase out of all food based biofuels and biodiesel respectively), compared to option 0 (baseline) 307 , as modelled by GLOBIOM 308 . The results indicate that maintaining food-based biofuels at the level of 2020 as projected in Option 0 would not address ILUC as it would cause additional emissions even after 2020. These emissions mainly come from peatland which was drained to produce palm oil in order to satisfy the additional feedstock demand stemming from biodiesel production. Production of palm oil on this land will continue to cause massive carbon emissions as, due to the drainage of the land, the soil itself, the peat, is slowly s oxidising. This effect would risk eliminating all GHG emissions achieved by biofuel production.

In contrast Option 2A (gradual phase out of food based biofuels by 2030) can significantly reduce ILUC emissions lowering the average ILUC factor from 64 to 27 g gCO2/MJ. After 2020, ILUC impacts associated to peat land oxidation and natural vegetation conversion could be expected to cease. However, the balance of emissions remains positive due to lower carbon sequestration as result of less palm plantations (which mirrors the increase before 2020). Still, under this scenario the phase down of conventional biofuels would avoid unintended effects associated to biofuel growth, while resulting in significant direct GHG savings.

Option 2 C could be even more effective in addressing ILUC than Option 2A as it involves a more rapid phase out of vegetable oil based biofuels – associated with the highest ILUC emissions. It would reduce the average ILUC factor from 64 to 17 g gCO2/MJ. In addition, this option implies a 70% GHG emission savings target for new installations – that, with a few exceptions, only advanced biofuels will be able to comply with.

The full phase out of food based biofuels under option 2B is projected reduce ILUC emissions further, as it would make additional land available to meet the growing demand for food and feed stemming from other sectors. However, the effect can be expected to be less pronounced as not only biodiesel, but also bioethanol (with much lower ILUC emissions) would be phased out. Furthermore, it should be noted that the amount of indirect emissions will also depend on the scale of biodiesel consumption in EU. Smaller quantities can be expected to result in lower indirect land use change impacts because they can be met largely through domestic feedstock, while with increasing demand more imports are necessary and the related ILUC risks increase.

Finally, it should be noted that a GHG emission reduction obligation (that incentivises operators to maximize direct emission savings) could have the unintended effect of promoting the use of those biofuels that also have very high ILUC impacts. This would be the case of palm oil biodiesel which has higher direct GHG savings than, for instance, rape seed biodiesel (62% compared to 45%) but it is associated with much higher indirect GHG emissions 309 .

Table 7: ILUC effect of options 0, 2A and 2C

Figure 24: Cumulated GHG emissions of phase out of food-based biofuels
(2008-2020, 2020-2030, MtCO2eq) 
Source: GLOBIOM

Direct and indirect GHG emission impacts of option 4

The relative GHG impacts of Option 4 and related sub-option are shown in Figure 25. No dedicated GLOBIOM model runs were undertaken for this policy Option, instead the feedstock specific ILUC factors obtained from the GLOBIOM study (Valin et al. 2015) were used. These have been presented in order to demonstrate the relative GHG impact of the Option 4 sub-options. These ILUC factor values were derived by determining the increase of ILUC emissions that result from an increase of biofuel consumption by 1% against the 2008 baseline (3.2% biofuel use in the EU). It should be noted, however, that this simplified approach assumes that the scale of production has no effect on the ILUC risk, e.g. that replacing 1% of transport fuels with food based biodiesel has the same effect as increasing the share from 3% to 4%.

In each scenario under Option B, the GHG reduction targets and reportable reductions would be fairly high (4-7%), but a much lower GHG reduction would be achieved when accounting for ILUC due to the very high estimated ILUC emissions associated with using oil crops for biofuel.

In contrast, the scenarios under sub-Options 4.C and 4.D, which exclude crop biodiesel, would deliver real GHG savings similar to or above their targets of 2-3%. In sub-Options 4.C2 and 4.C3, actual GHG reductions achieved would be higher than reported under the FQD because national mandates would contribute some GHG savings through conventional biofuels. If first generation fuels are included in the same target as advanced fuels, competition with first generation fuels may to slow investment in the advanced fuel industry. Option 4D3, which includes a sub-target for advanced fuels, would help mitigate this uncertainty.

Figure 25: GHG impacts of sub-option 4 (% difference to the GHG reduction target, 2030) Source ICCT 2016

Economic impacts

Economic impacts include investment costs which need to be compared against the savings on fossil fuel imports. Additional economic impacts can result from the impact of the policy options on global fuel prices.

As shown in Table 8 Options 0 to 3 will require significant increase in investment in advanced biofuels and construction of a sizable number of bio-refineries across the EU. This will also lead to an increase in capital costs. The unit capital cost of such bio-refineries is higher than that of conventional ones. However, increased production of advanced renewable fuels drives a reduction in the unit capital costs of these installations over time, as a result of learning effects.

In particular, given that advanced facilities have higher capital costs than conventional facilities, Option 2B (full phase out of conventional biofuels) would lead to the highest additional (compared to the baseline) capital costs, in the range of €1.5 billion per year. This would correspond to the installation of 200 additional advanced biofuel plants, assuming an annual production capacity of 100 Ktoe 310 . For Options 2A, 2C and Option 3 (gradual phase out of conventional biofuels) additional investments costs are reduced by more than 40%, down to € 0.9 billion/year.

Table 8: Annual capital costs (€ billions/yr) and capacity needs (Mtoe/yr)

Source: PRIMES

Impact on fuel prices of options 0- 3

Table 9 shows the impacts on fuel prices of the Options 0 to 3. Option 2B would result in the highest fuel costs in 2030 due to the significantly higher share of advanced biofuels, which are assumed to remain significantly more costly in the medium term (2030) than food based biofuels. On the other hand, the price increase is lower in Options 2A and 2C, reflecting a more gradual phase out of conventional biofuels. All scenarios show that, the fuel costs in Options 2 and 3 decline by 2050, compared to the baseline (as the learning effects lead to lower costs of advanced biofuels).

