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) - Hoofdinhoud
| Documentdatum | 02-12-2016 |
|---|---|
| Publicatiedatum | 03-12-2016 |
| Kenmerk | 15120/16 ADD 6 |
| Van | Secretary-General of the European Commission, signed by Mr Jordi AYET PUIGARNAU, Director |
| Externe link | origineel bericht |
| Originele document in PDF |  |
Council of the European Union
Brussels, 2 December 2016 (OR. en)
15120/16
Interinstitutional File: ADD 6
ENER 417 CLIMA 168 CONSOM 298 TRANS 479 AGRI 650 IND 261 ENV 757 IA 130 CODEC 1802
COVER NOTE
From: Secretary-General of the European Commission, signed by Mr Jordi AYET PUIGARNAU, Director
date of receipt: 1 December 2016
To: Mr Jeppe TRANHOLM-MIKKELSEN, Secretary-General of the Council of the European Union
No. Cion doc.: SWD(2016) 418 final - PART 3/4
Subject: 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)
Delegations will find attached document SWD(2016) 418 final - PART 3/4.
Encl.: SWD(2016) 418 final - PART 3/4
EUROPEAN COMMISSION
Brussels, 30.11.2016 SWD(2016) 418 final
PART 3/4
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 i} {SWD(2016) 419 final} Contents
ANNEX 4 - ANALYTICAL MODELS AND MODEL-BASED SCENARIOS USED
IN PREPARING THE IMPACT ASSESSMENT .................................................. 216
ANNEX 5 - KEY INDICATORS ................................................................................... 268
ANNEX 6 - WHO IS AFFECTED AND HOW ............................................................. 290
ANNEX 7 - OVERVIEW OF BIOFUELS MANDATES IN MEMBER STATES ....... 291
ANNEX 8 - MODELLING METHODOLOGY FOR THE GHG EMISSION
REDUCTION OPTIONS ........................................................................................ 296
ANNEX 9 - REFIT EVALUATION .............................................................................. 299 A NNEX 4 - A NALYTICAL MODELS AND MODEL - BASED SCENARIOS USED IN
PREPARING THE I MPACT A SSESSMENT
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1.Description of analytical models used – PRIMES related suite of models
The model suite used for this impact assessment has a successful record of use in the Commission's energy and climate policy impact assessments – it is the same model suite as used for the 2020 climate and energy package as well as for the 2030 climate and energy policy framework. The models and their linkages are briefly described in the following subsections. Detailed model descriptions can be found on the DG CLIMA
website 1 . Assumptions relevant for this impact assessment are described in section 2 on
the EU Reference scenario and section 3 on policy scenarios.
The model suite covers:
• The entire energy system (energy demand, supply, prices and investments to the
future) and all GHG emissions and removals:
• Time horizon: 1990 to 2050 (5-year time steps)
• Geography: individually all EU Member States, EU candidate countries and, where
relevant Norway, Switzerland and Bosnia and Herzegovina
• Impacts: on energy, transport and industry (PRIMES and its satellite models on
biomass and transport), agriculture (CAPRI), forestry and land use (GLOBIOM- G4M), atmospheric dispersion, health and ecosystems (acidification, eutrophication) (GAINS); macro-economy with multiple sectors, employment and social welfare (E3ME and GEM-E3).
The models are linked with each other in formally-defined ways to ensure consistency in the building of scenarios, as shown graphically in Figure 1. These inter-linkages are necessary to provide the core of the analysis, which are energy, transport and GHG emissions trends.
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Figure 1: Inter-linkages between models
Source: EU Reference Scenario 2016 publication report
1.1. PRIMES
The PRIMES model is an EU energy system model which simulates energy consumption and the energy supply system. It is a partial equilibrium modelling system that simulates an energy market equilibrium in the European Union and each of its Member States. This includes consistent EU carbon price trajectories.
Decision making behaviour is forward looking and grounded in micro-economic theory. The model also represents in an explicit way energy demand, supply and emission abatement technologies, and includes technology vintages.
The core model is complemented by a set of sub-modules, of which the transport sector module and the biomass supply module are described below separately in more detail. Industrial non-energy related CO 2 emissions are covered by a sub-module so that total CO 2 emissions can be projected. The model proceeds in five year steps and is for the
years 2000 to 2010 calibrated to Eurostat data.
The PRIMES model is suitable for analysing the impacts of different sets of climate, energy and transport policies on the energy system as a whole, notably on the fuel mix,
CO 2 emissions, investment needs and energy purchases as well as overall system costs. It
is also suitable for analysing the interaction of policies on combating climate change, promotion of energy efficiency and renewable energies. Through the formalised linkages
with GAINS non-CO 2 emission results and cost curves, it also covers total GHG
emissions and total ESD sector emissions. It provides details on the Member State level, showing differential impacts across Member States.
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The PRIMES model represents energy efficiency by simulating different measures with different techniques. These modelling techniques will affect the context and conditions under which stylized agents per sector, make their decisions on energy consumption.
PRIMES has been used for the analysis underpinning the Commission's proposal on the EU 2020 targets (including energy efficiency), the Low Carbon Economy and Energy 2050 Roadmaps, the 2030 policy framework for climate and energy and the energy efficiency Impact Assessment in 2014.
PRIMES is a private model and has been developed and is maintained by E3MLab/ICCS
of National Technical University of Athens 2 in the context of a series of research
programmes co-financed by the European Commission.
The model has been successfully peer reviewed 3 , most recently in 2011 4 .
1 .2. PRIMES- TAPEM & PRIMES-TREMOVE
PRIMES-TAPEM, operated by ICCS/E3MLab is an econometric model for transport activity projections. It takes GEM-E3 projections (GDP, activity by sector, demographics and bilateral trade by product, and by country) as drivers, to produce transport activity projections to be fed into PRIMES-TREMOVE. The econometric exercise also includes fuel prices coming from PROMETHEUS, as well as transport network infrastructure (length of motorways and rail-ways), as drivers. The PRIMES-TAPEM model provides the transport activity projections for REF2016.
The PRIMES-TREMOVE Transport Model projects the evolution of demand for passengers and freight transport by transport mode and transport mean. It is essentially a dynamic system of multi-agent choices under several constraints, which are not necessarily binding simultaneously. The model consists of two main modules, the transport demand allocation module and the technology choice and equipment operation module. The two modules interact with each other and are solved simultaneously.
The projection includes details for a large number of transport means, technologies and fuels, including conventional and alternative types, and their penetration in various transport market segments. It also includes details about greenhouse gas and air pollution emissions, as well as impacts on external costs of congestion, noise and accidents.
PRIMES-TREMOVE has been used for the 2011 White Paper on Transport, Low Carbon Economy and Energy 2050 Roadmaps as well as the 2030 policy framework for climate
and energy. 5
The PRIMES-TREMOVE is a private model that has been developed and is maintained
by E3MLab/ICCS of National Technical University of Athens 6 , based on, but extending
2 http://www.e3mlab.National Technical University of Athens.gr/e3mlab/ .
3 http://ec.europa.eu/clima/policies/strategies/analysis/models/docs/primes_model_2013-
4 https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1569_2.pdf '.
5 The model can be run either as a stand-alone tool (e.g. for the 2011 White Paper on Transport) or
fully integrated in the rest of the PRIMES energy systems model (e.g. for the Low Carbon Economy and Energy 2050 Roadmaps, and for the 2030 policy framework for climate and energy). When coupled with PRIMES, interaction with the energy sector is taken into account in an iterative way.
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features of the open source TREMOVE model developed by the TREMOVE 7 modelling
community. Part of the model (e.g. the utility nested tree) was built following the
TREMOVE model. 8 Other parts, like the component on fuel consumption and emissions,
follow the COPERT model.
In the transport field, PRIMES-TREMOVE is suitable for modelling soft measures (e.g. eco-driving, deployment of Intelligent Transport Systems, labelling), economic measures (e.g. subsidies and taxes on fuels, vehicles, emissions; ETS for transport when linked with PRIMES; pricing of congestion and other externalities such as air pollution,
accidents and noise; measures supporting R&D), regulatory measures (e.g. CO 2 emission
performance standards for new passenger cars and new light commercial vehicles; EURO standards on road transport vehicles; technology standards for non-road transport technologies), infrastructure policies for alternative fuels (e.g. deployment of refuelling/recharging infrastructure for electricity, hydrogen, LNG, CNG). Used as a module which contributes to a broader PRIMES scenario, it can show how policies and trends in the field of transport contribute to economy wide trends in energy use and emissions. Using data disaggregated per Member State, it can show differentiated trends across Member States.
1.3. PRIMES Biomass Supply
The biomass system model is linked with the PRIMES energy system model for Europe and can be either solved as a satellite model through a closed-loop process or as a standalone model.
It is an economic supply model that computes the optimal use of biomass/waste resources and investment in secondary and final transformation, so as to meet a given demand of final biomass/waste energy products, projected to the future by the rest of the PRIMES model. The biomass supply model determines the consumer prices of the final biomass/waste products used for energy purposes and also the consumption of other energy products in the production, transportation and processing of the biomass/waste products. The model also reflects the sustainability criteria currently in place and can be used for reflecting policies facilitating the use of renewable energy sources. After cross check of input data and draft results, results of the biomass supply model are used to ensure consistency between PRIMES, CAPRI and GLOBIOM bioenergy modelling.
The PRIMES biomass supply model is private and has been developed and is maintained
by E3MLab/ICCS of National Technical University of Athens 9 .
6 http://www.e3mlab.National Technical University of Athens .gr/e3mlab/
7 http://www.tmleuven.be/methode/tremove/home.htm
8 Several model enhancements were made compared to the standard TREMOVE model, as for
example: for the number of vintages (allowing representation of the choice of second-hand cars); for the technology categories which include vehicle types using electricity from the grid and fuel cells. The model also incorporates additional fuel types, such as biofuels (when they differ from standard fossil fuel technologies), LPG and methane fuels. In addition, representation of infrastructure for refuelling and recharging are among the model refinements, influencing fuel choices. A major model enhancement concerns the inclusion of heterogeneity in the distance of stylised trips; the model considers that the trip distances follow a distribution function with different distances and frequencies. The inclusion of heterogeneity was found to be of significant influence in the choice of vehicle-fuels especially for vehicles-fuels with range limitations.
9 http://www.e3mlab.National Technical University of Athens. gr /e3mlab/
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1.4. GAINS
The GAINS (Greenhouse gas and Air Pollution Information and Simulation) model is an integrated assessment model of air pollutant and greenhouse gas emissions and their interactions. GAINS brings together data on economic development, the structure, control potential and costs of emission sources and the formation and dispersion of pollutants in the atmosphere.
In addition to the projection and mitigation of greenhouse gas emissions at detailed subsectorial level, GAINS assesses air pollution impacts on human health from fine particulate matter and ground-level ozone, vegetation damage caused by ground-level ozone, the acidification of terrestrial and aquatic ecosystems and excess nitrogen deposition of soils.
Model uses include the projection of non-CO 2 GHG emissions and air pollutant
emissions for EU Reference scenario and policy scenarios, calibrated to UNFCCC emission data as historical data source. This allows for an assessment, per Member State, of the (technical) options and emission potential for non-CO 2 emissions. Health and environmental co-benefits of climate and energy policies such as energy efficiency can also be assessed.
The GAINS model is accessible for expert users through a model interface 10 and has
been developed and is maintained by the International Institute of Applied Systems
Analysis 11 . The underlying algorithms are described in publicly available literature. The
source code is not disclosed. GAINS and its predecessor RAINS have been peer reviewed multiple times, in 2004, 2009 and 2011.
1.5. GLOBIOM-G4M
The Global Biosphere Management Model (GLOBIOM) is a global recursive dynamic partial equilibrium model integrating the agricultural, bioenergy and forestry sectors with the aim to provide policy analysis on global issues concerning land use competition between the major land-based production sectors. Agricultural and forestry production as well as bioenergy production are modelled in a detailed way accounting for about 20 globally most important crops, a range of livestock production activities, forestry commodities as well as different energy transformation pathways.
GLOBIOM covers 28 (or 50) world regions. The disaggregation of the EU into individual countries has been performed only recently.
Model uses include the projection of emissions from land use, land use change and forestry (LULUCF) for EU Reference scenario and policy scenarios. For the forestry sector, emissions and removals are projected by the Global Forestry Model (G4M), a geographically explicit agent-based model that assesses afforestation-deforestation-forest management decisions. GLOBIOM-G4M is also used in the Impact Assessment for agriculture and LULUCF to assess the options (afforestation, deforestation, forest management, cropland and grassland management) and costs of enhancing the LULUCF sink for each Member State.
10 http://gains.iiasa.ac.at/models/
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The GLOBIOM-G4M is a private model and has been developed and is maintained by
the International Institute of Applied Systems Analysis 12 .
1.6. Prometheus
PROMETHEUS is a fully stochastic world energy model used for assessing uncertainties and risks associated with the main energy aggregates including uncertainties associated with economic growth and resource endowment as well as the impact of policy actions. The model projects endogenously the world energy prices, supply, demand and emissions for ten world regions.
World fossil fuel price trajectories are used as import price assumptions for EU Reference scenario and for policy scenario modelling.
The Prometheus model is private and has been developed and is maintained by
E3MLab/ICCS of National Technical University of Athens 13
1.7. CAPRI
CAPRI is an open source economic partial equilibrium model developed by European Commission research funds. Operational since more than a decade, it supports decision making related to the Common Agricultural Policy and Environmental policy related to agriculture based on sound scientific quantitative analysis.
CAPRI is only viable due to its pan-European network of researchers which based on an open source approach tender together for projects, develop and maintain the model, apply it for policy impact assessment, write scientific publications and consult clients based on its results. It has been the basis of numerous peer reviewed publications.
The model has been used to provide consistent agricultural activity projections for the EU Reference scenario 2016s. It is also used in the LULUCF impact assessment. The CAPRI model is an open source model which has been developed and is maintained by
Eurocare GmbH 14 , JRC, and other partners of the CAPRI network.
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2.The EU Reference Scenario 2016 – approach and main results
2.1. Scenario design, consultation process and quality assurance
Scenario design and consultation process
Building an EU Reference scenario is a regular exercise by the Commission. It is coordinated by DGs ENER, CLIMA and MOVE in association with the JRC, and the involvement of other services via a specific inter-service group.
REF2016 2016 (REF2016) has been developed building on a modelling framework including as core models PRIMES (PRIMES-TREMOVE for transport), GAINS and GLOBIOM-G4M and as supporting models GEM-E3, PROMETHEUS, PRIMES Biomass supply and CAPRI (see prior section for details).
13 http://www.e3mlab.National Technical University of Athens. gr /e3mlab/
14 http://www.eurocare-bonn.de/
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For the REF2016, the model was calibrated on energy data up to year 2013 from Eurostat
and other sources, and for agriculture and non-CO 2 emission data up to the year 2015.
Member States were consulted throughout the development process through a specific Reference scenario expert group which met three times during the development of REF2016. Member States provided information about adopted national policies via a specific questionnaire, key assumptions have been discussed and in each modelling step, draft Member State specific results were sent for consultation. Comments of Member States were addressed to the extent possible, keeping in mind the need for overall comparability and consistency of the results.
Quality of modelling results was assured by using state of the art modelling tools, detailed checks of assumptions and results by the coordinating Commission services as well as by the country specific comments by Member States.
REF2016 projects EU and Member States energy, transport and GHG emission-related developments up to 2050, given current global and EU market trends and adopted EU and Member States' energy, transport, climate and related relevant policies.
"Adopted policies" refer to those that have been cast in legislation in the EU or in MS
(with a cut-off date end of 2014 15 ). Therefore the binding 2020 targets are assumed to be
reached in the projection. This concerns GHG emission reduction targets (both for the EU ETS as well as ESD sectors) as well as renewables targets, including renewables in transport.
However, policies which are not yet legally implemented, e.g. those necessary to
implement the 2030 energy and climate framework, are not part of REF2016 16 . On this
basis, REF2016 can help identify areas where the current policy framework falls short of
reaching the EU's climate and energy objectives 17 . Notably, REF2016 shows that current
policy and market conditions will deliver neither the 2030 targets nor the long-term 2050 80-95% GHG emission reduction objective.
REF2016 provides projections, not forecasts. Unlike forecasts, projections do not make predictions about what the future will be. They rather indicate what would happen if the assumptions which underpin the projection actually occur. Still, the scenario allows for a consistent approach in the assessment of energy and climate trends across the EU and its Member States.