Under Option 3, jet fuel prices slightly increase in 2030 due to the higher cost for bio-kerosene, that fuels suppliers would be obliged to incorporate. In return the increase in costs for petrol and diesel (which include costs for blended biofuels) is less pronounced. By 2050 kerosene prices decrease in all scenarios compared to the baseline due to the fact that bio-fuels enable to avoid purchasing of ETS emission allowances which price is projected to grow steeply in all decarbonisation scenarios. Furthermore, it can be observed that the decreasing prices of feedstocks for bio-methane over the long term would also contribute to offset the initially higher fuel prices in the heavy duty and maritime sectors.

Table 9: Fuel price impacts (% changed to the baseline)

Source: PRIMES

Impacts of fuel prices of option 4

The relative costs of option 4 and its sub-options are shown in Figure 26. These costs represent the difference in fuel price between alternative fuels and fossil fuels (petrol and diesel) for the entire volumes that would be achieved in each scenario.

This analysis assumes that operating costs are higher for advanced facilities compared to conventional facilities – partly due to the costs of higher employment. Major cost savings of advanced facilities compared to conventional facilities are related to lower fuel costs compared to conventional biofuels and to a credit for valuable co-products from advanced processes (e.g. lignin). While cost estimates assume technological improvements that reduce the cost of advanced biofuel production over time, it should be noted that cost estimates for the year 2030 are used in this analysis.

Figure 26: Relative total costs of option 4 (relative to the policy baseline A, euro billions)
Source ICCT0 2016

Social impacts

Employment impacts of options 0 to 3

As the models used are not covering employment impacts, the following analysis is qualitative.

Employment impacts include direct impacts in biofuel generators and supporting industries (e.g. engineers and plant operators, employees in marketing and distribution of biofuels, researchers and technology developers of technology and innovation, etc.), and indirect impacts in agriculture and forestry for feedstock production (farmers and forestry workers, etc.).

In 2014, the European conventional food-crop based biofuels industry had a turnover of EUR 13.4 billion and work force of around 110,000 jobs (direct and indirect) 311 . These job levels could be maintained under Option 0 as the production of conventional biofuel can be extended to continue unchanged. Option 2B (full phase out of food based biofuels by 2030) could lead to losses in direct jobs in conventional biofuel production in the short term. However, a transition from food based to advanced biofuels could lead to the creation of new jobs and economic activity in the production chain of advanced biofuels. Under Option 2A and similarly options 2C and 3 (a partial phase out of food based biofuels), any potential job losses in the food-based biofuel sector could be lower, and may not occur, as there would be more time for industry to re-structure.

When assessing the employment impacts of the phase out of conventional biofuels, one important element to be considered is the feasibility of converting a part of the current production capacity to produce advanced biofuels. Significant synergies for bioethanol sites exist through co-location of the new separate second generation plant adjacent to the first generation facility and through retrofitting by altering an existing first generation production line for producing advanced alongside conventional biofuels. In this way, existing jobs are preserved and new jobs are created while generating 40% CAPEX savings which represents roughly a 20% total cost reduction.

On the contrary, fewer synergies for biodiesel sites exist as the retrofitting of renewable diesel HVO sites to ones using second generation feedstock is less attractive. Moreover, integration of first and second generation biodiesel sites faces a rather limited technical feasibility.

Employment impacts of option 4

Table 10 shows the employment impacts of option 4 as calculated by ICCT. This table presents permanent direct jobs that would be supported by alternative fuel production under the various sub-options. 312 . In all scenarios, most jobs that would be supported by alternative fuel policy are in feedstock production and collection, with fewer permanent jobs supported in facility operation.

The cultivation of food crops tends to require more labour than collection of crop residues. However, cellulosic feedstocks such as wheat straw that are used for biofuel are much more likely to be produced entirely in the EU, supporting EU jobs. We note that the number of feedstock production jobs in Option 4B1 (152 000) is fairly close to the number (190 000) predicted in a JRC study modelling a similar biofuel scenario 313 . 

Table 10: Employment impacts of option 4 (1000, 2030), Source ICCT 2016

Source ICCT 2016

Impacts on rural development

The impact on rural development depends on trends in demand and supply of agriculture feedstock. It should be noted that in 2015, 61 % of oilseed and 3.7 % of cereal cultivated in the EU were used for the production of conventional biofuels. In the same year, 13% of domestic sugar beet was used for the production of ethanol, of which virtually all was used for biofuels 314 . A complete phase out of food-based biofuels by 2030 is expected to have significant impacts on the rape seed production which would decline substantially and also sugar beet producers would also be impacted negatively. On the contrary, impacts on cereal producers are expected to be limited, given that only a fraction is used for the production of biofuels and the impact of European bioethanol production on commodity prices is very limited (1-2% impact on cereals prices 315 ). Positive impacts are expected from the production and mobilization of feedstocks for advanced biofuels (including wastes, energy crops and lignocellulosic material). 

On the other hand, it can be expected that a more gradual reduction of crop-based biofuels would allow the European agricultural sector to adjust, for instance, by shifting crops and by changing rotation plans, as well as through increase in production of lignocellulosic feedstock from dedicated energy crops (e.g. miscanthus or short-rotation coppice), provided that existing information and technical barriers are overcome.

Impact on third countries

Impact of third countries depends on how the policy options would biofuels/feedstock international trade flows. It is estimated that in 2014 the EU consumed between 1.6 and 3.2 Million tonnes of palm oil for its biodiesel production, corresponding to a share between 2.7% and 5.3% of the global palm oil production in the same year. Under REF2016, net EU imports of vegetable oil, mostly palm oil, are projected to amount to 2 Mtoe by 2030. This would correspond to approx. 20% of all vegetable oil used for biodiesel production in the EU in that year.

Under option 2B (full phase out), these imports of crop-based biofuels are expected to be discontinued, with resulting negative impacts in the short term on trading partners in Latin America (Argentina, Brazil) and Asia (Indonesia, Malaysia). On the other hand, a more gradual reduction of crop-based biofuels would allow the agricultural producers in third countries to adjust to the new market reality.

Administrative burden

It is expected that the administrative burden for public authorities would be similar for an energy based obligation and a GHG based obligation. However, the majority of Member States 316  has already introduced energy based incorporation obligations to promote renewable transport fuels along with other support mechanisms, such as tax measures. Therefore, the administrative changes and additional burden stemming from an EU-wide obligation would be somewhat limited because it would be implemented by the same public authorities that are currently implementing national measures.

Under the FQD Member States are required to implement a GHG emission reduction obligation before 2020, although so far only Germany has implemented it. In any case both options would be implemented by the Member States in a similar manner. Differences would mainly affect the economic operators. Furthermore, reporting requirements under the Fuel Quality Directive with regards to reporting on fuels origin and place of purchase will be streamlined and overlaps with other existing reporting requirements will be avoided.

Options 1 to 3 are expected to reduce the administrate burden for economic operators operating across the EU. Under these options, producers of advanced biofuels could simply apply default values to demonstrate compliance with the sustainability criteria avoiding an excessive administrative burden.

Under a GHG emission reduction obligation –which incentivises the calculation of the actual emission savings– significant simplifications could be obtained by a modification to the EU GHG calculation methodology. For instance, the option to calculate actual values could need to be limited to those parts of the life cycle – chiefly processing and transport – that can be effected by the biofuels producers.

Changing the methodology, however, could be criticised as the pre-calculated values would not reflect the situation in different regions or countries and economic operators could no longer adjust the figures according to their individual situation. As some types of feedstock are grown exclusively or mainly in Third countries, assumptions on the related emission could be challenged in the context of international trade obligations. Furthermore, a simplification could also have an impact on the feasibility of the current GHG emission savings thresholds.

Subsidiarity assessment

Implementation of an obligation on fuel suppliers is justified by the competence the EU has in the field of energy and climate policy. The political will of the Member States to act collectively on this matter was confirmed in the conclusions of the October 2014 European Council which established new energy and climate targets including a binding EU target for renewable energy of at least 27% by 2030.

A minimum EU wide energy based supply obligation for advanced renewable fuels is such a measure that promotes the increase of renewables in the transport sector, thus contributing to ensure that the binding renewable target is met. Given the environmental impacts of food-based biofuels, their contribution to the EU 2030 renewable energy target would be capped to a maximum of 7% of transport fuels. However Member States could set lower caps in case they wish to do so.

5.3.1.3. Overall findings

As discussed in the above analysis, both the RES Directive and FQD could contribute to the objective of increasing the share of renewables in transports and help decarbonizing this sector, albeit in a different way.

One first policy choice concerns the cap on food based biofuels for the period after 2030 as a means to address ILUC emissions. This includes a complete phase out by 2030, or a partial phase out. The analysis above points to the following considerations:

oUnder the same decarbonisation ambition, a complete phase out of food crop biofuels by 2030 would require high shares of advanced biofuels and other renewable fuels and would likely require significant increased public support in order to deliver the needed technology and economic development in the advanced biofuel industry.

oReducing the share of food-based biodiesel by 2030 combined with a higher GHG emission saving threshold and measures to incentivise advanced fuels would be effective for reducing ILUC emissions and promoting higher direct savings.

oA complete phase out of food based biofuels by 2030 would primarily lead to job losses in the production facilities, particularly in the biodiesel sector where there are lower synergies between conventional and advanced biofuel production technologies. These losses could be compensated by increased employment in the production of advanced biofuels, although the net impact is uncertain.

oThe impacts on indirect jobs in agriculture and forestry are also uncertain, with some modelling suggesting potential positive impacts associated with the production and mobilization of feedstocks for advanced biofuels (including wastes, energy crops and lignocellulosic material).

A second key element of the analysis concerns the choice of policy instrument for increasing the share of renewable energy in transport. This objective can be pursued either through an energy-based incorporation obligation or, alternatively, through a GHG emission reduction obligation. Both approaches have their strengths and weaknesses. The analysis above points to the following considerations:

An energy based obligation would:

-Promote greater penetration of biofuels on the basis of the energy density of fuels relative to cost, and ensure GHG savings based on minimum, possibly increased, emission saving thresholds;

-Build on the extensive policy and administrative experience developed by Member States in implementing the RES Directive and their national renewable fuel mandates;

-Minimize the administrative burden for economic operators, which would continue to use mainly default values and not requiring a change in the EU GHG saving methodology.

A GHG intensity reduction obligation would:

-Incentivize fuels with the greatest direct GHG reduction relative to costs, as well as the continuous improvement in the GHG efficiency of fuels throughout the whole period up to 2030 as the instrument is optimised to GHG reduction.

-Continue the FQD policy approach currently being implemented by the Member States for the period up to 2020, thus ensuring policy continuity.

-Allow fuel suppliers compliance choices depending on costs. Where this is economically advantageous it is expected to encourage suppliers to report actual GHG values, instead of GHG default values, in order to maximise the GHG savings of their fuels.

Among the energy-based options (options 1 to 3) Options 0 can be discarded as it could not ensure that food based biofuels are gradually replaced by more advanced biofuels.

Among the options based on the Fuel Quality Directive (option 4), option 4A and option 4B can be discarded on the basis of the preceding analysis. These options maintain a mandate for food-based biofuels up to 2030, which significantly lowers their GHG performance.