15 In addition, amendments to two Directives only adopted in the beginning of 2015 were also
considered. This concerns notably the ILUC amendment to the RES Directive and the Market Stability Reserve Decision amending the ETS Directive.
16 For the period after 2020, policies are included that are part of the EU acquis, as well as important
investments that are part of Member States' national energy plans. For instance, ETS with the Market Stability Reserve is included in REF16, but not the Commission's proposal for a change in the linear reduction factor post-2020. New near-zero energy buildings after 2020 - as defined in the Energy Performance of Buildings Directive - continue to be built, as well as energy labelling continues. Member States also gave input on planned energy investments, particularly in nuclear energy.
17 Each new update of REF2016 models the projected impact of policy adopted up to the relevant
cut-off date. Therefore, differences between two consecutive Reference scenarios, e.g. between the one from 2013 and REF2016, can be explained by the implications of policies adopted in the meantime as well as by changed economic and technological trends.
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The report "EU Energy, Transport and GHG Emissions Trends to 2050 - Reference Scenario 2016" describes the inputs and results in detail. This section summarises the main messages derived from it, especially those relevant for the Energy Union framework.
Main assumptions
The projections are based on a set of assumptions, including on population growth, macroeconomic and oil price developments, technology improvements, and policies.
Macroeconomic assumptions
In REF2016, the population projections draw on the European Population Projections (EUROPOP 2013) by Eurostat. The key drivers for demographic change are: higher life expectancy, convergence in the fertility rates across Member States in the long term, and inward migration. The EU28 population is expected to grow by 0.2% per year during 2010-2030 (0.1% for 2010-2050), to 516 million in 2030 (522 million by 2050). Elderly people, aged 65 or more, would account for 24% of the total population by 2030 (28% by 2050) as opposed to 18% today.
GDP projections mirror the joint work of DG ECFIN and the Economic Policy
Committee, presented in the 2015 Ageing Report 18 . The average EU GDP growth rate is
projected to remain relatively low at 1.2% per year for 2010-2020, down from 1.9% per year during 1995-2010. In the medium to long term, higher expected growth rates (1.4% per year for 2020-2030 and 1.5% per year for 2030-2050) are taking account of the catching up potential of countries with relatively low GDP per capita, assuming convergence to a total factor productivity growth rate of 1% in the long run.
Sectorial activity projections are derived in a consistent way from these macroeconomic assumptions, using the macro-economic modelling tool GEM-E3 as well as econometric estimates for global demand for energy intensive industries.
Fossil fuel price assumptions
Oil prices have fallen by more than 60% since mid-2014, to an average of around 40 $/barrel for Brent crude oil in the first four months of 2016. The collapse of oil prices has been driven by low demand and sustained oversupply, due in particular to tight oil from North America and to the decision of the Organization of Petroleum Exporting Countries (OPEC) countries not to cut their output to rebalance the market. REF2016 considers a gradual adjustment process with reduced investments in upstream productive capacities by non-OPEC countries. Quota discipline is assumed to gradually improve among OPEC members. Thus, oil price is projected to reach 87 $/barrel in 2020 (in year 2013-prices). Beyond 2020, as a result of persistent demand growth in non-OECD countries driven by economic growth and the increasing number of passenger cars, oil price would rise to 113 $/barrel by 2030 and 130 $/barrel by 2050. This price trend resulting from PROMETHEUS modelling is in line with other reference sources such as the 2015 IEA World Energy Outlook.
No specific sensitivities were prepared with respect to oil and gas price developments. Still, it can be recalled that lower fossil fuel price assumptions tend to increase energy
consumption and CO 2 emissions not covered by the ETS. The magnitude of the change
would depend on the price elasticities and on the share of taxation, like excise duties, in
18 European Commission/ DG-ECFIN (2015) "The 2015 Ageing Report Economic and budgetary
projections for the 28 EU Member States (2013-2060)", European Economy 3/2015
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consumer prices. For instance, for transport, the changes would be limited (depending on the magnitude of the change in the oil price) due to the high share of excise duties in the consumer prices but they are still expected to lead to some higher energy consumption and CO 2 emissions. They also tend to lead to lower overall energy system costs, as the increase in consumption is more than compensated by lower prices. Conversely, costs for emission mitigation could slightly increase. Different fossil price assumptions are unlikely to lead to significantly different impacts across Member States.
Technoeconomic assumptions
In terms of technological developments, input assumptions are based on a wide range of
sources 19 , with estimates on technological costs across main types of energy equipment,
from power generation to heating systems and appliances. In addition, it should be recalled that the PRIMES model (and other models where relevant) take into account technological progress.
In terms of technological developments relevant to the transport sector, battery costs for electric vehicles and plug-in hybrids are assumed to go down to 320-360 $/kWh by 2030 and 270-295 $/kWh by 2050; further improvements in the efficiency of both spark ignition gasoline and compression ignition diesel are assumed to take place. In addition, the market share of internal combustion engine (ICE) electric hybrids is expected to
increase due to their lower fuel consumption compared to conventional ICE vehicles. 20
For the techno-economic assumptions in the projection of non-CO 2 GHG emissions, see
the detailed technical documentation 21 . In general, technological progress in this domain
is strongly linked to regulation; hence Reference scenario assumptions are conservative.
Technology assumptions are based on extensive literature review and have been peerreviewed by the Commission services, notably the Joint Research Centre of the European Commission.
Specific policy assumptions
Following the above described policy modelling approach, the key policies included in
the REF2016 are 22 :
• The EU Emissions Trading System (Directive 2003/87/EC i and its amendments) is
fully reflected in the modelling, including the linear reduction factor of 1.74% for
stationary installations and the recently adopted Market Stability Reserve. 23
19 Those include, among others, the European Commission Joint Research Centre, notably for power
generation costs or identification of Best Available Technologies, or MURE, ICARUS or ODYSSEE for the demand sectors.
20 REF2016, by design, assumes the continuation of the current trends and policies without the
implementation of additional measures. Hence, due to the absence of further policies, car manufacturers and industry are not expected to devote additional effort in marketing advanced vehicle technologies. The relatively low production of advanced vehicles, in REF2016, is not expected to yield economies of scale which could potentially imply high reduction in battery costs as suggested by other sources. Such assumptions change in a decarbonisation policy scenario context.
21 Höglund-Isaksson, L., W. Winiwarter, P. Purohit, A. Gomez-Sanabria (2016): Non-CO2
greenhouse gas emissions in the EU-28 from 2005 to 2050: GAINS 2016 Reference scenario, International Institute for Applied Systems Analysis (IIASA)
22 For a comprehensive discussion see REF2016 report
23 Decision EU/2015/1814 concerning the establishment and operation of a market stability reserve
for the Union greenhouse gas emission trading scheme and amending Directive 2003/87/EC i
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• The Effort Sharing Decision (406/2009/EC) is assumed to be implemented, i.e. ESD
GHG emission reductions at EU level in 2020 need to reach at least -10% compared to 2005 levels. It turned out that no specific policy incentives in addition to adopted EU and national policies were needed to achieve the EU level target. National ESD targets need not be achieved domestically given the existing flexibilities (e.g. transfers between Member States).
• The Energy Efficiency Directive (EED) and the Energy Performance of Buildings
Directive (EPBD) are reflected, including Member States' specific obligations as regards energy savings obligation and buildings codes.
• Ecodesign and Energy Labelling Directives and Regulations are also reflected.
• CO 2 standards for cars and vans regulations (Regulation (EC) No 443/2009 i, amended
by Regulation EU No 333/2014 i and Regulation (EU) No 510/2011 i, amended by
Regulation EU 253/2014 i); CO 2 standards for cars are assumed to be 95gCO 2 /km as of 2021 and for vans 147gCO 2 /km in line with current legislation. Standards are assumed constant after 2020/2021.
• The Renewable Energy Directive (Directive 2009/28/EC i) and Fuel Quality Directive
(Directive 2009/30/EC i) including ILUC amendment (Directive (EU) 2015/1513): achievement of the legally binding renewables target for 2020 (including 10%
renewables in transport target) for each MS, taking into account the use of flexibility mechanisms when relevant as well as of the cap on the amount of food or feed based biofuels (7%). Member States' specific renewable energy policies for the heating and cooling sector are also reflected where relevant.
• Directive on the deployment of alternative fuels infrastructure (Directive
2009/30/EC).
• The Waste Management Framework Directive (Directive 2008/98/EC i) and in
particular the Landfill Directive (Directive 1999/31/EC i) which contribute to a significant reduction of emissions from waste.
• The revised F-gas Regulation (Regulation 517/2014 i) strengthens existing measures
and introduces a number of far-reaching changes, notably limiting the total amount of the most important F-gases that can be sold in the EU from 2015 onwards and phasing them down in steps to one-fifth of 2014 sales in 2030, and banning the use of F-gases in many new types of equipment where less harmful alternatives are widely available.
• The impacts of the Reforms of the Common Agricultural Policy are taken into
account, e.g. the milk quota abolition.
• Energy Efficiency Design Index (EEDI) and the Ship Energy Efficiency Management
Plan (SEEMP) for maritime transport. 24
• Relevant national policies, for instance on the promotion of renewable energy, on fuel
and vehicle taxation or national building codes, are taken into account.
Discount rates
The PRIMES model is based on individual decision making of agents demanding or supplying energy and on price-driven interactions in markets. The modelling framework includes two distinct stages: a) a first stage models decision-making behaviour of agents,
24 IMO Resolution MEPC.203(62)
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hence investment and technology choices; b) a second stage calculates total costs for the entire energy system in order to support comparisons across scenarios.
In the first stage, agents take decisions considering the time dimension of money flows. Private discount factors can be defined as reflecting opportunity costs of raising funds by the actor on a private basis. The opportunity costs of an investment decision also vary with the degree of market distortions and non-market barriers as well as with the degree of risk associated with the decision options. The opportunity costs differ hence by sector and by type of agent.
The aim is to assess policy impacts as close as possible to reality and to avoid under- or over- estimation of the costs, and thus the difficulties, of transformation required to meet targets and transition objectives (i.e. transition towards a low carbon economy). Therefore, in line with the impact assessment guidelines the modelling is based on
private discount rates 25 .
For determining the values of discount rates to be applied, the model follows different approaches by sector. Decisions by firms are based on the weighted average cost of capital (WACC) to determine the discount rates. REF2016 applies different WACC rates by business sector, by type of technology (mature versus emerging), by scale level (e.g. industrial or decentralised versus utility scale) and for companies subject to regulation by the state. WACC rates vary between 7.5% and 11%.
Decisions by individuals are modelled based on a subjective discount rate, annualizing
investment costs following the equivalent annuity cost method. Literature surveys 26 find
high implicit discount rates for households, because of various factors, such as lack of information, uncertainties, different income levels, lack of sufficient funding, agency costs, transaction and hidden costs. By varying the discount rates applied in the model, it is therefore possible to reflect, for instance, the effects of energy efficiency policy instruments, mainly ESCOs, campaigns and labelling programs, by lowering the discount rates when these policies are implemented. Therefore, the EU Reference scenario uses discount rates for individuals reflecting both existing barriers for investment decisions (which have an upward effect on discount rates) and the impact of existing energy efficiency policies, such as energy-labelling, energy performance certificates for buildings, or the promotion of energy service companies (ESCOs), which are reflected by lower discount rates compared to default values. As such, discount rates for investment decisions used in REF2016 are comprised between 9.5% and 12% depending on the consumer good subject that is purchased.
As said above, in a second stage the model analyses the resulting energy system costs. Here, the crucial element is the amount of money that energy consuming agents (households and firms, grouped into the sectors services and industry, transport and agriculture) are required to pay in order to get the energy services they need. Energy services are provided by using energy commodities purchased by end-consumers, which depend on energy efficiency at the consumption level. The PRIMES report aggregates
25 This is different from the perspective of a social planner who optimises the whole system from a
societal perspective. In such a perspective social discount rates could play a role for determining normative inter-temporal choices.
26 For instance: Mundaca Luis, Lena Neiz, Ernst Worell and Michael McNeil (2010) “Evaluating
energy efficiency policies with energy-economy models”, Ernest Orlando Lawrence Berkeley National Laboratory
226
capital or investment expenditures (CAPEX) and purchasing costs for fuels and other energy commodities or operational expenditures (OPEX) of end-consumers to show a single total cost figure. OPEX for end-users already incorporates through pricing of energy commodities the CAPEX and OPEX costs incurred by the energy supply and trading sectors (calculated using the above mentioned WACC rates for those sectors). For making costs comparable, the CAPEX figures related to investments by final energy demand consumers also need to be annualised, and a flat discount rate of 10% is used for this purpose, a lower rate than in the past that is more in line with the WACC used for the supply sector. The cost accounting approach adopted in the EU Reference scenario maintains comparability of costs across different scenarios, which is key.
2.2. Summary of main results
Figure 2 below presents the projected evolution of EU Gross Inland Energy Consumption. After the 2005 peak, energy consumption is projected to steadily decline until 2040, where it stabilises. Oil still represents the largest share in the energy mix, mostly because of transport demand. Solid fuels see a significant reduction in their share of the energy mix, while the biggest increase is for renewable energy. Natural gas and nuclear energy keep relatively stable shares in the energy mix.
2,000 100%
7
1,800 90% 19
22
14 25 1,600 80%
Renewable 12
1,400 energy 70% 11
11
forms 24
1,200
Nuclear 60% 24
1,000 26 50% 25
800 Natural 40%
gas 37
600 30%
33
400 Oil 33 20% 33
200 10%
Solids 17 12 0 7 0% 6
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 2005 2030 2040 2050
Figure 2: EU28 Gross Inland Consumption (Mtoe, left; shares (%), right)
Source: PRIMES
Energy security
EU energy production (Figure 3) is projected to continue to decrease from around 760 Mtoe in 2015 to around 660 Mtoe in 2050. The projected strong decline in EU domestic production for all fossil fuels (coal, oil and gas) coupled with a limited decline in nuclear energy production is partly compensated by an increase in domestic production of renewables. Biomass and biowaste will continue to dominate the fuel mix of EU domestic renewable production, although the share of solar and wind in the renewable mix will gradually increase from around 17% in 2015 to 36% in 2050.
227
1,000
900
800
700
600 Renewable
energy sources
500 Nuclear
400 Natural gas
300
Oil 200
100 Solids
0 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 3: EU28 Energy Production (Mtoe)
Source: PRIMES
EU's import dependency shows a slowly increasing trend over the projected period, from 53% in 2010 to 58% in 2050. Again renewables deployment, energy efficiency improvements and nuclear production (which remains stable) counteracts the strong projected decrease in EU's fossil-fuel production.
Solid imports as well as crude oil and (refinery) feedstock decline throughout the projection period, while oil products imports slightly increase. Natural gas imports
increase slightly in the long term reaching approximately 370 bcm 27 net imports in 2050.
Biomass remains mostly supplied domestically, although the combination of increased bioenergy demand and limited potential for additional EU domestic supply leads to some increases in biomass imports post-2020 (from 11% of biomass demand in 2020 to about 15% in 2030 and beyond).
Up to 2020, the consumption of gas 28 is expected to remain stable (at around 430bcm in
gross inland terms). Net import dependency of natural gas registers an increase as domestic gas production continues its downward trend. Post 2020, a slight decrease in gross inland consumption of gas (412 bcm in 2030) is projected, as well as further reductions in indigenous production of gas. Net import dependency of natural gas registers an increase as domestic gas production continues its downward trend. The imported volumes of gas are projected to increase between 2015 and 2040 and then to stabilise in the long term, 15% above the 2010 net import level (from 309 bcm in 2010 to 369 bcm in 2050).
27 The conversion rate of 1 Mtoe = 1.11 bcm was used for natural gas, based on the BP conversion
calculator.
28 The imported volumes of gas are projected to increase between 2015 and 2040 and then to
stabilise in the long term, 15% above the 2010 net import level (from 309 bcm to 369 bcm - Figure 3).
228
600
497
500
427 412 420
400 Production 309 310 328
369
300 Net im ports
200
178 118 Gross Inland
87 Consumption
100 59
0 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 4: Gas - production, net imports and demand (volumes expressed in bcm)
Source: PRIMES
Internal energy market and investments
The EU power generation mix changes considerably over the projected period in favour of renewables (Figure 5). Before 2020, this occurs to the detriment of gas, as strong renewables policy to meet 2020 targets, very low coal prices compared to gas prices, and low CO 2 prices do not help to replace coal. After 2020, the change is characterised by further renewables deployment, but also a larger coal to gas shift, driven mainly in anticipation of increasing CO 2 prices.