5.3.1.    Overall comparison of the options to increase renewable energy in the transport sector (RES-T)

5.4.Options to empower and inform consumers of renewable energy

The table below provides an overview of the options discussed in this section.

5.4.1.    Empower consumers to generate, self-consume and store renewable electricity 

Option 0: Baseline

Under this option, no EU policy framework for self-consumption of renewable energy is developed. Member States decide individually if and how to promote renewable energy self-consumption systems. Support schemes will have to comply with the State aid rules. The regulations in some Member States discourage self-consumption and would continue to be in place.

Option 1: EU guidance on self-consumption of renewable energy

Under this option, the Commission would develop a revised non-binding guidance on self-consumption, building on and further expanding the Staff Working Document (2015)141. Given the non-binding nature of the guidance, it is uncertain that this option would address existing legal barriers to renewable energy self-consumption effectively, with the risks of different levels of consumer empowerment across the EU.

Option 2: Empower citizens to self-consume and store renewable electricity

The Revised RES Directive would set out framework principles enabling consumers to generate renewable electricity for their own use without their supplier's permission, and would limit the administrative burdens of doing this. This option responds to the concerns of 79 % of stakeholder who expressed an option on the matter in the public consultation and believed that there are administrative barriers to self-consumption. More specifically, this option would include the following provisions:

Introduce a EU-wide definition of renewable energy prosumers;

Empower consumers (below a certain capacity threshold) to generate and store renewable electricity for their own use, without requiring the supplier's permission, and limit the administrative burden by requiring a simple notification to the DSO;

Enable consumers to sell excess renewable electricity and to participate in all relevant energy markets either directly or through market aggregators.

At the same time, there are a number of aspects relevant for self-consumption that will need to be addressed in the Market Design Initiative, such as ensuring that consumers who generate their own renewable energy electricity have access to wholesale and balancing markets through aggregators and that wholesale market rules do not discriminate against renewables, in particular small-scale producers. In addition, grid tariffs should reflect the cost-benefits of self-consumption systems for the electricity network and incentivise cost-effective consumer behaviour from a system point of view.

Option 3: Distance self-consumption for municipalities

Option 3 would further expand Option 2 by enabling also distant self-consumption of renewable energy, specifically for municipalities, i.e. renewable plants installed in one municipal building could provide electricity for other municipal buildings. This option would help municipalities fully engage in the energy transition.

5.4.1.1.    Introduction to the assessment

Thanks to the drop of PV module prices, decentralised generation of solar energy has reached grid parity in most Member States, i.e. self-generated electricity is as cheap as or even cheaper than electricity from the grid, at retail price. In many Member States this new trend allows consumers to actively engage in the energy transition while saving on their electricity bill.

Self-consumption (i.e. the simultaneous generation and consumption of electricity) can provide benefits to the entire electricity system, chiefly when there is a good match between renewable electricity generation and consumption. This is for instance often the case for commercial buildings and supermarkets when the generation profile of solar panels matches the consumption pattern (day consumption) or when air conditioning is used during sunny days. At the same time, the wide-spread deployment of self-consumption can bring a challenge in terms of adaptation of grid tariffs. To the extent that grid costs are passed on to consumers through volumetric billing of the grid (as opposed to capacity-based charging), the increase in self-consumption rates may reduce revenues for grid operators, which in turn may need to recoup these losses via increased charges on traditional consumers. Once the levelised costs of rooftop solar reach the level of wholesale market prices, it can compete on the electricity element of the retail electricity price. Until then, investments in distributed solar generation depend on the pricing regime (e.g. on gird tariffs, RES levies or taxes). In the absence of support schemes, self-consumption is economically only viable in those Member States where distributed generation can produce at least at retail level prices 317 .

As the RES Directive does not contain any specific provisions on self-consumption, Member States have developed different legal frameworks that led to a high degree of fragmentation and different levels of consumer empowerment in Europe. Some Member States put in place feed-in tariffs, such as Bulgaria, Denmark, Germany, Estonia, France, Greece, Croatia, Lithuania, Luxembourg, Hungary, Malta, Netherlands, Austria, Poland, Slovenia, and Sweden. The level of these feed-in tariffs varies and is sometimes below the levelised costs of electricity. The UK offers an export tariff and Romania works with Green Certificates. Denmark put in place an hourly net metering scheme, in other Member States it is annual but with lower price for electricity which is fed in to the grid. An overview of different degrees of consumer empowerment is provided in the graph below.

Table 11: Overview of self-consumption schemes in Member States

Furthermore, in the absence of European legal framework national regulations have been highly unstable 318 , which significantly reduced investor certainty in many Member States and led many respondents to the public consultation, in particular from the renewables industry, NGOs and cooperatives, to call for a clear European framework and a European vision on self-consumption. In the figure below (map), the Member States with a dotted line have made changes to their national framework since 2013 and the Member States in yellow only established a legal framework after that year.

Figure 27: Regulatory frameworks for self-consumption

Source: European Commission (Report on Investments in investments in solar panels in the residential sector in EU Member States, to be published in Q4 2016)

Blue: Member States with a regulatory framework established before 2013
Yellow: Member States with a regulatory framework dating after 2013.
Dotted line: Changes to a regulatory framework existing before 2013 and implemented after 2013
Grey: Member States that do not have a dedicated support framework for self-consumption, although self-consumption can be allowed

5.4.1.2.    Detailed assessment

In the future, it is likely that the uptake of small-scale solar will be mostly driven by decision taken at household and business levels looking to offset retail power tariffs and reduce costs 319 . Based on this assumption, this impact assessment tries to assess the gap of renewable energy generation that would result from a support phase-out and that would have to be filled by self-consumption. According to the model, growth will first take place in small-scale solar designed for self-consumption during daytime. With storage becoming more widely and cheaply available, a higher level of self-consumption throughout the day and larger solar panels will be installed.

In order to assess the impact of the different options, this Impact Assessment focuses on the deployment of rooftop solar PV generation 320 as well the share of self-consumed electricity among overall rooftop PV generation. For this, the following PRIMES scenarios and assumptions are used:

For Option 0 and Option 1, REF2016 was used to assess the continuation of current practices in the absence of enabling framework at Member State level. Within these options, the self-consumption ratio 321 ranges between 33% and 64% 322 .

For option 2, EUCO27 has been used, mirroring cost-effective deployment of renewables within a harmonized enabling framework. The self-consumption ratio ranges between 37% and 67% 323 .

For option 3, EUCO27 has been used, mirroring cost-effective deployment of renewables within a harmonized enabling framework. The self-consumption ratio ranges between 41 % and 72 %. The increased self-consumption ratio is an illustrative draft estimation assuming an additional 9 % of energy potentially self-consumed at municipal level 324 .

Based on these assumptions, the solar PV generation by 2030 would break down as below:

Figure 28: projected rooftop PV generation in 2030

The effect of the enabling measures under Option 2 and Option 3 is, as depicted in Figure 29, twofold:

An increase in overall rooftop solar PV deployment, driven by self-consumption. By 2030, this increase is expected to be 20% compared to options 0 and 1, and 50 % compared to 2020.

An increase in self-consumed electricity. By 2030, the maximal increase (assuming no battery deployment) is 26 % to 34 % compared to options 0 and 1. This increase could be however substantially higher 325 when compared to 2020, mostly due to a possible uptake of batteries.

However, all of these options will have a relatively moderate impact on the electricity consumption and generation pattern at EU-level, as shown in Figure 33.

Figure 29: residential electricity consumption in 2030

Economic impacts

Self-consumption allows consumers to lower their electricity bill. With an average self-consumption rate of 30 % a consumer a four-person household with a 4 kWp PV system and with an average annual electricity consumption of 3 600 kWh could save almost € 320 a year due to self-consumption 326 .

These savings are partly due to self-produced electricity which does not have to be bought and to a lesser extent due to the grid charges that are saved. This has led to concerns about lost revenue for the TSO that might impact the grid charges to be paid by other users that do not self-consume. However, due to the low self-consumption rates this problem is of theoretical nature today. Although today no statistics are available regarding self-consumption in the EU, German statistics for PV self-consumption indicate that it represents about 2.5 TWh (or 0.5 % of the final German electricity consumption) and seems to remain constant overtime from 2012 -2016. The same report assumes that even if the maximum potential of roof top solar according to PRIMES is used for self-consumption, the reduction amounts to 7.2 % of the 2013 distribution revenues and 1.1 % of the total electricity revenues. This calculation is based on the current rate design. Further analysis can be found in the MDI Impact Assessment, according to which on the one hand, a potential 'flight from the grid' could see the remaining connected ratepayers bear an increasing share of the burden of contributing to public finances and financing the electricity network. On the other hand, grid costs may actually fall as distributed generation and storage assets enable network operators to more efficiently manage the grid and connect remote customers. Cost-reflective distribution tariffs, i.e. tariffs that allocate the costs of the grid fairly amongst system users, are analysed in the MDI Impact Assessment.

Option 0 is expected to have the lowest impact on additional self-consumption of solar electricity, as business as usual continues. Option 2 and 3 are expected to have the largest impact because more actors are enabled to resort to solar generation. However, under Option 3, municipalities would be allowed to consume electricity that was produced on one building in a municipal building in another location, in order to better match their own production and consumption and increased their self-consumption ratio. By increasing the distance between the points of production and consumption by using the distribution grid, potential benefits of self-consumption for grid demand and grid losses would diminish, especially when the consumer is supplied via the distribution grid. It could however motivate municipalities to invest in renewable energy sources but it seems doubtful that this solution would be cost-efficient.

Option 0 and Option 1 would have the smallest impact on revenues. However, they would also fail to empower consumers. Option 3 appears to be most costly because it does not provide the potential benefits of self-consumption but reduces financing and tax revenues.

Social impacts

The Energy Union places citizens at its core. This includes giving consumers a wider choice of action when choosing their participation in energy markets and enabling them to generate and consume their own energy under fair conditions in order to save money, help the environment, and ensure security of supply. Engaging consumers can also help mobilise private investments for the energy transition and increase the sense of ownership. As the large number of petitions at the European Parliament on self-consumption show 327 , the business as usual scenario fails to achieve that objective in at least some Member States.

Option 1 is unlikely to improve the situation in all Member States as guidance would remain voluntary. Option 2 is likely to improve the situation across the EU as a European legal framework could establish a minimum degree of consumer empowerment in all Member States. Option 3 would indirectly involve a very large share of the population in self-consumption if municipalities started to install solar panels for virtual self-consumption on schools, swimming pools and other public buildings. However, virtual self-consumption over the grid would raise new challenges with regards the financing of the grid.

In addition to consumer empowerment, enabling self-consumption could also create new jobs. In 2014, the PV sector in Europe represented nearly 110.000 full-time jobs most of which in the installation and maintenance sector 328 . Yearly installed capacities in Europe have a significant impact on job creation as there is a direct impact on and services needed. Rooftop solar creates nearly three times as many jobs as ground-mounted installations. As self-consumption is likely to be a key driver for the uptake of solar (and other renewable) energy generation, this would also be the driver for new jobs. Option 0 and Option 1 are not expected to have a strong impact. Option 2 and 3 could trigger higher investments in the sector and thus contribute to higher job creation. Options 2 and 3 might create 10 000 to 20 000 additional jobs 329 in roof-top solar by 2030 compared to the business as usual scenario.