Gas therefore maintains its presence in the power generation mix in 2030 (at slightly higher levels in the long term compared to 2015). The share of solids/coal in power generation significantly declines, but not before 2020, to 15% in 2030.
4,500 100%
4,000 90%
3,500 80% RES
3,000 70%
Nuclear
2,500 energy
60%
2,000 Gas fired
50%
40% 1,500 Oil fired
30%
1,000 Solids fired
20%
500 10%
0 0% 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 5: EU power generation (net) by fuel (Mtoe – left, shares – right)
Source: PRIMES
Variable renewables (solar and wind) reach around 19% of total net electricity generation in 2020, 25% in 2030 and 36% in 2050, demonstrating the growing need for flexibility in the power system. Wind onshore is expected to provide the largest contribution. Solar PV and biomass also increase over time. Hydro and geothermal remain roughly constant.
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The share of nuclear decreases gradually over the projected period despite some life time extensions and new built, from 27% in 2015 to 22% in 2030.
REF2016 shows increasing volumes of electricity trade over time. The flow between regions increases from 17% in 2015 to 26% in 2020, 29% in 2030 and then stays almost stable for the remainder of the projection period reaching 30% in 2050. Main drivers are intermittent RES power generation and the resulting balancing requirements. Trade is facilitated by the assumed successful development of the ENTSO-E Ten-Year Network
Development Plan 2014 29 as well as pan-European market coupling and sharing of
reserves and flexibility across Member States.
Average retail electricity prices 30 (Figure 6) steadily increase up to 2030 by about 18%
relative to 2010 levels, stabilising around 20% during 2030-2040, after which they start to gradually decrease. The structure of electricity costs changes over time, with the capital cost component (generation and grid costs) increasing significantly in the short term up to 2020, but decreasing afterwards in the longer term. From 2030, the fuel cost component remains stable despite the increase in fuel prices, due to a decreasing share of fossil-fuel combustion. Transmission and distribution costs increase significantly in the longer term, post-2030, partly linked to the need to cater for the increased presence of RES in the power generation mix.
200 Excise tax and VAT on electricity
180
Estimation of RES supporting
160 costs passed on to consumers
140 Transmission, distribution and sales costs
120 Tax on fuels and ETS auction
100 payments
80 Fuel cost
60 Variable non fuel cost
40 Fixed O&M cost
20
0 Annual capital cost
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 6: Decomposition of electricity generation costs and prices (€'2013 MWh)
Source: PRIMES
As a result of the modelling, the carbon price is projected to increase (Figure 7), reflecting both the steadily decreasing ETS cap and the stabilising effect of the Market Stability Reserve. However, the increase in electricity prices due to ETS remains limited despite the significant increase in CO 2 price, as the share of carbon-intensive power generation decreases.
29 Source: https://www.entsoe.eu/major-projects/ten-year-network-developmentplan/ten%20year%20network%20development%20plan%202016/Pages/default.aspx
30 In the PRIMES model, prices differ per type of end-user.
230
2,500 100
90
2,000 80
70 ETS GHGs em issions in
1,500 60 Mt CO2-eq
50 ETS carbon
1,000 40 price (€'13/tCO2)
30
500 20
10
0 0 2015 2020 2025 2030 2035 2040 2045 2050
Figure 7: ETS emissions and carbon prices over time
Source: PRIMES, GAINS
Electricity prices for households and services are projected to increase moderately in the medium term and to decrease slightly in the long term. Prices for industry on the contrary are stable or decrease over time as energy intensive industry maintains an electricity demand profile compatible with base-load power generation and bears a small fraction of grid costs and taxes. Taxes apply mainly on prices for households and services.
Investment expenditures for power supply increase substantially until 2020 driven by renewables targets and developments, but slow down thereafter, until 2030, before increasing again from 2030 onwards notably due to increasing ETS carbon prices reflecting a continuously decreasing ETS cap based on the current linear factor. New power plant investment is dominated by renewables, notably solar PV and wind onshore. Nuclear investment mostly takes place via lifetime extensions until 2030 and in the longer term via new built, such as projected in, for instance, the UK, Finland, Sweden, France, Poland, and other Central European Member States. New thermal plant investment is mainly taking place in gas-fired plants.
350,000 Gas fired
300,000 Oil fired
250,000 Solids fired
Nuclear energy 200,000
Biomass-waste fired
150,000 Solar
100,000 Wind off-shore
50,000 Wind on-shore
Hydro (pumping 0 excluded)
Figure 8: Net power capacity investments by plant type (MWh – for five year period)
Source: PRIMES
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Investment expenditures in demand sectors (Figure 9 – left hand side) over the projected period will be higher than in the past. They notably peak in the short term up to 2020, particularly in the residential and tertiary sectors, as a result of energy efficiency polices. Post-2020 they slightly decline until 2030, before increasing again to 2050. On the supply side (Figure 9 – right hand side), investments peak towards 2020, followed by a decrease, notably explained by a decline in power generation investments.
1,200,000 600,000
Steam
1,000,000 500,000 boilers
800,000 400,000
Tertiary Power
plants - CHP units
600,000 Residential 300,000
Power plants -
400,000 Industry 200,000 electricity
only
200,000 Power grid 100,000
investment
0 0
Figure 9: Investment expenditures (5-year period) - demand side, million €'2013 (left, excluding transport) and supply side, million €'2013 (right)
Source: PRIMES
Transport investments (expenditures related to the turnover of rolling stock) steadily increase over time but maintain a relatively stable share of GDP.
The relative weight of energy-related spending in households' expenditure 31 increases in
2020 compared to 2015 (7.5% compared to 6.8%), stabilising until 2030 before decreasing again until 2050 (6.1%).
Moderation of energy demand
In 2020, primary energy consumption decreases by 18.4% (relative to the 2007 baseline, i.e. how the energy efficiency target is defined), more than the sum of national Member States' indicative energy efficiency targets but still falling slightly short of the 2020 indicative EU energy efficiency target of 20%. In 2030, energy consumption is projected to decrease (again relative to 2007 baseline projections) by 23.9%. Primary energy demand and GDP continue to decouple (Figure 10), which is consistent with the trends observed since 2005. Energy efficiency improvements are mainly driven by policy up to 2020 and by market/technology trends after 2020.
31 Share of energy system costs for the residential sector (fuel costs and annualised capital costs of
energy related investment expenditures) in total households' consumption
232
200
180
160
140 Primary
120 energy
100 GDP
80 Energy
intensity 60
40
20
0 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 10: Decoupling of EU energy use and intensity from GDP (2005=100) Source: Commission calculations based on PRIMES and GEM E3
The distribution of final energy consumption across sectors remains broadly similar to the current picture, all the way to 2050, with transport and the residential sector comprising the lion's share of final energy consumption (32% and 27% of final consumption, respectively, in 2030). Industry sees its share in final energy demand slightly decreasing, from 28% in 2005 to 23% in 2050, mostly due to improved energy efficiency in non-energy intensive industries. The tertiary (services and agriculture) sector keeps a stable share of about 17%.
1,400 100%
90%
1,200 28% 26% 25% 23% 23%
80%
1,000 70%
Industry
800 60%
27% 27%
26% 26% 27%
Residential 50%
600 Tertiary
40% 15% 16% 17% 17% 17%
Transport 400 30%
20%
200 31% 31% 32% 33% 33%
10%
0
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 0% 2005 2020 2030 2040 2050
Figure 11: Evolution of final energy demand by sector (Mtoe – left, shares – right)
Source: PRIMES
With regard to the fuel mix in final energy, there is a gradual penetration of electricity (from 22% in total final energy use in 2010 to 28% in 2050). This is because of growing electricity demand as compared to other final energy use and to some electrification of heating (heat pumps) and to a limited extent in the transport sector.
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1,400 100%
Solids 5% 4% 3%
2% 1%
90% 1,200
Oil 80%
34% 32% 36% 35%
1,000 42% 70%
800 Gas 60%
22% 22%
50% 23% 22%
600 Electricity
40% 24%
400 30% 27% 28%
Heat (from CHP 22%
25%
and District 20% 20%
200 Heating)
10% 4% 5% 5%
5%
Other 4%
0 0% 5%
10% 10% 11% 11%
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 2005 2020 2030 2040 2050
Figure 12: Evolution of final energy demand by fuel (Mtoe – left, shares – right)
Source: PRIMES
Energy intensity of the industrial sectors remains approximately constant in the medium term, as additional energy demand is due to the increase in production activity. In the long term however energy demand decreases, even though activity in terms of value added progresses. This is due to the energy efficiency embedded in the new capital vintages which replace old equipment and structural changes towards higher value added and less energy-intensive production processes, such as in iron and steel or non-ferrous metals.
200 Index 1995=100
180
160
140
120
100
80
60
40
20
0 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Energy Intensity Final Energy
Value Added Trend 1995-2008
Figure 13: Industrial energy demand versus activity (value added)
Source: PRIMES
In the residential sector, energy demand remains below 2015 levels throughout the projection period. Energy demand decouples from income growth more than would be suggested by extrapolation of trends as the efficiency policies drive energy intensity improvements fast in the medium term; in the long term however the rate of improvements decreases due to the absence of additional policies.
234
350 100%
13
90% 17 16 15
300 Renewables 8
80% 8 8 9
250 70%
Distr. Heating 23
25 27 60% 32
200 Electricity
M toe in % es 50%
150 S har
40%
Gas 39
100 30% 37 39
38 Oil
20%
50
10% 14
Solids 10 9
6 0 0%
4 3 2 1 95 00 05 10 15 20 25 30 35 40 45 50 2010 2020 2030 2050 19 20 20 20 20 20 20 20 20 20 20 20
300
Residential Energy Demand Energy for Heating in
versus Private Income
250 kWh/sqm Index 1995=100
180 200
160
150 140
120
100 100
50 80
60 0
95 00 05 10 15 20 25 30 35 40 45 50 40
19 20 20 20 20 20 20 20 20 20 20 20 20
0
Energy Intensity Final Energy 00 05 10 15 20 25 30 35 40 45 50 Income Trend 1995-2008 20 20 20 20 20 20 20 20 20 20 20
Figure 14: Final energy demand in the residential sector
Source: PRIMES
The activity of the transport sector shows a significant growth (Figure 15), with the highest increase in 2010 to 2030, driven by developments in economic activity. Historically, the growth of final energy demand in the transport sector has shown strong correlation with the evolution of transport activity. However, a decoupling between energy consumption and transport activity has been recorded in the past years. The decoupling between energy consumption and activity is projected to continue and even to intensify in the future.
235 240 240
220 220
200 200
GDP
180 GDP 180
100 100 160 160
1995= 140 Passenger 1995= 140
Freight
Index transport transport
120 activity
Index
120 activity
100 100 Energy for Energy for
80 passenger freight transport 80 transport
60 60 Source:
1995 2010 2020 2030 2040 2050 1995 2010 2020 2030 2040 2050 PRIMES TAPEM &TREMOVE
Figure 15: Trends in transport activity and energy consumption Source: PRIMES and GEM-E3; For aviation, passenger transport activity includes domestic, international
intra-EU and international extra-EU aviation
Electricity use in transport is expected to increase steadily as a result of further electrification of rail and the uptake of alternative powertrains in road transport. However, its share is projected to remain limited in REF2016, increasing from 1% currently to 2% in 2030 and 4% in 2050 (Figure 16). The uptake of hydrogen would be facilitated by the increased availability of refuelling infrastructure, but its use would remain low in lack of policies adopted beyond the end of 2014.
Liquefied natural gas becomes a candidate energy carrier for road freight and waterborne transport, especially in the medium to long term, driven by the implementation of the Directive on the deployment of alternative fuels infrastructure and the revised Trans European Transport Network (TEN-T) guidelines which represent important drivers for the higher penetration of alternative fuels in the transport mix. However, the potential of gas demand developments in the transport sector do not fully materialise in REF2016, suggesting that additional policy incentives would be needed to trigger further fuel switching.
Diesel is projected to maintain its share in total final energy demand in transport by 2030, slowly decreasing its share only during 2030-2050. Consumption of gasoline declines considerably until 2030, continuing the declining trend from 1995 and stabilizes from thereon to 2050. Consumption of jet fuels in aviation increases steadily by 2050 due to the strong growth in transport activity and despite improvements in energy efficiency.
236
400 Shares (%)
4 2 2
350 Hydrogen 2 6 6 4 3 4 6
14 6
300 Electricity 16 17
18 Biofuels
250
Gaseous
M toe 200 54
Other fossil 54
150 54 51
Kerosene
100 Diesel
50 Gasoline
26
19 16 15
0
95 00 05 10 15 20 25 30 35 40 45 50
19 20 20 20 20 20 20 20 20 20 20 20 2010 2020 2030 2050
Figure 16: Final energy demand in transport by fuel type
Source: PRIMES-TREMOVE; Biofuels include biomethane used in transport
Oil products would still represent about 90% of the EU transport sector needs (including maritime bunker fuels) in 2030 and 86% in 2050, despite the renewables policies and the deployment of alternative fuels infrastructure which support some substitution effects towards liquid and gaseous biofuels, electricity, hydrogen and natural gas.
Decarbonisation:
CO 2 emission reduction
In REF2016, the binding energy and climate targets for 2020 will be met by assumption. However, current policy and market conditions will not deliver achievement of either the EU 2030 targets or the EU long-term 2050 decarbonisation goal.
Total CO 2 emissions are projected to be 22% below 1990 levels by 2020. In 2030, CO 2 emissions reduce (relative to 1990 levels) by 32%. Most of these emissions are energy related, and this part also determines the overall trends. Non-energy related CO 2 emissions mainly relate to industrial processes, and remain rather stable. Land-use related
CO 2 emissions are discussed below in the LULUCF section.
Emission reductions in the ETS sectors are larger than those in sectors covered by the Effort Sharing Decision (ESD) as current legislation implies a continuation of the reduction of the ETS cap with 1.74% per year over the projected period leading to a carbon price driving long term emission reduction. In the ESD sectors there are no further drivers beyond market forces (e.g. rising fossil fuel prices) and the continued impact of adopted policies such as CO 2 standards for vehicles or energy performance standards for new building to further reduce energy and consequently emissions.
CO 2 emissions can be decomposed in the components GDP, Energy Intensity of GDP and Carbon Intensity of Energy. The Energy Intensity of GDP component declines due to structural changes in the economy and increasing energy efficiency in all sectors. The decrease of carbon intensity of energy supply becomes an increasingly significant component over the period. This is mainly due to Renewable Energy policies in the short term and the ETS in the medium to long term.
On a sectorial level, CO 2 emissions decrease in all sectors. Figure 17 shows a steep
decrease in power generation, whereas emissions in the field of transport decrease at much slower pace between 2010 and 2050, and the transport sector becomes the largest
source of CO 2 emissions after 2030. Non-energy and non-land use related CO 2 emissions
237
(e.g. industrial processes) reduce only slowly throughout the projection period; however
they only represent a small share of total CO 2 emissions.
5,000
4,500 Process and other CO2
em issions 4,000
Transport 3,500
3,000 Tertiary
2,500 Residential
2,000 Industry
1,500
Energy branch 1,000
500 Power generation/District heating
0 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 17: Evolution of CO 2 emissions (Mt) by sector
Source: PRIMES
Renewable Energy
In 2020, the renewables share in gross final energy consumption reaches 21% in 2020, while in 2030, it reaches 24%.
In the short term, the set of EU and national specific policies that promote renewables (notably implementation of supportive financial support such as feed-in-tariffs) drive significant penetration of renewables in power generation. By 2020, renewables in power
generation are projected to increase to 35.5% (RES-E indicator 32 ) or 37.2% of net
electricity generation, of which 52% are projected to be variable renewables – wind and solar. This implies an acceleration compared to observed trends, in particular in those countries that currently facing difficulties to reach their targets. Beyond 2020 support schemes are 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.
32 Calculated according to the definitions of the RES Directive used also for the pertinent provisions
of Eurostat statistics
238
6 to 12% 2020 6 to 12% 2030
13 to 25% 13 to 25% 26 to 42% 26 to 42% 43 to 70% 43 to 70% 71 to 79% 71 to 79%
MA CY MA CY
Source: PRIMES Source: PRIMES
Figure 18: RES-E shares across EU Member States in 2020 and 2030
While renewables provide growing shares in electricity generation (up to 56% in 2050 of net power generation in overall EU28), 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, 25% in 2030 and 36% in 2050. 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 and 25% by 2050. 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, 255 GW in 2030 and 367 GW in 2050, 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 and 11% in 2050. PV capacity is projected to reach 137.5 GW in 2020, 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. PV capacities continue to increase due to the low costs and installed capacity reaches 183GW in 2030 and 299GW in 2050.
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, 22% in 2030 and 31.5% in 2050 33 . Pure biomass/waste plant capacities
33 Calculated following Eurostat definitions, i.e. excluding energy consumed by Industrial sectors
and refineries for on-site CHP steam generation
239
(excluding co-firing) reach 51.6 GW in 2020, up from 21.7 GW in 2010, 53.2GW in 2030 and 57.3 GW in 2050. The share of biomass products in total inputs rises from 68% in 2015 to 79% in 2050, whereas waste products, including industrial waste, represent the remaining quantities.
The relative contribution of hydro generation remains rather constant at 10-11% of total net generation, with small hydro slightly increasing. Net installed capacity increases by 19GW in the time period from 2010 to 2050; 8.5GW are planned investments in hydroreservoirs between 2010 and 2020. Beyond this period the majority of investments are in small run-of-river plants.
Looking at the decomposition of change of RES-E relative to 2010, it is also important to highlight the negative contribution of electricity demand savings. This means that electricity demand increases over the period, and therefore requires even more RES investments than constant demand would otherwise suggest.
Figure 19: Decomposition of change of RES-E relative to 2010, in % terms
Source: PRIMES
The renewables share in heating and cooling increases from 17% in 2015 to 22% in 2020, reaching 25% in 2030. The use of renewables in final demand for heating and cooling is the main driver of RES-H&C increase in the short term, but its contribution first decreases and then stagnates in the long term. Final consumption of renewable energy in the industrial sector (excluding derived heat) is the second contributor to renewable energy in the heating and cooling sector. In the long-term, renewables in CHP and heat plants (e.g. district heating), as well some deployment of heat pumps, drive further increases of the RES-H&C share. In terms of district heating fuel input, the share of solids and oil decreases considerably, as well as the share of gas. Biomass and waste as well as other renewables and electricity in fuel input increase, representing almost 42% of fuel input in 2020 and 88% in 2050 (in comparison to 31% in 2010) – excluding heat from CHP. Energy efficiency, implying lower demand for heat in all sectors, is also
240
an important driver in the medium and long term, as it tends to reduce demand for renewable heating and cooling, all else equal.
Figure 20: Decomposition of change of RES-H&C relative to 2010, in % terms
Source: PRIMES
The RES-T share reaches 11% in 2020. The development of bio-fuels is the main driver in the short term, but its contribution stagnates in the long term, as the share of biofuels in total fuels used in transport remains stable, around 6%. The biofuel penetration is mainly driven by the legally binding target of 10% renewable energy in the transport sector. Projections also take into consideration specific Member States' mandatory blending obligations and tax incentives, as well as the ILUC Directive. Renewables in electricity, combined with the relative increase of electricity use (albeit modest in share terms), is the main contributor to RES-T in the long term.
Figure 21: Decomposition of change of RES-T relative to 2010, in % terms
Source: PRIMES
241
Non-CO 2 emission reduction
Non-CO 2 emissions (CH4, N2O and F-Gases), account currently (2013) for 18% of total
EU GHG emissions (excluding LULUCF). They have decreased significantly (32%) between 1990 and 2013. They are expected to further decrease by 29% below 2005 levels in 2030 (-46% compared to 1990 levels), and to stagnate later on. CH 4 emissions – which have the largest share in this aggregate - are projected to decrease above average (33% due to declining trends in fossil fuel production, improvements in gas distribution and waste management) and N 2 O emissions fall below average (17%) until 2030, both remaining flat thereafter. F-Gases would reduce by half between 2005 and 2030, largely driven by EU and Member State's policies (i.e. the 2014 F-gas regulation and mobile air conditioning directive); F-gases would increase somewhat between 2030 and 2050 in line with economic developments. Except for a very minor fraction from some specific
industries, non-CO 2 emissions fall under the ESD.
1,000
900
800 Other
700 AC & refrigeration
600 Wastewater
500
Waste 400
300 Industry
200 Energy
100 Agriculture
0 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 22: Non CO 2 GHG emissions
Source: GAINS
The non-CO 2 emission trends and their drivers vary by sector.
Agriculture is responsible for about half of all non-CO 2 emissions and is expected to increase its share in total non-CO 2 until 2030. While the agricultural non-CO 2 emissions have reduced by 22% between 1990 and 2013, they are projected to roughly stabilize at current levels as a result of different trends which compensate each other, such as decreasing herd sizes (both of dairy cows and of non-dairy cattle) but increasing milk yields. Slightly reduced use of mineral fertilizer through improved efficiency (2% less in
2030 than in 2005) leads to corresponding reductions in N 2 O emissions from soils.
Improved manure management (e.g. through anaerobic digestion) also delivers minor emission reductions. The Common Agricultural Policy influences, inter alia, livestock numbers/intensities and the Nitrogen Directive and the Water Framework Directive impact on the use of fertilizer.
Waste is currently the second most important sector emitting non-CO 2 . There, a substantial reduction between 2005 and 2030 is expected (70%), strongly driven by environmental legislation, such as the Landfill directive and improvements in waste management as well as an update in inventory methodology of historic landfills that results in increased historic emissions and subsequent increased reductions of these
emissions in the near to mid-term future. Also an increasing amount of CH 4 is recovered
242
and utilised, thereby impacting on these trends towards lower emissions. After 2030, however, a moderate increase is projected, reflecting trends in economic development.
CH 4 and N 2 O emissions from the energy sector (incl. transport) are expected to decrease
by 36% from 2005 to 2030, and further 26% between 2030 and 2050. The main reductions come from less coal-mining and crude oil production in the EU, together with reduced emissions from power generation with fossil fuels. On the other hand, transport is expected to generate an increasing share of energy sector non-CO 2 emissions (N 2 O from road transport being the most important contributor), growing from 12% in 2005 to 15% in 2030 and 20% in 2050 within the energy aggregate.
Emissions from air conditioning and refrigeration decrease by half from 2005 until 2030, also thanks to existing legislation (i.e. the new 2014 F-gas Regulation and the Mobile Air Conditioning systems Directive).
Most of the non-CO 2 emissions from industry – overall a minor non-CO 2 sector - are
covered by the EU ETS (production of adipic and nitric acid, and of aluminium). The resulting incentive in combination with relatively cheap abatement options and (previous) national legislation cut emissions quite rapidly, to, in 2030, only a fifth of those in 2005. For the period after 2030 slight increases are projected in line with economic trends.
Emissions from the wastewater sector and remaining other sectors are projected to increase moderately in line with economic development over the whole period covered.
LULUCF emissions and removals
The EU28 Land Use Land Use Change and Forestry (LULUCF) sector is at present a net
carbon sink which has been sequestering annually on average more than 300 Mt CO 2
over the past decade according to the UNFCCC inventory data 34 . In REF2016, the
LULUCF sink is expected to decline in the future to -288 Mt CO 2 eq in 2030 from -299 Mt CO 2 eq. in 2005 and decreases further after 2030. This decline is the result of changes
in different land use activities of which changes in the forest sector are the most important. These changes are driven partly by the increase in timber demand for all uses (including the increase in bioenergy demand that is expected in order to reach the RES targets in 2020). Figure 23 shows the projection of the total EU28 LULUCF sink in REF2016 and the contribution from different land use categories.
At present, the carbon sink in managed forest land (-373 Mt CO 2 eq. in 2010 without
applying any accounting rules 35 ) is the main component of the LULUCF sink. The
managed forest land sink is driven by the balance of forest harvest and forest increment rates (accumulation of carbon in forest biomass as a result of tree growth). Forest harvest
is projected to increase over time from 516 million m 3 3 in 2005 to 565 million m in 2030
due to growing demand for wood for material uses and energy production. Along with the aging of EU forest – which reduces the capacity of forest to sequester carbon – the
forest increments are projected to decrease from 751 million m 3 in 2005 to 725 million m 3 in 2030. As a consequence, the rate of accumulation of carbon (i.e. the sink) in
34 See: http://unfccc.int
35 The GHG accounting approach for LULUCF differs from other emission sectors. Notably, forest
management is not accounted compared to historic emissions, but against a so called Forest Management Reference Level. This means that the accounted removals from the LULUCF sector are much smaller than the reported removals seen by the atmosphere.
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managed forest land declines by 32% until 2030. This is partially compensated by a continuation of increasing trend in carbon sink from afforestation and decreasing trend of
emissions from deforestation which decline from 63 Mt CO 2 in 2005 to 20 Mt CO 2 eq. in 2030. Carbon sequestration from afforested land increases steadily to 99 Mt CO 2 eq. by 2030, as new forests continue, albeit at slower rate, to be established. In addition, young forests that were established over the last 20 years get into a phase of high biomass production.
Activity in the agricultural sector (on cropland and grassland) has a smaller impact on the total LULUCF sink than the forest sector. Still, net carbon emissions from cropland are projected to decline by some 18% by 2030 compared to 2005 as soils converge towards soil carbon equilibrium over time. In addition, perennial crops (miscanthus, switchgrass and short rotation coppice) that typically sequester additional carbon in soil and biomass contribute to decreasing cropland emissions. By 2030, 0.9 Mha of perennial crops are expected to be cultivated. The grassland sink increases to around -19 Mt CO 2 eq. in 2030 as land continues to be converted to grassland e.g. through cropland abandonment while at the same time the total grassland area slightly declines over time due to afforestation and the expansion of settlements.
Figure 23: Development of the EU28 emissions/removals in the LULUCF sector
in Mt CO 36 2 until 2050
Source: GLOBIOM-G4M
Research, innovation and competitiveness
Although REF2016 does not deal explicitly with research and innovation, it does tackle directly the penetration of new technologies. The approach is in two steps. First, assumptions are made on techno-economic characteristics and technological learning
curves based on latest scientific evidence 37 . Figure 24 presents an illustration of the RES
power technologies assumptions used in REF2016. Second, the model endogenously selects the most economically viable technologies at each point in time, leading to further technological cost reduction as technologies are deployed at increasingly larger scales.
36 Emissions from deforestation and harvested wood products are included in “Forest land” in
contrast to UNFCCC inventories
37 See notably the European Commission's Joint Research Centre ETRI 2014 report, available at:
https://setis.ec.europa.eu/publications/jrc-setis-reports/etri-2014
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The development of solar photovoltaics (PVs) starts from lower costs than in the previous Reference Scenario and has a positive learning curve throughout the projection period. This translates into significant deployment of solar PVs in REF2016, especially in Southern Europe.
Although wind onshore costs are already competitive with many conventional technologies, the remaining potential for learning is estimated to be small, but costs can decrease due to the size of turbines and their height; very small scale wind is the only exception and still has high learning potential.
There remains large uncertainty about the costs for offshore wind and there have been cost increases due to previously unforeseen difficulties and logistics. Surveys have identified significant potential of cost decrease due to economies of scale and possibilities of improvement in logistics, but these cost decreases are likely to occur only towards 2030. As such, offshore wind developments in REF2016 are more conservative than in past exercises.
400
350
300
250
200
150
100
50
0 2005 2010 2015 2020 2030 2040 2050
Solar PV North of Europe Solar PV South of Europe Solar Thermal South of Europe with storage Wind offshore - remote Wind offshore close to coast Wind onshore
Figure 24: Illustrative levelized cost of electricity for selected RES technologies (expressed in
€'2013/MWh-net)
Source: NTUA based on PRIMES
Compared to the previous Reference scenario, the costs of nuclear investment have increased and also the costs for nuclear refurbishments have been revised upwards. Although lifetime extensions of nuclear power plants remain economically viable in most cases, investments in new built plants are lower compared to previous projections.
The construction of power plants equipped with carbon capture and storage (CCS) technologies is developing at a very slow pace, and is dependent on public support (e.g. EEPR and NER300). Geological restrictions as well as current political restrictions on storage are also reflected. For these reasons, CCS costs are assumed higher than in previous Reference scenarios. Uptake of carbon capture and storage (CCS) in power and industry beyond supported demonstration plants remains very slow and occurs only towards the end of the projection period, driven by increasing ETS carbon prices.
On the demand side, demand for electric appliances continues to increase. However, there is an uncoupling between appliance stock and energy consumption due to the technological progress facilitated by eco-design regulations.
Car manufacturers are expected to comply with the CO 2 standards by marketing vehicles
equipped with hybrid system, which are becoming more appealing to the consumers
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thanks to lower costs. Electrically chargeable vehicles emerge around 2020 and are kickstarted by existing EU and national policies as well as by incentive schemes aiming to boost their penetration. The share of activity of total electric vehicles in the total activity of light duty vehicles reaches 15% in 2050 (Figure 25). Fuel cells would add an additional 2% by 2050. Other energy forms such as liquefied petroleum gas (LPG) and natural gas maintain a rather limited share.
7,000 Shares (%)
3 2 2 2
6,000 8 5 6
5 9
20
5,000 Fuel Cell
Pure Electric 54 5
31 4,000 Plug-in hybrid
m 54 Hybrid
G pk 3,000 ICE Gaseous 5 45
ICE Diesel 2,000
ICE Gasoline 33
1,000 42 32 22
0 14
95 00 05 10 15 20 25 30 35 40 45 50 Source:
19 20 20 20 20 20 20 20 20 20 20 20 PRIMES TREMOVE 2010 2020 2030 2050
Figure 25: Evolution of activity of light duty vehicles by type and fuel 38
Source: PRIMES-TREMOVE
Energy system costs (Figure 26) increase up to 2020. Large investments are undertaken driven by current policies and measures (Figure 26). Overall, in 2020 energy system costs constitute 12.3% of the GDP, rising from 11.4% in 2010 and 11.2% in 2015, also
driven by projected rising fossil fuel prices 39 . Despite further fossil fuel price increases,
between 2020 and 2030 the share remains stable and decreases thereafter, as the system reaps benefits from the investments undertaken in the previous decade (notably via fuel savings). In this period, the share of energy system costs in GDP is gradually decreasing, reaching levels close to 2005 by 2050.
38 Light duty vehicles include passenger cars and light commercial vehicles.
39 Total system costs include total energy system costs, costs related to process-CO
2 abatement and non-CO 2 GHG abatement.
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Evolution of energy system costs Decomposition of relative to GDP (%) energy system costs
(%) 14.1
12.1
D P
/G 10.1 72 66
c o
s ts
8.1 84
78
m
y s
te 6.1
y s
4.1
E n e rg
16 22 28 34
2.1 2010 2020 2030 2050
0.1
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050 CAPEX OPEX
Figure 26: Projected evolution of energy system costs Source: PRIMES, Energy system costs exclude ETS auction payments, given that they result in
corresponding auction revenues.
-
3.Description of modelling set-up for the policy scenarios developed with
PRIMES
Policy scenarios developed in this Impact Assessment rely first on a number of scenarios used in other impact assessments underpinning other 2016 Energy Union policy proposals, notably the Impact Assessments underpinning the Energy Efficiency Directive, the Effort Sharing Regulation, and the proposals on Electricity Market Design.
All policy scenarios build on the EU Reference Scenario 2016 40 .
In addition, coordination policies are assumed which enable long term decarbonisation of the economy. Coordination policies replace the "enabling conditions" which have been modelled in the 2030 framework Impact Assessment and the 2014 Impact Assessment on 2030 Energy Efficiency targets.
3.1. EUCO27
In October 2014, the European Council decided on the energy and climate 2030
framework. 41 The following was agreed among the Heads of States and Governments:
• Substantial progress has been made towards the attainment of the EU targets for
greenhouse gas emission reduction, renewable energy and energy efficiency, which need to be fully met by 2020.
• Binding EU target is set of an at least 40% domestic reduction in greenhouse gas
emissions by 2030 compared to 1990.
40 Full description of the EU Reference Scenario is available above
41 http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf .
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• This overall target will be delivered collectively by the EU in the most costeffective
manner possible, with the reductions in the ETS and non-ETS sectors amounting to 43% and 30% by 2030 compared to 2005, respectively.