Grid defection from households that can cover their entire energy needs through self-produced electricity is not expected. In Northern Europe, this would require seasonal storage in order to match the consumption peak in winter with the production peak in summer. Even in Southern Europe, it is questionable if self-sustainable prosumers would choose to disconnect from the grid as this would prevent them from using electricity from the grid when their own generation does not function (e.g. for rooftop panels when the sun does not shine) and from selling excess electricity to the market (e.g. in times of long sunny periods). Should a prosumer however wish to disconnect from the grid, it would be fair if he does not contribute to the grid costs as he does not use it. This question is analysed more substantially in the MDI Impact Assessment.

Environmental impact

Environmental impacts are mostly influenced by the additional renewable energy generation in the system. In this case, the difference in rooftop PV generation between options 0 and 1 and enabling option 2 and 3 is 24 TWh, i.e. around 1.4 % of all renewable electricity by 2030 330 . Therefore these options are expected to have an overall moderate but still positive impact on renewable electricity deployment.

5.4.2.    Disclosing information on the sources of electricity generation

Option 0: Baseline

There would be no change in the current system, it would continue to function as presently designed.

Option 1: Improve functioning of GO system

Improvements are made to the functioning of the GO system by making current good practice approaches of Member States in the operation of the system a mandatory part of the legislation. This would create a better single EU market for GOs from renewable energy.

Option 2: Option 1 plus GOs mandatory for disclosure

In addition to improving the functioning of the system, GOs become the only means for disclosure of renewable electricity consumption to consumers. Energy suppliers would therefore need to use GOs if they are to make any claims about the renewable content of the electricity. The disclosure requirements set out in the Electricity Directive may need to be amended accordingly for this purpose. For this more comprehensive approach to work, Member States would need to issue GOs for electricity subject to a national support scheme in a way would not provide these generators with additional compensation.

Option 3: Option 2 plus extend GOs to all sources of electricity generation

The GO system is expanded to provide a system of full disclosure of all energy sources, so enabling the origins of fossil and nuclear energy to be tracked in the same way. This would also mean that data such as CO2 emissions from electricity consumption could be reported to consumers in a consistent way. In addition to making cancellation of GOs mandatory to energy suppliers, this option could also make issuance of GOs mandatory to all electricity producers, requiring all such energy sources to have GOs issued for them. However, such an expansion could be implemented in a voluntary manner, where Member States issue GOs to such electricity producers only at their request. There would be no obligation for GOs to be issued if the electricity generator does not want them.

5.4.2.1.    Introduction to the assessment

The guarantee of origin (GO) system helps to disclose to consumers the share or quantity of energy from renewable sources in an energy supplier’s energy mix. It provides a pan-European information system for the final consumer as to the origin of electricity, so enables producers to demonstrate the share or quantity of electricity produced from renewable sources and from high efficiency CHP 331 .

GOs may be used for energy mix disclosure requirements by energy suppliers (e.g. set out under the Electricity Market Directive 2009/72/EC), but their use is not compulsory under this legislation.

GOs are electronic certificates that prove that energy is generated from renewable sources or CHP. The key features are:

GOs prove that a certain amount of renewable energy was produced somewhere in Europe – they do not prove that a certain amount of renewable energy has been physically consumed by the purchaser;

The legislation creates a single market for GOs - they are traded separately from the physical power so they can move around Europe;

A GO represents 1 MWh of energy; GOs need to be used and cancelled within 12 months; each GO has unique identifier which gives standardised information on factors such as: date and country of issue, date of energy production, age of installation, location;

Member States have to recognise GOs issued by another Member State.

A common hub has been developed to enable such electronic transfers by the Association of Issuing Bodies (AIB). Refusal to recognise a GO from another Member State is possible, in case of doubts about its quality, in which case it must be notified to the Commission.

Each Member State has a national competent body for electronic issuing, transfers and cancellations of GOs:

othey must be issued upon request to producers of renewable and high efficiency CHP electricity 332 ;

oit is optional for Member States to issue them for renewable heating and cooling;

oit is possible for Member States to only issue GOs to renewable electricity not receiving support under any other national support mechanism. This was to avoid concerns as to double subsidy of renewable energy.

In theory, a book and claim approach for GOs is an efficient system enabling renewable energy to be produced in more cost efficient locations and consumed remotely. They are low cost and efficient relative to other certification models and fit well with diverse supply chains across multiple countries. However, to retain credibility, it is essential that such an approach has well-functioning systems for issuing and retiring GOs and that the central registry is robust. In addition, the system can be more vulnerable to fraud and gain a poor reputation with consumers if the systems are not resilient 333 .

Use of GOs is growing over time. Figure 30 shows that increasing volumes of GOs have been issued and cancelled over recent years. In 2011, GOs were issued for about 22% of the renewable electricity generated in the EU. By 2015 issuance had grown to covering around 45% of the renewable electricity generated.

Figure 30: Total volume of GOs using EECS standard transacted through the AIB hub 334

Although an increasing amount of renewable electricity is covered by GOs, Figure 31 shows that the majority of power generation is outside of the GO system.

Figure 31: Total Generation (left) and non-tracked generation (right) in 2014 335

The trend for increased use of GOs demonstrates that there is strong and growing consumer demand for green energy products in recent years. Green electricity tariffs based on renewables and backed by GOs are common in many Member States. The growth in the issuance and cancellation of GOs suggests that abolition of the system could be counterproductive, possibly resulting in the need for alternative mechanisms to be developed. Furthermore, it was notable that there was little call for such an approach in the public consultation.