• A well-functioning, reformed Emissions Trading System (ETS) with an
instrument to stabilise the market in line with the Commission proposal will be the main European instrument to achieve this target; the annual factor to reduce the cap on the maximum permitted emissions will be changed from 1.74% to 2.2% from 2021 onwards.
• An EU target of at least 27% is set for the share of renewable energy consumed in
the EU in 2030. This target will be binding at EU level.
• An indicative target at the EU level of at least 27% is set for improving energy
efficiency in 2030 compared to projections of future energy consumption based on the current criteria. It will be delivered in a cost-effective manner and it will fully respect the effectiveness of the ETS-system in contributing to the overall climate goals. This target will be reviewed by 2020, having in mind an EU level of 30%.
• A reliable and transparent governance system is to be established to help ensure
that the EU meets its energy policy goals, with the necessary flexibility for Member States and fully respecting their freedom to determine their energy mix.
These requirements are reflected in the scenario called the European Council (EUCO) scenario with a 27% energy efficiency target for 2030 (EUCO27).
The table below summarises the assumptions on climate, renewable energy and specific energy efficiency policies in the EUCO27 scenario that have been modelled.
Table 1: Policy assumptions in EUCO27 scenario
EUCO27 This scenario is designed to meet all 2030 targets set by the European Council:
• At least 27% share of renewables in gross final energy consumption • 27% primary energy consumption reduction (i.e. achieving 1369
Mtoe in 2030) compared to PRIMES 2007 baseline (1887 Mtoe in 2030).
• At least 40% GHG reduction (wrt. 1990) • 43% GHG emissions reduction in ETS sectors (wrt 2005) • 30% GHG emissions reduction in Effort Sharing Decision sectors
(wrt 2005) Main policies and incentives additional to Reference: Revised EU ETS
• Increase of ETS linear factor to 2.2% for 2021-30 • After 2030 cap trajectory to achieve 90% emission reduction in 2050
in line with Low Carbon Economy Roadmap.
Renewables policies
• Renewables policies necessary to achieve 27% target, reflected by
renewables values applied in electricity, heating & cooling and transport sectors.
Residential and services sector
• Increasing energy efficiency of buildings via increasing the rate of
renovation and depth of renovation. In this model, better
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implementation of EPBD and EED, continuation of Art 7 of EED and dedicated national policies are depicted by the application of energy efficiency values (EEVs).
• Financial instruments and other financing measures on the European
level lowering the cost of capital for investment in thermal renovation of buildings. This, together with further labelling policies for heating equipment, is depicted by a reduction of behavioural discount rates for households from 12% to 11.5%.
• More stringent (than in Reference 42 ) eco-design standards banning
the least efficient technologies.
Industry
• More stringent (than in REF2016) eco-design standards for motors.
Transport
• CO 2 standard for cars: 85g/km in 2025; 75g/km in 2030 and 25
gCO 43 2 /km in 2050 .
• CO 2 standards for vans: 135g/km in 2025; 120g/km in 2030; 60g/km
in 2050 44 .
• 1.5% average annual energy efficiency improvements for new
conventional and hybrid heavy goods vehicles between 2010 and 2030 and 0.7% between 2030 and 2050.
• Measures on management of transport demand:
-
-recently adopted/proposed measures for road freight, railways
and inland navigation 45 ; - gradual internalisation of transport local externalities 46 as of 2025
and full internalisation by 2050 on the inter-urban network.
Non-CO 2 policies
• In 2030 carbon values of EUR0.05 applied to non-CO 2 GHG emission
order to trigger cost-effective emission reductions in these sectors inclu in agriculture.
• After 2030, carbon values set equal to EU ETS carbon price level).
3.2. EUCO30 scenario
The table below summarises the assumptions on a specific energy efficiency policy scenario reaching a 30% energy efficiency target. As this scenario built on EUCO27, only the differences that illustrate the increases level of ambition are listed. Assumptions are further explained below the table.
Table 2: Assumptions in EUCO30 scenario
42 REF2016 does not include the revisions of existing ecodesign measures that are required by their
implementing regulations or any future measures under this directive which are currently under discussion.
43 On current test-cycle
44 On current test-cycle
45 Directive on Weights & Dimensions, Fourth railway package, NAIADES II package, Ports
Package
46 Costs of infrastructure wear & tear, congestion, air pollution and noise
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EUCO30 As EUCO27 except:
• 30% primary energy consumption reduction target is set
(i.e. achieving 1321 Mtoe in 2030) compared to PRIMES 2007 baseline (1887 Mtoe in 2030). This equals a reduction of primary energy consumption of 23% compared to historic 2005 primary energy consumption (1713 Mtoe in 2005).
Main policies and incentives additional to Reference:
Energy efficiency policies:
Residential and services sector
• Further increasing of energy efficiency values compared to
EUCO27.
• More stringent (compared to EUCO27) eco-design standards
banning the least efficient technologies.
• Policies facilitating uptake of heat pumps
Transport
• CO 2 standard for cars: 80g/km in 2025; 70g/km in 2030 and 25
gCO 2 /km in 2050.
• CO 2 standards for vans: 130g/km in 2025; 110g/km in 2030;
60g/km in 2050.
• Additional measures on management of transport demand
-
-Modulation of infrastructure charges for HDVs according
to CO 2 emissions leading to faster fleet renewal.
-
-Eco-driving. - Deployment of Collaborative Intelligent Transport Systems.
Non-CO 2 emissions reduction policies
• No policy incentive until 2030.
3.3. EUCO3030 scenario
This scenario builds on the EUCO30 scenario, but increases the share of renewable energy to 30%, via the use of renewables values mimicking further developments of unspecified policies across Member States and sectors. Other assumptions are kept the same as in EUCO30. The exception is the modelling of ETS and non-ETS: GHG emission reductions are allowed to go beyond the greenhouse gas reduction targets as agreed in the 2030 framework, both in the ETS (in practice the ETS carbon price trajectory was kept the same as in EUCO30) and the non-ETS sectors.
3.4. CRA scenarios and variants
CRA scenario
Building on the EUCO27 scenario, a specific renewable energy baseline policy scenario – reaching the same targets – was developed. Instead of focusing on a cost-effective development of renewable energy across the EU, it assumes the continuation of current support policies by Member State, and further differentiates investment costs assumptions in power generation across Member States and technologies. All other
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assumptions, notably as regards ETS and electricity market functioning, are kept unchanged. Regarding ETS in particular, the ETS price is an outcome of the modelling work.
The main characteristics of this scenario are described in the table below, with additional details on input assumptions provided afterwards.
Table 3: Assumptions in CRA scenario
CRA As EUCO27 except:
• Support schemes in 2020 reflect policy developments under
preparation, mostly feed in premium schemes to be granted after auctions. This is different than in REF2016 or the EUCO scenarios, where only policies in place by end of 2014 were reflected, by construction of REF2016.
• In contrast to Reference Scenario and EUCO scenarios, a
continuation of Member States' support schemes policies for renewable energy in the power generation sector post-2020 is modelled; such policies phase out post-2030.
• In contrast to REF2016 and EUCO Scenarios, additional
differentiation in risk premium factors is applied to renewables technologies in the power sector (as add-ons) and these are differentiated by technology and by Member State (in REF2016 and EUCO Scenarios, no country-specific risk premiums are introduced). Regarding technologies, less mature technologies (with higher WACCs than onshore wind or solar PV for instance) include tidal, geothermal, offshore wind, biogas, biomass solid and bioliquids. Regarding Member States, differences in WACC reflect the outcome of the
DiaCore project 47 , but are recalibrated to be in line with the
WACCs taken by PRIMES for other investment projects.
• Renewables values for the power sector are put to 0 in 2025
and 2030 and replaced by detailed modelling of specific policies in power generation.
• No Priority Dispatch as a general rule. Specific exemptions are
applied for certain categories, e.g. (a) small scale renewables, (b) emerging technologies and (c) industrial CHP.
• Grid connexion charges reflect current practices per Member
State, which means notably deep costs (and not shallow) for offshore wind
• Incentives, absence of them or even effective banning of
certain resources from the market like self-generation and small scale generation reflecting current practices. This notably means no net metering allowed beyond what is considered in Reference scenario
CRA_regio
47 See http://diacore.eu/
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This variant builds on the main CRA scenario, but includes the following changes: instead of national support, support to renewables is being regionalised. Specifically, the EU is split into 5 main regions:
• Nordic/Baltic countries: this region includes the following countries: SE, FI, LV,
LT, EE
• British Isles: this region includes the following countries: UK, IE • Central Europe: this region includes the following countries: DK, NL, BE, LU,
FR, DE, PL, HU, CZ, SK, SI, AT
• South East Europe: this region includes the following countries: IT, BG, RO, EL,
CY, MT, HR
• Iberian Peninsula: this region includes the following countries: ES, PT
Concretely, this means that within each region, support levels are harmonised, per technology. In addition, the WACC assumed for investment decisions is also harmonised. Specifically, an average weighted WACC for the region is calculated, based on initial WACCs per Member State and taking account of the relative share in renewables investments in the CRA scenario for each country in the region. In addition, since a broad market at regional level implies broadening the funding, the procedures and the guarantees, a small reduction of the weighted average WACCs is being applied. The difference from the weighted average does not exceed 0.5pp.
It is also important to note that this variant aims at mirroring, to the extent possible, the overall renewables investment levels of the CRA scenario at EU level and within each region. This is necessary to ensure comparability of the results, and to test implications on deployment of renewables across countries and impacts on overall investment and system costs. As such, support levels necessary to reach the renewables deployment of the CRA scenario and ETS prices are an outcome of the modelling work.
CRA_crossborder
This variant is an intermediate case between the main CRA scenario, and the CRA_regio variant. Specifically, it has been constructed by assuming that it uses in 2030 85% of CRA assumptions (support levels and WACC) and 15% of CRA_regio. The percentages are 90% and 10% respectively in 2025.
CRA_countryspec
This variant builds on the CRA scenario, but assumes that for the Member States with the initially highest WACCs for renewables investment projects, a guarantee scheme is put in place, reducing the cost of debt of the project, and therefore the overall WACC. The assumption is that the WACC decreases by 15% for all technologies in the selected Member States. This scenario also tries to mirror overall renewables investment levels, to ensure comparability of the results, as mentioned above in the case of CRA_regio.
CRA_techspec
This variant focuses on the sector specific risks of renewables investments projects. That is, contrary to CRA_countryspec, the focus is not on specific Member States but rather on specific renewables technologies, namely, tidal, geothermal, offshore wind, biogas, biomass solid and bioliquids. These are the technologies with initially a risk premium in the CRA scenario as compared to more mature renewables technologies. As in
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CRA_countryspec, a 15% decrease in the WACC is assumed for these projects, on the basis of the expected benefits of a guarantee of the debt finance of the project.
3.5. Modelling input parameters for the PRIMES scenarios and variants
RES values
Renewables policies necessary to achieve 27% target (in EUCO27 and in EUCO30) and 30% (in EUCO3030) are reflected by renewables values applied in electricity, heating and cooling and transport sectors. Renewables values are used in order to ensure costefficient renewables target achievement at European level.
The renewables value is a shadow price, a signal of potential costs per unit of renewable energy not achieved (relative to the target) which is internalized in the optimizing behaviours of actors and thus leads to higher renewables uptake. Renewables values do not describe in detail the renewables supporting policies, but are introduced if needed, in addition to the supporting policies, so as to complement them and reach the renewables target. The renewables value should not be confused with feed-in tariffs or green certificates, because it does not model any sort of power purchasing agreement with the renewables developers and the renewables projects compete on equal economic grounds with other forms of energy.
Renewables values needed to be slightly increased with more ambitious energy efficiency efforts in 2030 to achieve a share of renewables of at least 27%. They needed to be increased even more to reach a share of 30% renewables in the case of EUCO3030. However, as described above, the renewables values are significantly reduced in the CRA scenario, as they are replaced in the power generation sector by concrete policies, differentiated by Member State, and mimicking existing renewable support policies.
The decrease in renewables values for heating and cooling between Reference Scenario and policy scenarios is due to the impacts of additional energy efficiency in those scenarios.
Energy Efficiency values
The EEV, as described above in modelling terms, are used to simulate increasing energy efficiency obligations related to thermal integrity of houses and buildings, implying reduced consumption of fuels and electricity. Currently, such obligations are chiefly driven by the Art 7 of the EED but in addition some Member States have also put in place national policies aiming at renovation of the building stock (notably fiscal policies and financial incentives). As EEV increase step-wise by scenario and in time, they drive a faster pace of investments in renovations (as demonstrated by renovation rates) as well as increasing depth of renovations from an energy perspective (as demonstrated by the increased energy savings of the renovations). Other energy efficiency policies such as eco-design, labelling etc. act in addition to the EEV by influencing the choice of equipment technologies and their turnover over time.
All details on the use of energy efficiency values can be found in the Energy Efficiency Directive Impact Assessment. The table below shows, that significant energy efficiency values are needed to achieve higher energy efficiency levels. To achieve 23.9% of energy reductions in 2030, only EUR5 per toe are necessary. To achieve 27%, an EEV of EUR338 per toe is already needed. This values needs to be increased to EUR713 toe to
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achieve an energy efficiency level of 30% in 2030. No further changes were performed in the dedicated renewables scenarios, when compared to the EUCO scenario they build upon.
Table 4: Main policy variables
Main policy Ref20 CR CRA_re CRA_crossbor CRA_countrys CRA_techs EUCO EUCO EUCO30 variables 16 A gio der pec pec 27 30 30 (2030)
Carbon price ETS sectors 34 38 41 38 38 29 42 27 27 (EUR'13/ t of CO 2 )
Carbon value non
ETS
sectors 0 0 0 0 0 0 0 0 0
(EUR'13/ t of CO 2 )
Average
Renewabl es value 11 4 4 4 4 4 7 16 58 (EUR/
MWh)
Average
Renewabl es value -
Power 0 0 0 0 0 0 6 23 51 generation
(EUR/
MWh)
Average
Renewabl es value - heating and 20 6 6 6 6 6 6 6 62 cooling sector
(EUR/M
Wh)
Average
Renewabl es value -
Biofuels 12 12 12 12 12 12 12 12 16 support
(EUR/M
Wh)
Energy efficiency value 5 338 338 338 338 338 338 713 713 (EUR/
MWh)
Source: PRIMES
Modelling of Eco-design regulations
The Eco-design policy aims at reducing energy consumption of energy-related equipment and appliances by promoting product varieties which embed higher energy efficiency. Depending on implementing measures and voluntary agreements, the eco-design regulations certify specific energy consumption by product variety and eventually provides for mandatory requirements for certain products. The requirements impose a minimum bound on energy performance of products. The bounds are set for the next two to five years. This implies that the menu of technologies for consumer choices in the future is restricted to product varieties which have performances exceeding the minimum threshold value. The menu will still allow selecting technologies which perform above minimum threshold value; the choice will depend on relative costs, perception of technical risks and the policy context. The Eco-design regulations, combined with the
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labelling directive, are playing an important role to remove uncertainties regarding technical risks and those stemming from lack of information.
PRIMES considers equipment in an aggregated manner, looking at the equipment performance in heating and cooling, water heating, cooking, lighting and (white and black) appliances.
REF2016 is assumed to include the currently adopted eco-design regulations. The effects additional of Eco-design regulations are then simulated to intensify towards the 2030 horizon relative to REF2016 and across the energy efficiency scenarios. Moving from 2030 to 2050, the effects are simulated to intensify further relative to the 2020-2030 period and approach technical potential in the very ambitious cases. The learning effects are modelled to be relatively lower until 2030 than after 2030.
Modelling of transport policies
CO 2 standards for new cars and light commercial vehicles
The tightening of CO 2 standards post-2020 is a key assumption, leading to improvements in energy efficiency and CO 2 emissions reduction in transport. The CO 2 standards assumed in the policy scenarios are provided in Table 5 for cars and in Table 6 for light commercial vehicles.
Table 5: Assumptions on CO 2 standards (gCO 2 /km)
for new cars across scenarios 48
Scenario CO 2 standards (gCO 2 /km) for new cars
2025 2030 2050
EUCO27 85 75 25
EUCO30 80 70 25
Source: PRIMES
Table 6: Assumptions on CO 2 standards (gCO 2 /km)
for new light commercial vehicles across scenarios 49
Scenario CO 2 standards (gCO 2 /km) for new light commercial vehicles
2025 2030 2050
EUCO27 135 120 60
EUCO30 130 110 60
Source: PRIMES
Vehicle efficiency of new heavy duty vehicles
The following improvements in specific fuel consumption of new heavy duty vehicles were assumed:
-
-1.5% per year on average in all scenarios. EUCO27, EUCO30
48 On current test-cycle
49 On current test-cycle
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Recently adopted/proposed measures
Measures adopted after the cut-off date of Reference scenario 2016 (i.e. Directive on
Weights & Dimensions 50 ) and measures already adopted by the Commission and in discussion by co-legislators (i.e. Fourth railway package 51 , NAIADES II package 52 , and the Ports Package 53 ) are assumed to apply in all scenarios. The input for modelling draw
on the respective Impact Assessments.
Fair and efficient pricing for sustainable transport
Gradual internalisation of the costs of infrastructure wear & tear, congestion, air pollution and noise in the pricing of road transport on the inter-urban network is assumed from 2025 onwards. For rail, internalisation of the costs of air pollution, noise and congestion is assumed from 2030 onwards; for inland waterways internalisation of the costs of air pollution is assumed from 2030 onwards. In scenarios EUCO27 and EUCO30, the levels of the charges are gradually increased from 2025/2030 to 2050, when they become equal to the values of the 2014 Handbook on external costs of
transport 54
Modulation of the infrastructure charges according to CO 2 emissions for heavy goods
vehicles (HGVs) is assumed to apply in all scenarios except for EUCO27; it is assumed to apply on the inter-urban network from 2025 onwards. Starting from the average infrastructure charge in each Member State, a linear incremental variation is assumed for HGVs with higher emissions than average; a similar linear variation is assumed for HGVs with lower emissions than average (by HGVs category). The measure is assumed to apply similarly to the Euro class-differentiation of network-wide tolls and implies revenue neutrality.
Collaborative Intelligent Transport Systems (C-ITS)
Deployment of C-ITS in road transport has been assumed in all scenarios except for EUCO27.
-
1.In scenarios EUCO30, the input assumption for modelling draws on the central
scenario of a Cost Benefit Analysis (CBA) study carried out by Ricardo AEA 55
Eco-driving
Promotion of eco-driving is assumed in all scenarios except for EUCO27; the input
assumption used for modelling draw on "EU Transport GHG: Routes to 2050?" project. 56
It is assumed that virtually all drivers would be trained by 2050 (for road and rail). Savings from training decline to 2050 due to technology effects. No variation in the level of intensity of the measure is assumed between scenarios.
50 SWD(2013)109 final
51 SWD (2013) 10 final
52 SWD( 2013 ) 324 final
53 SWD( 2013 ) 181
54 Source: http://ec.europa.eu/transport/themes/sustainable/internalisation_en.htm
55 Source: http://ec.europa.eu/transport/themes/its/c-its_en.htm
56 "EU Transport GHG: Routes to 2050?" final report is available at:
http://www.eutransportghg2050.eu/cms/assets/EU-Transport-GHG-2050-Final-Report-22-06- 10.pdf
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Coordination policies
In this modelling exercise, all scenarios (except Reference) achieve decarbonisation in 2050 and hence assume an overall policy framework which enables this. Given that concrete policies will most likely have to be proposed in order to fulfil the necessary conditions in infrastructure, technology, market coordination, the elements of this framework which go beyond the drivers and policies specified in the policy scenarios are called coordination policies. Coordination policies replace the "enabling conditions" which have been modelled in the 2030 framework IA (in decarbonisation scenarios) and the 2014 IA on energy efficiency target.
In the past modelling exercises, enabling conditions were present in all decarbonisation scenarios. Enabling conditions meant that because of good anticipation of future GHG emission reduction commitments, all conditions were met in infrastructure, technology learning, public acceptance and market coordination so as to enable the decarbonisation. In other words, enabling conditions enabled to maximize the effectiveness of policy instrument which aim at driving strong GHG emission cuts. These enabling conditions were fully costed in decarbonisation scenarios.
These assumptions have been revisited considering that concrete policies will most likely have to be proposed in order to fulfil the necessary conditions in infrastructure, technology, market coordination, etc. Consequently, enabling conditions are replaced by coordination policies as indicated in the list included in Table 7. These coordination policies will be proposed by the Commission post 2020. Coordination policies are fully costed in the scenarios, as it was the case with enabling conditions. It is important to make a distinction between 2 types:
• coordination policies related to ongoing infrastructure developments that will
enable a larger exploitation of cost-effective EE, RES, GHG abatement options after 2020.
• coordination policies related to R&D and public acceptance that are expected to
be needed to meet long term decarbonisation objectives, and have effects post 2030
Table 7: Summary of coordination policies assumed
Enabling conditions in the 2030 Impact New approach
Assessment
Intelligent grids and metering (also for Coordination policy post 2020
EVs) (Partly accomplished in REF2016 2016 -
implementation of the 3rd Internal Energy Market package).
Infrastructure to harvest decentralised as Coordination policy post 2020 well as remote RES for power generation
Carbon transportation and storage coordination policy post-2030 (CCS is infrastructure and acceptance indispensable for decarbonisation towards
2050)
Gas and hydrogen: (technological progress coordination policy post-2030 (advanced enabling mix of hydrogen and bio-gas in storage is necessary and in that time gas supply and possibility to use hydrogenperspective)
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Enabling conditions in the 2030 Impact New approach
Assessment
based storage for balancing RES power)
Battery technology development (for Reference scenario 2016 has assumptions electric and plug-in hybrid vehicles) and on battery technology development and fuel cells fuel cells which are rather conservative,
consistent with the logic of a Reference scenario, i.e. without additional policies stimulating R&D, infrastructure or purchase.
For the decarbonisation scenarios,
increased R&D, expectations and learning
effects lead to lower technology costs for
electrification technology (for electric and
plug-in hybrid vehicles) and fuel cells.
Recharging infrastructure Coordination policy post 2020
(based on the Directive on the deployment of alternative fuels infrastructure)
Market acceptance (of electrification) Coordination policies post 2020
(supported by the implementing measures following the Directive on the deployment of alternative fuels infrastructure)
Innovation in biofuels Coordination policy with impacts post 2030
These are biomass related innovation and agriculture policies assumed to develop so as to allow the development of new generation bio-energy feedstock (basically lingo-cellulosic crops) at large scale. As a result, a new industry would emerge ranging from agriculture, industrial-scale collection and pre-treatment, bio-refineries with new conversion technologies, product standardization and commercialisation.
Overcoming some market barriers to Part of 2020-2030 policy mix as described
Energy Efficiency in Buildings in assumptions on policy options.
Heating equipment and appliances As above technology uptake in the domestic sector
Energy efficiency innovation diffusion in As above
Industry
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4.Set-up of modelling scenarios in the various impact assessments underpinning the 2016 energy union policy proposals
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This section aims at describing how modelling scenarios were designed, how they can be used to describe a baseline or policy scenario and which questions they try to address in the Impact Assessments (IA) underpinning the various 2016 Energy Union proposals.
Role and use of the EU Reference Scenario 2016
A common starting point to all Impact Assessments is the EU Reference Scenario 2016 ('REF2016'). It projects greenhouse gas emissions, transport and energy trends up to 2050 on the basis of existing adopted policies at national and EU level and the most recent market trends. This scenario was prepared by the European Commission services in consultation with Member States. All other PRIMES scenarios build on results and modelling approach of the REF2016.
Although REF2016 presents a comprehensive overview of the expected developments of the EU energy system on the basis of the current EU and national policies, and could be considered as the natural baseline for all IA, it fails doing so for an important reason. This scenario does not have in place the policies to achieve the 2030 climate and energy targets that are already agreed by Member States in the European Council Conclusions of October 2014. It also does not reflect the European Parliament's position on these targets.
Therefore, although it was important for all initiatives to have a common "context" in order to ensure coherent assessments, each Impact Assessment required the preparation of a specific baseline scenario, which would help assess specific policy options relevant for the given Impact Assessment.
A central policy scenario: EUCO27
Because of the need to take into account the minimum agreed 2030 climate and energy targets (and the 2050 EU's decarbonisation objectives) when assessing policy options for delivery of these targets, a central policy scenario was modelled. This central policy scenario, (called "EUCO27"), reaches by construction the 2030 targets (40% greenhouse gas emissions reductions compared to 1990, a split of 43% and 30% in emissions reduction between the ETS and ESD sectors, compared to 2005, a share of renewables of 27% and an energy efficiency target of 27%).
Concrete specifications on assumptions were made by the Commission in order to reach the relevant targets by using a mix of concrete and yet unspecified policies. A detailed description of the construction of this scenario is presented in Chapter 4 of the EED IA and in its Annex IV.
This scenario is the central scenario for all Impact Assessments. Additional baseline and/or policy scenarios were prepared for each Impact Assessment, addressing the specific issues to be assessed by each initiative, notably which measures or arrangements have to be put in place to reach the 2030 targets, how to overcome market imperfections and uncoordinated action of Member States, etc.
This approach of separating a central policy scenario reaching the 2030 targets in a costeffective manner and specific scenarios that look into specific issues related to implementation of cost effective policies enables to focus on "one issue at a time" in the respective separate analysis. It enabled to assess in a manageable manner the impacts of several policy options and provide elements of answers to problems specified in the respective 2016 Impact Assessments, without the need to consider the numerous possible combinations of all the options proposed under each respective initiative.
The Impact Assessment accompanying the proposal on an Effort Sharing Regulation (ESR)
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The EUCO27 and EUCO30 scenarios were used in the Impact Assessment underpinning the Effort Sharing Regulation Proposal of July 20 2016 to assess the implications for specific Member States of setting national targets to reduce greenhouse gas emissions in the ESR sectors, following the guidance provided by EU leaders to use a methodology that reflects fairness, solidarity and cost-effectiveness.
In this Impact Assessment, the projections in the non ETS sectors of the EUCO27 and EUCO30 scenarios, representing the cost effective implementation of the agreed 2030 climate and energy targets, are compared with 2030 targets defined purely on the basis of GDP per capita criterion only, as well as other important elements such as starting point of the target trajectory and additional flexibilities, to assess any concerns related to cost efficiency, fairness and environmental integrity.
The Impact Assessment accompanying the proposal for the revision of the Energy Efficiency Directive
Regarding the Impact Assessment accompanying the proposal for a revised Energy Efficiency Directive, one central question to be addressed concerned the level of the energy efficiency target for 2030. This reflects the European Council conclusions from October 2014 which leave the issue of 2030 energy efficiency target still open.
In this context, the baseline is a situation where the EU would achieve the minimum commonly agreed target among the three EU Institutions, that is, 27% energy efficiency, or the EUCO27 policy scenario. Additional policy scenarios were then developed leading to higher energy efficiency levels, notably the EUCO30 scenario as well as scenarios achieving energy efficiency savings going up to 40% (30, 33, 35 and 40% respectively). The additional policy scenarios were then compared to EUCO27 baseline in order to identify the impacts of increasing energy efficiency level only.
The Impact Assessment accompanying the proposal for the revision of the Renewable Energy Directive
Regarding the Impact Assessment accompanying the proposal for a revised Renewable Energy Directive, various scenarios are developed, building on the central EUCO27 policy scenario. Each scenario focuses on specific issues to be addressed in each renewable energy sector, namely, electricity, heating and cooling, and transport.
Regarding the electricity sector, a scenario was built focusing on what the continuation of current practices would mean for reaching the overall RES target. In fact, EUCO27 considers harmonised additional incentives to renewable electricity projects as well as the same financing conditions across Member States (but not technologies) for renewable electricity investments over the 2020-2030 period. Contrary to the EUCO27 scenario, the baseline scenario (so-called Current Renewables Arrangement – 'CRA') models continuation of current national specific renewable support schemes, designed at national level, also after 2020, in order to reach the 27% target. A continuation of differences in investment environments and financing conditions for renewable electricity projects across Europe is therefore assumed. Additional details on the construction of the CRA scenario are presented above. Policy scenarios build on this baseline scenario by testing the impacts of various designs and scopes of renewable support schemes, direct financial support or collaboration across borders to develop renewable electricity projects with the aim of establishing which policies can contribute best to further improve cost efficiency related to renewables deployment.
Regarding the heating and cooling sector, the EUCO27 scenario considers a set of yet unspecified policies in the heating and cooling sector, contributing in a cost effective manner to achieving the overall 2030 target. However, given the absence of evidence of
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concrete policies by Member States post-2020, it is also relevant to consider as a baseline scenario a case where such policies would not materialise. REF2016 was then used as an approximation for such a baseline scenario. Various policy options are then compared to this baseline, with in mind comparing policies that could ensure a deployment of renewables in the heating and cooling sector in line with deployment occurring in the central policy scenario.
Finally, for the transport sector, it is pertinent to consider as baseline the EUCO27 scenario. Under this scenario, Member States, as in REF2016, are assumed to maintain post-2020 biofuels blending obligations, where those exist thus maintaining the 7% cap on food-based bio-fuels. The key policy question to be assessed for this sector concerns the implications of additional policies promoting the use of advanced biofuels and the phase-out of food-based biofuels as well as dedicated measures for maritime and aviation sector. Policy scenarios used to illustrate different choices in these matters build on the EUCO30 scenario in order to keep consistency with scenarios used in Strategy for Lowemission Mobility (see below) and for the reasons specified below. These policy scenarios are, in some cases, more ambitious in terms of the transport sector contribution to the overall 2030 RES target, which would imply smaller role of other sectors.
Staff Working Document accompanying Strategy for Low-emission Mobility
While the SWD does not analyse policy options like an IA would do, it analyses impacts of the EUCO27 and EUCO30 scenarios in transport sector and presents several pathways/scenarios that are even more ambitious options in three fields: low- and zeroemission vehicles; low emission alternative energy for transport; efficiency of the transport system. Those additional, more ambitious pathways/scenarios are built on EUCO30 scenarios in order to combine ambitious energy efficiency with other actions. Two key scenarios on bio-fuels (BIO-A and BIO-B) are common with the transport section of the IA for revision of the Renewable Energy Directive. In addition, the same transport-related measures have been used to define the more ambitious pathways/scenarios in the SWD on Low-emission mobility and the more ambitious policy options in the Energy Efficiency Directive IA; they have been however packaged differently to address their respective purpose.
The Impact Assessment accompanying the Market Design Initiative
Similar to the other 2016 Energy Union initiatives, EUCO27 was chosen as the starting point (i.e. context) of the baseline for the Market Design Initiative (so-called "Current Market Arrangements" – CMA). The EUCO27 scenario is the most relevant to the objectives of the initiative, as it provides information on the investments needed and the power generation mix in a scenario in line with the EU's 2030 objectives.
As all analysis focuses on the power sector, all assumptions exogenous to the power sector were taken from the EUCO27 scenario. This also applied for the energy mix, the power generation capacities at each period, the fuel and carbon prices, electricity demand, technology costs etc. The scenario achieves the 2030 targets as in EUCO27.
However and importantly, the CMA scenario differs from the EUCO27 scenario by including existing market distortions, as well as current practices and policies on national and EU level. It assumes implementation of the Network Codes, including the Capacity Allocation and Congestion Management and the Electricity Balancing Guidelines (the latter in their proposed form). CMA does not consider explicitly any type of existing support schemes for power generation plants, neither in the form of RES-E subsidies nor in the form of capacity remuneration mechanisms. A full description of this scenario is included in Annex IV of the Market Design Impact Assessment. Policy scenarios are
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then prepared to address specific issues covered by the market design initiative, and are compared to the CMA baseline scenario.
Higher energy efficiency levels and the role of the EUCO30 scenario
Because the specific target for energy efficiency in 2030 remains an open question, it was also necessary to take into account in all Impact Assessments the potential impacts of higher energy efficiency levels, notably of 30% target which is explicitly mentioned by the European Council conclusions. The achievement of this 30% energy efficiency target, in combination with other agreed 2030 targets, is illustrated by the 'EUCO30' scenario.
The EUCO30 scenario is one of the policy scenarios investigated in detail in the Energy Efficiency Impact Assessments and one of the central scenarios used in the SWD accompanying the Strategy for Low-emission Mobility. It was also used in the Effort Sharing Regulation Impact Assessment to test the potential implications of higher energy efficiency levels on the cost-effective level of greenhouse gas emissions reductions at Member State level in the non-ETS sector.