Growth in demand for GOs has also come from corporate consumers seeking to satisfy corporate environment, social and governance (ESG) requirements. Indeed one important driver of the GO market is the recent recognition of GOs by the main corporate carbon accounting standard organisation CDP (formerly Carbon Disclosure Project). Their technical guidance now states: "you can reflect specific policies on contracting renewable energy into your disclosure on emissions performance, namely if your […] emissions have reduced as a consequence of buying RECs or GOs you can consider that as a emission reduction activity" 336 . The endorsement of GOs by such a body is likely to increase demand from the corporate sector for GOs over the coming years as they start to implement the latest guidance. The guidelines also demonstrate that a core demand for the GOs from these corporate consumers is for CO2 accounting reasons, rather than the renewable character of the energy itself. The GO is valued primarily for the reason that it represents low carbon energy.

The most developed case of such renewable consumption can be found in Luxembourg, where it is reported that the number of ‘green’ electricity contracts accounts for 100% of the retail market 337 . In the Netherlands 63% of all contracts are now green 338 . This high level of consumption, contrasts strongly with the low renewable energy generation. In 2014, just 5.9% of the electricity produced in Luxembourg was from renewable sources and 10% in the Netherlands demonstrating significant imports of the GOs from other countries 339 .

As a consequence of this, Norway which generates virtually all of its electricity from renewable sources and exports the associated GOs ends up importing a residual mix of electricity from fossil and nuclear power generated in other parts of Europe. In accordance with the principles of the Electricity Market Directive, this resulting mix is shown to consumers on their bills.

GOs have a relatively low value, generally trading for under a Euro for each MWh of electricity. Finding prices of GOs is not straight forward as there are no published indices since most GOs are traded over the counter. One publically available source is the results of the auctions made by GME which sells GOs on behalf of the Italian Government 340 . Prices achieved in the three 2016 auctions averaged between 15-29 cents per MW/h.

The data on the GME website shows that prices have remained low over time, suggesting that there is little scarcity in the market, i.e. supply through issuance has grown at slightly higher rate than the demand for cancellation. However, there have been cases reported of certain specific types of GOs selling at much higher prices (e.g. anecdotal evidence that GOs from wind energy generated in the Netherlands has sold at over EUR 2 a MW/h). Such prices are likely to be driven by consumers expressing demand for certain types of renewables in certain locations.

It is apparent that there are differences across the EU in the way in which Member States have implemented the GO system. A 2014 consultant's report for DG Energy on progress in renewable energy 341 found that:

-There were considerable differences between the national systems due to different approaches to implementing the requirements;

-Not all Member States had decided to join the Association of Issuing Bodies (AIB) which provides a standardised system for the exchange of GOs between Members;

-2 Member States did not have an electronic registry;

-Practices for fraud avoidance varied, many Member States have put in place a system of verification; and

-Only 3 Member States had decided to introduce GOs for heating and cooling, however neither seemed to have any activity in that sector.

Some of the variations in the implementation of the system between Member States, reflects the flexibility inherent in the legislation. Many of these differences persist. For example, at the end of 2015, AIB had a total of 18 EU and EEA-EFTA countries as members 342 . Whilst membership of the AIB is voluntary for Member States, it provides a convenient and robust means for the trade of GOs. The absence of some Member States from the AIB indicates differences in implementation of the GO system around the EU and an incomplete internal market.

A key variation is the relationship between GO issuance and national support schemes. In line with an option in the Directive, many Member States restrict issuance of GOs to electricity not benefiting from support schemes to avoid double compensation to electricity producers. As a result, GOs are only issued for the unsupported part of the renewable electricity production. Other Member States issue GOs for all renewable electricity. For example, Italy auctions the GOs associated with supported electricity. This ensures full issuance of GOs for all renewable electricity, but prevents double compensation for energy generators who already received payment from the national support scheme.

As described in the problem definition section, the current legal structure risks double counting of renewable electricity, as use of GOs is not required for disclosure purposes. To prevent such risks, the hub system developed by the AIB for exchange of GOs across the EU has at times disconnected some Member States 343 from trading GOs with other countries, if risks of double counting are perceived in the structure of national legislation related to GOs and disclosure.

From a consumer perspective, there have been concerns about misleading green claims and "greenwashing" by the GO system given the risk of double counting and also as it enables imports of renewable electricity across the whole of the EEA. For example, renewable electricity from Norway can be consumed in Greece, when in reality it is unlikely to travel that far. In essence this is a criticism of the use of "book and claim" systems for certification purposes, rather than credibility of the GO system itself. Clearly robust implementation of the system across the EU should help build confidence in the system and allay concerns that the origin of the electricity is not double counted in any way.

The partial use of the GOs for just renewable electricity means that residual mix calculations need to be carried out each year to calculate the consumption of non-renewable sources as a result of the GO transfers. This is quite a complex statistical exercise and cannot be as accurate as the tracking function provided by a well-designed GO system.

The current system design means that in effect those covered by the GO system generate the data for disclosure and effectively pay for the residual mix calculations. As a consequence, fossil and nuclear generators do not directly contribute towards producing data for disclosure that is produced through the GO system. This also means that the system applies to smaller generation sites, but not to some of the large ones, as renewable installations have a much smaller average output compared to large thermal power plant. Data for the UK 344 shows that in May 2015, 78% of the electricity generation installations operating were renewable (362 installations including co-firing, excluding small scale) and 12% were purely fossil or nuclear (100 installations). In 2014, 19.1% of the UK's electricity generation was from renewable sources.

There are also variations in the scope of the GO system. Austria, Sweden and Switzerland 345 have extended a GO system to all types of electricity generated in their territory. Data from some of these states shows that extension to large thermal generators has modest additional administrative impact as both countries have a relatively high share of renewable generation. In Austria, fossil plants represent about 1% of the total installations on their registry, but represent around 30% of electricity production. Similarly in Switzerland, fossil and nuclear generation represents about 10% of the number of installations, but over 40% of the total power generated.