The EUCO30 scenario results are also presented in the Renewable Energy Directive Impact Assessment. Regarding the electricity market design, changing the level of energy efficiency has marginal effects on the issues to be addressed in the power generation sector, and therefore this scenario is not used for comparing results of policy options in that sector. Regarding the heating and cooling sector, the implications are, however, more significant, and therefore, this issue is addressed in more detail in the relevant sections of the Impact Assessment.
Likewise, in the transport sector, the policy scenarios presented in the Renewable Energy Directive Impact Assessment build on the results of the EUCO30 scenario. This is because compared to EUCO27 scenario, EUCO30 includes a set of specific energy efficiency policies in the transport sector which have a bearing on policy options directly related to the use of biofuels. For instance, EUCO30 leads to higher market penetration of electric vehicles, which needs to be taken into account before looking at the remaining needs for additional biofuels policies.
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5.Description of analytical models used – other models
5.1. Whole-electricity System Investment Model (WESIM) 57
WESIM is a comprehensive electricity system analysis model simultaneously balancing long-term investment-related decisions against short-term operation-related decisions, across generation, transmission and distribution systems, in an integrated fashion. In this context, WESIM is a holistic model that enables optimal decisions for investing into generation, network and/or storage capacity (both in terms of volume and location), in order to satisfy the real-time supply-demand balance in an economically optimal way, while at the same time ensuring efficient levels of security of supply. A key feature of WESIM is in its capability to simultaneously consider system operation decisions and infrastructure additions to the system, with the ability to quantify trade-offs of using alternative smart mitigation measures, such as DSR, new network technologies and distributed energy storage, for real-time balancing and transmission and distribution network and/or generation reinforcement management. The model also captures potential conflicts and synergies between different applications of distributed resources (e.g.
57 Source: http://www.wholesem.ac.uk/documents/icl-model-summary
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demand side response - DSR) in supporting variability management at the national level and reducing necessary reinforcements in the local distribution network.
The objective function of WESIM is to minimise the overall system cost, which consists of cost of investment in generation, network, interconnection and emerging flexible network, storage and DSR technologies and cost of operating the system, which includes generation operating cost and cost of supply interruptions. The problem is subject to power balance constraints, reserve and adequacy constraints, carbon emission constraints, power flow limits in transmission, distribution and interconnection, generation plants’ dynamic characteristics, and DSR and storage operational constraints.
WESIM can be used to assess the electricity infrastructure development and system operation within UK or EU. Different network topologies are generally used to balance the complexity and accuracy of modelling. Different levels of market integration can be modelled in WESIM through distinctive levels of energy exchanges cross-border, sharing of security or various operating reserves, e.g. country, regional, EU levels. WESIM optimises the generation, storage, and DSR dispatches taking into account diversity of load profiles and renewable energy profiles (hydro, wind, PV, CSP) across Europe, in order to minimise the additional system capacity to meet security requirements.
Regarding the local distribution networks, WESIM uses a set of representative networks that follow the key characteristics of different type of real GB (and EU member states) distribution network. These representative networks are calibrated to match the actual electricity distribution systems. The mismatches in control parameters between the actual GB and representative networks characterised using this process, are less than 0.1%.
Regarding DSR modelling, WESIM broadly distinguishes between the following electricity demand categories: (i) weather-independent demand (ii) heat-driven electricity demand (space heating / cooling and hot water), (iii) transport demand and (iv) smart appliances’ demand. Different demand categories are associated with different levels of flexibility. Losses due to temporal shifting of demand are modelled as appropriate. Flexibility parameters associated with various forms of DSR are obtained using detailed bottom-up modelling of the different types of DSR.
5.2. Description of the modelling set-up for the policy options tested with WESIM
Hourly electricity prices are modelled with WESIM for five separate years: 2020, 2025, 2030, 2040 and 2050. The scenarios modelled used a number of common assumptions, as presented in the table below.
Table 8: Common assumptions
Assumption Description
Price base Monetary values are in Euros and were converted to 2015 price base.
Modelling 2020, 2025, 2030, 2040, 2050
Years
Countries • All EU Member States (28 countries)
modelled
• Non-EU countries: Switzerland, Norway, Albania, Serbia, Montenegro,
Bosnia, Macedonia.
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Hourly demand Hourly demand was derived using PRIMES annual electricity demand profiles projections in combination with hourly demand profiles taken from ENTSO-
E’s TYNDP 2016. 58 The following demand profiles were used:
• 2020: ENTSO-E’s ‘Expected 2020’ hourly demand profiles by country.
• 2025: Apply the average of 2020 and 2030 hourly profiles, i.e. if the weighting of hour one in 2020 was 1% and the weighting of hour one in
2030 was 2%, use a weighting of 1.5% for hour one in 2025.
• 2030: ENTSO-E’s ‘Vision 3’ hourly demand profiles.
• 2040/2050: Assume no change in demand profile after 2030.
Peak demand was calculated as the maximum hourly demand (GW) for a given country in a given year.
Fuel prices Coal, oil and gas prices were taken from PRIMES and converted to constant 2015 prices. Biomass fuel cost forecasts were supplied by Parsons Brinkerhoff and uranium prices from ENTSO-E’s TYNDP 2016.
ETS prices Taken from PRIMES EUCO27 scenario results
Technology Fixed and variable O&M costs: provided by Parsons Brinkerhoff.
costs (RES-E) Capex costs: sourced from PRIMES.
Technology Fixed and variable O&M: provided by Imperial College London. costs
(Conventional Capex costs: Build on PRIMES
technologies)
RES-E Country and technology specific generation profiles were used to capture generation variable renewables generation. These were based on profiles used for the profiles EC’s Roadmap 2050 study.
Electricity Assumed only pumped hydro storage. Distribution level storage was not storage captured, as WESIM does not model distribution networks.
Results from PRIMES scenarios were used to calibrate the deployment mix for both renewable and conventional technologies in EU Member States. Still, due to difference in models, some unavoidable differences remain in the exact power generation mix between the two approaches. The table below summarises the links between the WESIM scenarios and the PRIMES scenarios.
In addition, the same approach was followed to calibrate WESIM for each Member State’s annual electricity demand. As an input, WESIM used data on final electricity demand, plus transmission and distribution losses as a measure for annual electricity demand.
58 Malta is not a member of ENTSO-E. However, we received 2015 hourly electricity demand data
from the Maltese energy regulator, and following an assessment of the similarities in the load profile between Malta and Cyprus we opted to use the ENTSO-E load profile for Cyprus, as a
proxy for Malta’s projected load profile.
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For non-EU countries, deployment scenarios were developed based on ENTSO-E TYNDP 2016 forecasts where possible, supplemented by forecasts from National Renewable Electricity Action Plans (primarily for the Balkan countries). No change in capacity mix was assumed after 2030 for these countries. Projections from ENTSO-E’s TYNDP 2016, Vision 3 were used for electricity demand.
Table 9: PRIMES sources for the different WESIM scenarios
Scenario Deployment scenario
1 WESIM27 PRIMES EUCO27
2 WESIM30 PRIMES EUCO30
3 Removal of preferential market rules PRIMES EUCO27
Interconnection capacity was calibrated in WESIM using ENTSO-E’s TYNDP 2016. Assumptions on transmission capacity were equivalent across scenarios/ sensitivities. As part of WESIM’s cost minimisation algorithm, WESIM also endogenously adds additional interconnection capacity if it was efficient to do so. The following assumptions:
• 2020: Used ENTSO-E reference interconnection capacities for 2020 as an input
into WESIM.
• 2025: Transmission capacity of projects of common interest (PCIs) with a
commissioning date on or before 2025 were added to the 2020 capacity values. Capacity and commissioning dates for PCIs were taken from ENTSO-E TYNDP 2016.
• 2030: Used ENTSO-E interconnection capacities for 2030 as an input into
WESIM.
• 2040/50: No additional interconnection capacity was assumed to have been
installed after 2030. WESIM’s optimisation process forecast additions to
interconnection capacity.
Demand response is another important assumption for this modelling work. The characterisation of DSR is based on the concept of achievable potential, which describes the total amount of demand resources that could be realistically expected to be deployed if enabling policies are put into practice. In the modelling, a distinction was made between curtailable DSR and shiftable DSR, with the split between the two being 60:40 in terms of overall achievable potential. Differentiation between countries was also performed based on the level of DSR they would likely require in the future given renewables penetration and additional needs for flexibility in the electricity system. The table below shows the level of achievable potential assumed across scenarios/ sensitivities, defined as a % of daily electricity demand.
Table 10: DSR potential
Curtailable DSR potential Shiftable DSR potential Total DSR potential
6% 4% 10%
Finally, the last important assumption for this modelling work concerns priority dispatch. Priority dispatch is a market access rule which places an obligation on transmission system operators to schedule and dispatch RES-E generators ahead of all other types of generation. The purpose of priority dispatch is to provide certainty to renewable
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generators that they will be able to sell electricity into the grid at all times (reducing volume risk) and to enable a more rapid integration of RES-E generators into the power system. Currently, priority dispatch is being combined with other forms of support (e.g. FITs & CfDs in UK) that make it profitable to sell electricity on the wholesale market at any price (even below marginal cost). It is implemented for renewable electricity generators, but is relevant only for those with non-zero marginal costs, namely biomass. By default, it is assumed that renewable would continue to receive priority dispatch indefinitely. However, a sensitivity was conducted in which priority dispatch for all renewables was removed from 2020 onwards.
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A NNEX 5 - K EY I NDICATORS
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1.Options to increase renewable energy in the electricity sector (RES-E)
This section presents an overview of the detailed numerical results used in section 5.1. of the Impact Assessment to analyse and compare the different policy options. First, a detailed discussion is included on the potential funding gap that an absence of support schemes for renewable electricity projects would entail. Second, the relevant results of the various PRIMES runs used to assess and compare options are presented.
1.1. Detailed analysis on viability of RES projects and on the need for support schemes in the electricity sector post-2020
This subsection presents in detail the modelling approaches and the results of an analysis of the impacts of the absence of support schemes on the viability of renewables projects over the 2020-2030 period, as summarised under the assessment of policy options in section 5.1 of this Impact Assessment.
Lessons learned from the main PRIMES scenarios
EU Reference Scenario 2016
The EU Reference Scenario 2016 (REF2016) assumes no additional policies post-2020. From a RES perspective, it means no additional policy support beyond the already adopted policies and the assumed additional policies necessary to implement the current EU acquis in the RES area, namely reaching the binding 2020 RES targets.
In this context, by 2020, RES in power generation are projected to increase to 35.5% (RES-E indicator) or 37.2% of net electricity generation, of which 52% are projected to be variable RES (wind and solar). Beyond 2020, support schemes are phased out and further investments in RES are driven by market forces, the ETS and the improvement in the techno-economic characteristics of the technologies.
Still, such additional investments are insufficient to contribute to achieving the 27% RES target. Overall, RES-E reaches 42.5% in 2030 (RES-E indicator), or 42.8% of net electricity generation.
To conclude, no additional policy in any energy or climate field beyond 2020 would lead to a shortfall in RES investments, hampering the achievement of the RES (and of the GHG emission reductions) targets. However and importantly, many initiatives have been or will be implemented in various relevant climate and energy fields, and therefore, REF2016 only very partially answer the question on the need for additional support schemes for renewable energy.
The EUCO27 scenario
As opposed to REF2016, the EUCO27 scenario was constructed with in mind a costeffective achievement of the 2030 climate and energy targets. A detailed description of this scenario is presented in Annex 4.
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This scenario assumes implemented the proposal for a revised ETS post-2020, including a new linear reduction factor. It also models a set of concrete policies in the field of energy efficiency and transport, as well as some additional unspecified policies via the use of energy efficiency values in the residential and tertiary sectors. This scenario also considers improved electricity market functioning and uses RES values to model yet unspecified dedicated policies in the RES sectors to reach the 27% target. In the electricity sector, such RES values are on average equal to 6 €/MWh. Finally, under this scenario, financing conditions are assumed to be the same across Member States (similar WACC) as specific country risks, as in Reference Scenario, are assumed inexistent.
Under this scenario, the RES-E share reaches 47.3% in 2030, or 47.6% of net electricity generation. Installed capacity for RES technologies increases by 34% between 2020 and 2030.
This scenario suggests that under the right framework conditions, namely 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 RES investments to develop such that they effectively contribute to the overall achievement of the RES target. However, there remains a gap, visible because RES-E values had to be used in the model to trigger the necessary investments to achieve a 27% share of renewable energy by 2030.
The EUCO30 scenario
Similar to the EUCO27 scenario, this scenario aims at reaching 2030 targets (in this case 30% energy efficiency in addition to 40% GHG emissions and 27% RES), in a cost effective manner. Again, in this scenario, RES-values are used to simulate the impact of unspecified policies necessary to reach the 27% RES target. The average renewables value is 16€/MWh, more than in the EUCO27 scenario. This implies that more stringent policies would be needed to reach the 27% RES target in case of a more ambitious energy efficiency target. This result is explained by the higher RES value used in the electricity sector (23€/MWh instead of 6€/MWh), which, in turn, is the result of a lower ETS carbon price in EUCO30 than in EUCO27. In other words, this scenario suggests that the investment gap for RES-E projects would increase in the case of more ambitious energy efficiency policies, as such policies tend to decrease the carbon price needed to reach the ETS target, and therefore make renewable electricity projects relatively less profitable.
The CRA scenario
In contrast to the EUCO27 scenario, the CRA scenario is based on the assumption of the continuation of current Member States policies and practices in the renewable energy field. The description of this scenario is detailed in Annex 4, and has similar assumptions in non-RES-related policy fields than the central policy scenario (EUCO27).
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.
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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 remains 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, as well as efficient market functioning. In other words, this scenario differs in its design compared to the EUCO27 scenario via two main features: i/ the costeffective support 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, as under any other PRIMES scenario, the RES investments resulting from the overall policy and economic context as well as incentives have been projected assuming that investors evaluate project specific Internal Rates of Return including the financial incentives and decide upon investing accordingly. The projected RES investments implied directly from the financial incentives are considered as given by the market model which then decides upon the remaining potentially necessary investments (among all power generation technologies) based on pure economic considerations with a view to meeting the RES obligations. In that respect, this scenario does not try to directly answer whether an investment gap would necessarily emerge, but rather that the continuation of current policies and practices would lead to policy support driving more than half of EU investments in renewable electricity projects.
More specifically, one of the results of the CRA scenario is that 59% of RES investments over the 2021-2025 period would be based on public support. This share decreases to 51% for the 2026-2030 period. The following table presents the split by technology and by region. The results show mature RES technologies can be more easily financed without public support, in particular in regions with the highest potential (e.g. Southern Europe for solar, Nordic region for wind onshore). Differences also exist in general between regions, as RES projects seem in general less profitable in British Isles and Central Europe than in other regions.
% of GW new investment driven from support 2021-2025 2026-2030 schemes (CRA scenario
Nordic region Wind onshore 16% 21%
Nordic region Wind offshore
Nordic region Solar and other 100%
Nordic region Biomass solid 0% 0%
Nordic region Sum 15% 19%
British Isles Wind onshore 100% 100%
British Isles Wind offshore 100% 100%
British Isles Solar and other 100% 100%
British Isles Biomass solid 100% 100%
British Isles Sum 100% 100%
Central Europe Wind onshore 81% 58%
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Central Europe Wind offshore 98% 100%
Central Europe Solar and other 67% 22%
Central Europe Biomass solid 93% 91%
Central Europe Sum 84% 61%
Southern Europe Wind onshore 0% 0%
Southern Europe Wind offshore 100% 100%
Southern Europe Solar and other 1% 4%
Southern Europe Biomass solid 18% 58%
Southern Europe Sum 2% 2%
Iberian Peninsula Wind onshore 15% 1%
Iberian Peninsula Wind offshore 100% 100%
Iberian Peninsula Solar and other 20% 26%
Iberian Peninsula Biomass solid 38% 27%
Iberian Peninsula Sum 19% 20%
EU28 Sum 59% 51%
Source: PRIMES – description of which countries are included in each region is provided in Annex 4
Lessons learned from electricity market simulation tools
In addition to PRIMES, which is an energy-system model notably looking at interactions across sectors and variables, it is possible to investigate the viability of RES projects using specific analytical tools focusing on electricity market functioning only.
WESIM
The issue of viability of RES investments has first been investigated with the use of the WESIM model. As described in Annex 4, WESIM is a comprehensive electricity system analysis model simultaneously balancing long-term investment-related decisions against short-term operation-related decisions, across generation, transmission and distribution systems, in an integrated fashion.