Evaluation work 346 by consultants was carried out to support the REFIT assessment of the RES Directive. The conclusions and recommendations included:

-Continue to stress the importance of Member States to move towards a GO system based on the European Energy Certificate System (EECS) operated by the Association of Issuing Bodies (AIB). Also, continue to monitor progress, to ensure full implementation of this aspect throughout the EU;

-Assess the benefits of following the Best Practice Recommendations formulated by RE-DISS 347 , such as streamlining the use of tracking mechanisms at Member States level and clarifying the relation between support schemes and the tracking systems used for purposes of disclosure;

-Investigate the possible extension of the use of GOs beyond RES-E and high-efficient cogeneration to all types of power generation i.e. including electricity from fossil and nuclear generation.

These recommendations are captured by the options under consideration.

5.4.2.2.    Detailed assessment

Economic impacts

Increasing issuance and cancellation of GOs will result in changes in financial flows. The overall economic impacts are likely to be low as GOs trade at very low prices relative to the price of electricity.

The economic impact of the option for improving the functioning of the existing system will be negligible relative to a business as usual scenario, as it may not shift the supply and demand balance for GOs very much.

Making the system mandatory will increase supply and demand for GOs, and may result in more financial flows to generators. However, if a consistent approach is adopted to prevent double compensation, say by Governments auctioning GOs associated with supported electricity, then the impact should be neutral. Especially if the auction revenues are returned to those who pay for the support scheme in the first place.

With a system of full disclosure, the additional financial flows are likely to be minimal as GOs from fossil and nuclear sources may trade at very low prices as they could have little value to energy consumers. Nuclear may have more value than fossil GOs due to it low carbon character, so nuclear electricity generators may benefit more than those producing electricity from fossil fuels.

Improving the functioning of the single market for GOs should make the market more efficient and less costly. The different options under consideration should improve the coordination and robustness of the schemes and create a liquid, functional market. They should bring in more consumers to a properly functioning GO disclosure market, so should make green energy purchasing a more effective consumer driven market. This would be expected to improve the responsiveness of energy companies to green consumer preferences. It could help supplement or possibly in the longer term supersede public support for renewable energy. This should result in system based on green consumer pricing which is less distorting and more efficient.

Improving the functioning of the system also seems to be preferable to abolition. It is difficult to see how abolition could create a more efficient outcome and more reliable information to consumers and producers as to preferences for renewables.

The administrative costs of changing the scope of the system should be moderate. All Member States currently have the administrative infrastructure in place from the existing GO system, so extra administrative costs will be incremental. The highest additional administrative costs would result from expanding the system to fossil and nuclear generators. These costs would increase further if CO2 emissions data from power plants is included in some way in the GO system.

Social impacts

The ultimate impact of the GO system is that it as a means to provide reliable data to consumers as to the sources of the electricity that they consume. The more reliable and comprehensive the data provision, the bigger the social impact. A poorly designed and implemented system could have negative impacts on consumers by reducing levels of trust in the information that is provided to them and raising suspicions of misleading green claims and "greenwashing".

Compared to the business as usual option, improving the functioning of the GO system should have positive social impacts, in that it should improve levels of trust and confidence in the mechanism through creating a more transparent system. The impacts should be larger with the more ambitious options. Making the system mandatory for disclosure purposes should therefore have a bigger positive impact, as the system would cover the whole range of renewable electricity generation sources. Positive impact should come from extending the system from only renewables to all sources of electricity.

Abolition of the system would also seem to make the quality of the information provided to consumers worse.

Environmental impacts

The environmental benefits of the improving the GO system relate to consumers being empowered to make more informed choices regarding their energy consumption. An improved and more comprehensive GO system could have the effect of increasing the demand for renewable and low carbon energy by enabling consumers to express more clearly their willingness to pay for different types of electricity.

The options of making the system mandatory and that of expanding its scope to other energy sources could both result in larger environmental benefits relative to a business as usual approach. Improved information about the character of energy consumption, may increase demand for greener tariffs. It is possible therefore possible that there could be an increase in price of GOs and result in more renewable energy brought to the market. The incentive impact is likely to be small given the very low prices at which GOs trade relative to wholesale market prices. However, the reported much higher prices paid for specific types of renewable technology in specific locations indicate that there could be a more pronounced impact for certain types of projects.

There should also be other positive environmental impacts from expanding the system to fossil and nuclear plants, as this would enable emissions data to be attached to GOs. Consumers would therefore be able to choose with greater confidence electricity supply tariffs with low CO2 emissions (e.g. nuclear and renewables) in addition to pure renewables based tariffs. In particular, this would help satisfy the growing demand for such products from the business sector. The additional price incentive that this provides to power generators is likely to be very small given the price that GOs trade for, however at the margin it would create a small amount of additional revenues for low carbon electricity.

Political feasibility /opportunity

Further development of the GO system is compatible with the development of broader European energy market and the objectives of the Energy Union. As cross border flows in energy increase with greater interconnection and more coupled markets, the need for a robust systems to track production and consumption of renewable electricity will increase. The need for, and benefits of, an effective pan European GO system should increase over time. Abolition of the system would have a negative effect of reducing the potential for trade for renewable energy across Europe.

Other impacts (markets, innovation…)

The current system just applies to renewable generators. Most renewable energy generation sites are owned by large corporations, however it is possible that some of these installations are small, so could be owned by SMEs. Expansion of the system to large thermal power generation plants will result in further coverage of mainly larger energy generators and companies.

Of the options under consideration, it is difficult to see how Option 0 of continuing with current practice should be selected. Given the increases in the amount of renewable energy that is generated, the greater cross border trade in renewables and the growing interest in disclosure, an improved system of guaranteeing the origin of renewable electricity is desirable.

5.4.3.    Tracing origins of renewable fuels used in heating and cooling and transport