For the purpose of this analysis, WESIM has been calibrated to mirror investment patterns as projected by PRIMES in the EUCO27 scenario. The focus of the analysis presented below is to assess whether wholesale electricity market revenues would be sufficient, on their own, to finance the necessary RES investments as projected by PRIMES over the 2020-2030 period. However, this analysis does not consider investment profitability issues for conventional power generation technologies, an issue assessed in detail in the market design IA via other tools.
Assuming overall framework conditions similar to the ones used to build the EUCO27
scenario (e.g. in terms of interconnection, market functioning, ETS prices 59 ), WESIM
determines hourly electricity prices and dispatching and uses this to project a stream of
59 The noticeable exception is that the main scenario developed with WESIM still assumes priority
dispatch for biomass generation over the 2020-2030 period.
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revenues for all RES generation technologies. By comparing overall RES investment and operational costs to this stream of revenues, it is possible to assess the viability of RES projects.
The difference between total annual investment as projected with PRIMES in the EUCO27 scenario and the ones that are not estimated to be viable with WESIM provides an indication of a potential investment gap. This investment gap corresponds to the share of RES investments estimated to not be able to be financed by wholesale electricity market revenues on their own. The analysis performed with this model concludes that the investment gap will amount to EUR 13 billion in 2020; EUR 12 billion in 2025 and EUR
9 billion in 2030 60 . It is important to note that this does not correspond to the level of
public support which would be needed, as only a fraction of the investment cost might need to be supported for the project to become viable.
More specifically, the model results show that only 41% of investments in 2020 could be financed by the market. This share increases to 54% in 2025 and 66% in 2030. Onshore and solar PV become gradually profitable and by 2030, such projects could be financed entirely by the markets, under the specific assumptions considered in this scenario. Conversely, technologies such as offshore wind investments cannot be yet fully financed via electricity market revenues by 2030.
Required Biomas Geotherm Hydro Hydro Offshore Onshore Solar Tida TOTA annual s al reservoir ROR wind wind PV l L
investmen t (€ bn)
2020 0.48 0.00 0.26 0.04 5.54 7.21 8.09 0.24 21.88
2025 0.77 0.00 0.41 0.14 8.74 9.43 5.33 0.37 25.19
2030 0.94 0.23 0.09 0.69 9.61 8.93 6.75 0.50 27.74
Total Biomas Geotherm Hydro Hydro Offshore Onshore Solar Tida TOTA investmen s al reservoir ROR wind wind PV l L
t gap (€bn)
2020 0.48 0.00 0.23 0.00 5.54 3.55 2.91 0.24 12.95
2025 0.00 0.00 0.34 0.00 8.74 0.00 2.26 0.37 11.71
2030 0.00 0.00 0.00 0.00 8.99 0.00 0.00 0.50 9.49
Share of Biomas Geotherm Hydro Hydro Offshore Onshore Solar Tida TOTA investmen s al reservoir ROR wind wind PV l L t financed
by the market
2020 1% 12% 100% 0% 51% 64% 0% 41%
2025 100% 18% 100% 0% 100% 58% 0% 54% 2030 100% 100% 100% 100% 6% 100% 100% 0% 66%
Source: CEPA, central scenario
Two sensitivity analyses were performed. First, the assumption of priority dispatch for biomass was lifted. In this context, biomass units are not forced to operate when their marginal cost is lower than the electricity price in absence of operational support, and therefore, average electricity prices tend to increase. This increases the viability of (other) RES projects and in this context, the share of investments that could be financed
60 For additional details on viability gap of RES-e technology assessed with WESIM methodology,
see Annex 4
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based on electricity market revenues increases as follows: 52% in 2020, 61% in 2025 and 89% in 2030.
Second, another sensitivity was performed to investigate potential impacts of different expectation regarding ETS prices. This extreme case scenario considers that investors in each year take as given the prevailing ETS price, and assume that it remains constant over the life of their project, and do not expect the price to increase over time. This is obviously a simplification, only aiming at illustrating the impact of extreme boundary conditions on the viability of RES projects. Wholesale market revenues received by RES- E generators were amended to reflect this change of assumption. Given that it is difficult to accurately determine the contribution of carbon costs to the total wholesale price in every hour, a less granular approach was therefore used, using average yearly prices instead. Overall, under this assumption, 35% of investments in 2020 could be financed via these revised (theoretical) market revenues, 48% in 2025 and 54% in 2030.
PRIMES market simulation tools
The issue of whether wholesale electricity market revenues would be sufficient to finance investments in power generation is addressed in detail in the MD Impact Assessment.
First, the MD IA simulates market revenues taking as a constant the level of investments provided by the EUCO27 scenario (PRIMES/IEM). It identifies viable and non-viable power generation technologies based on various electricity market functioning assumptions, from status quo to a scenario removing all existing barriers. Potential revenues on day-ahead, intraday and balancing markets are then calculated, and the net profits or losses, as compared to overall costs of investments, are determined. Second, additional projections are provided, where investment decisions become endogenous (PRIMES/OM). A detailed analysis of the results is provided in the MD IA.
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. The benefits of improving the energy-only market are then assessed in the MDI IA but from a RES generation investment profitability perspective, the results are not significantly amended.
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, in the MDI IA. The following table summarises the results for RES technologies. It confirms that mature RES technologies are among the profitable technologies by 2030. Conversely, less mature technologies, such as wind offshore, biomass or solar thermal, remain unprofitable.
Profit or Loss by plant type in M€'13
2020 2025 2030
Lakes 13 384 15 132 17 435
Run of River 10 382 12 065 13 219
Wind onshore 0.323 6 152 20 231
Wind offshore -0.205 -3 152 -3 262
Solar PV (large) -3 207 -0.141 3 644
Solar thermal -1 786 -2 080 -2 900
273
Geothermal 0.158 0.242 0 323
Tidal -2 705 -2 833 -0 320
Biomass -5 938 -7 432 -6 160
CHP biomass -2 958 -3 094 -3 075
RES (small) -9 486 -8 525 -4 126
Source: PRIMES/OM
Conclusions
The various modelling approaches used to analyse the potential viability of RES investments based on market revenues alone, as well as in an overall energy-system context, all converge around the following conclusions:
• Profitability of RES technologies will improve over the 2020-2030 period. The
combination of technological progress, improved market functioning, and increasing ETS prices, among other factors, lead to more and more RES
investments being projected to be viable without support.
• The situation is contrasted depending on the level of maturity of RES
technologies. Even if some less advanced RES technologies would need support to emerge as part of the power generation mix towards 2030, this is likely not the case anymore for most mature technologies, at least towards the end of the 2021- 2030 period, such as hydro, wind onshore and solar PV (at least in some parts of Europe).
• Improving electricity market functioning will overall be beneficial to RES
investments profitability. This is also true as regards confidence of investors in the evolution of ETS prices. Anticipating on future ETS price increases improve the profitability of RES investment projects.
1.2. Main indicators used to compare results of electricity policy options modelled with PRIMES
This subsection presents tables summarising the main results of the various PRIMES modelling scenarios used for the assessment of policy options in the electricity sector. Detailed explained for these results are included in the main part of the report (section 5.1.).
Electricity
indicators Ref2016 CRA CRA CRA CRA CRA
(2030) countryspec techspec regio crossborder
EUCO27 EUCO30
Net Electricity
Generation 3390872 3372371 3373067 3374239 3363306 3369539 3396680 3285630 (TWh) - Renewable
share 43% 50% 49% 52% 50% 49% 47% 49%
of which hydro share 11% 11% 11% 11% 11% 11% 11% 11%
(%) of which wind onshore share 14% 15% 15% 15% 15% 15% 17% 17%
(%) of which wind offshore share 4% 8% 8% 11% 6% 8% 4% 4%
(%) of which solar
share (%) 7% 9% 9% 8% 11% 9% 9% 9%
of which
Biomass & 7% 7% 7% 7% 7% 7% 7% 8%
274 waste share
(%) Average
Electricity 158 166 166 166 168 166 161 157 prices
Average cost of electricity 101 108 108 108 109 107 103 100 generation
ETS carbon
price 34 38 38 29 38 41 42 27
Source: PRIMES
Energy Ref2016 CRA CRA CRA CRA CRA EUCO27 EUCO30 system costs countryspec techspec regio crossborder
Total System 1928 1952.5 1951.0 1961 1951.2 1951 1943 1952 Costs in bn €'13 (average annual 2021-30) change in system 0 24.3 22.8 32.6 23.0 23.2 14.9 24
costs compared to Ref2016 (in bn
€'13) Total System 12.28% 12.43% 12.42% 12.48% 12.42% 12.42% 12.37% 12.43% Costs as % of GDP (average annual 2021-30)
Total System 0.00% 0.15% 0.14% 0.21% 0.15% 0.15% 0.10% 0.15% Costs as % of GDP increase (average annual 2021-30) compared to
REF16 in % points
Total System 2130 2275 2273 2281 2273 2274 2264 2255 Costs in bn €'13
(average annual
2021-2050) change in system 0 145 143 151 143 144 134 125 costs compared
to Ref2016 (in bn €'13)
Total System 11.62% 12.41% 12.41% 12.45% 12.40% 12.41% 12.35% 12.31% Costs as % of GDP (average annual 2021-2050)
Total System 0.00% 0.79% 0.781% 0.83% 0.78% 0.79% 0.73% 0.68% Costs as % of GDP increase (average annual 2021-
2050) compared to Ref2016 in % points
Source: PRIMES
Investment indicators CRA CRA CRA
(2030) Ref2016 CRA27
CRA
countryspec techspec regio crossborder EUCO27 EUCO30
Investment expenditures in power generation (2021- 311663 552761 544188 649884 558000 542093 395403 393970 2030 period)
Investment expenditures in renewables (2021-2030 150431 404130 394090 502666 406862 393311 240131 245414 period)
% of RES investments in total investments in power 48% 73% 72% 77% 73% 73% 61% 62% generation
% of total RES investments
in wind 62% 70% 70% 77% 54% 69% 59% 58%
275 % of total RES investments
in solar 29% 18% 19% 13% 31% 19% 36% 36%
% of total RES investments
in biomass-waste 4% 8% 8% 7% 11% 9% 2% 2%
% of total RES investments in other renewables (hydro, 5% 3% 3% 3% 3% 3% 3% 1%
tidal, etc.) Share of top three MS in
overall RES-E investments 54% 67% 63% 74% 58% 65% 47% 44%
Share of bottom ten MS in
overall RES-E investments 0.7% 0.6% 0.8% 0.4% 2.0% 0.6% 2.2% 2.8%
Source: PRIMES
Social impacts and CRA CRA CRA CRA
affordability Ref2016 CRA27 countryspec techspec regio crossborder EUCO27 EUCO30
issues (2030)
Electricity price
-
-households 212 226 224 226 231 225 218 215 (€/MWh)
RES supporting costs passed on 19 26 25 31 25 25 19 20 to consumers
Electricity price
-
-industry 100 104 104 104 102 103 100 98 (€/MWh)
Energy related production cost - 376363 381358 381293 379351 380087 380917 377935 374087 industry
-
2.Options to increase renewable energy in the heating and cooling sector
(RES-H&C)
2.1. Mainstreaming renewables in heating and cooling supply
Dimension Indicator Option 0 Option Option Option Option 1-1 1-2 2-1 2-2 Source
Average share of small-scale Fraunhofercompanies under N/A 18% 18% 2% 2% own HCOS (in energy assessmnet
Social supply) Maximal share of
small-scale Fraunhofercompanies under N/A 100% 100% 25% 25% own HCOS (in energy assessmnet supply)
Standard deviation
of additional effort PRIMES+o
Economic in terms of RES- H&C shares at MS N/A 2.80% 3.20% 2.80% 3.20% wn
level compared to calculations
cost-effective
Maximal additional effort PRIMES+o
Political asked to a single 0% 4% 6% 4% 6% wn
MS vs. costcalculations
effectiveness
2.2. Facilitating the uptake of renewable energy and waste heat in district heating and cooling systems
276
Dimension Indicator Option 0 Option 1 Option 2 Option 3 Source Öko
Social Consumers empowerement 0 0 + +++ Institut and EC-own
assessment Potential Öko
Economic impact on district heating 0 0 - - Institut and EC-own
operators assessment
Potential fuelÖko
Environmental switching to 0 0 20% 20% Institut and
RES in H&C EC-own assessment
Potential Administrative impacts on
burden administrative 0 + - -
EC-own assessment costs
-
3.Options to increase renewable energy in the transport sector (RES-T)
Option Option Option Option Option
Dimension Option Option 2
Option 2
0 1 (variant (variant
2 Option 4 4 4
-
1)2)
(variant 3 (variant (variant (variant 3) 1) 2) 3)
Social 0 + 0/+ + + + + + +
Economic 0 - - - - - - - - - -
Environmental 0 + ++ +++ +++ + + +++ +++
-
4.Options to empower and inform consumers of renewable energy
4.1. Empower consumers to generate, self-consume and store renewable electricity
Option Option Option Option 3 Option 3 Dimension Indicator 0 1 2 (variant (variant Source
-
1)2)
Potential PRIMES,
Social level of consumers 0 + + +++ ++ EC own
participation assessment
Potential
Economic impact on 0 - - --- - EC own grid costs assessment
Potential contribution PRIMES, Environmental of rooftop 0 - + + EC own
solar PV to assessment RES-E
4.2. Disclosing information for renewable electricity
Dimension Indicator Option 0 Option 1 Option 2 Option 3 Source
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Transparency
Social and data 0 + ++ ++ EC own
reliability assessment
Data coverage:
% of the Natural
energy system 0 change – All RES -
All
covered by approx. E
electricity EC own
50% RES sources
assessment
Economic GOs Changes in Some EC own
financial flow 0 No change
Some change change assessment Reduction in
administrative 0 Marginal Marginal
cost impact impact
-- EC own assessment
Potential for encouraging
consumers to 0 + ++ +++ EC own switch to RES assessment
Environmental contracts Consumer data on CO 2
emissions 0 None None +
EC own assessment through GOs
4.3. Tracing renewable fuels used in heating and cooling and transport
Dimension Indicator Option 0 Option 1 Option 2 Option 3 Source Increase ability
of consumers
Social to choose 0 ++ + + EC own
renewable assessment
fuels Fraud
prevention
through better 0 + + +++
EC own assessment
Economic tracking
Minimise
administrative 0 + + + EC own
burden assessment
Reduce
Environmental sustainability concerns of the 0 + ++ +++ EC own assessment
fuels
-
5.Options to ensure the achievement of at least 27% renewable energy in 2030
5.1. Baseline of 2020 targets
Dimension Indicator Option 0 Option 1 Source
Social Impact of consumer groups 0 - EC own assessment
Economic Reduced cost of capital 0 + EC own assessment
Environmental Reduced GHG emissions 0 + EC own assessment
5.2. EU Trajectory 2021-2030 for achievement of the EU renewables target
Dimension Indicator Option 0 Option 1 Option 2 Source
278
Consumer
Social impacts through avoiding changes 0 ++ + EC own assessment
in policy Encouraging long
Economic term investment 0 ++ + EC own in renewables assessment
Environmental Reducing GHG emissions 0 ++ + EC own assessment
5.3. Mechanisms to avoid an "ambition gap" to the EU renewables target
Dimension Indicator Option 0 Option 1 Option 2 Option 3 Source Avoids
Social distributional 0 + + + EC own
impact assessment
Incentivises
Economic investment in 0 + ++ ++ EC own
RES assessment
Avoids increase in
Environmental emissions by 0 + ++ ++ EC own
correcting any assessment
ambition gap
5.4. Mechanisms to avoid and fill a "delivery gap" to the EU renewables target
Dimension Indicator Option 0 Option 1 Option 2 Option 3 Option 4 Source
Avoids
Social distributional 0 + + + + EC own impact assessment
Incentivises
Economic investment 0 + + ++ ++ EC own in RES assessment
Avoids increase in
Environmental emissions by correcting 0 + + ++ ++ EC own assessment
any delivery gap
-
6.Other results of energy-system modelling scenarios, including a sensitivity scenario and a RES decomposition analysis
This section summarises first the energy-system results of various core scenarios used in this Impact Assessment, while also presenting the results of the sensitivity scenario projecting an increase of renewable energy to 30% in 2030 (EUCO3030 scenario).
In a second subsection, a RES decomposition analysis is provided, presenting in detail the contribution of the various subsectors to the achievement of the overall RES target in the various scenarios considered.
6.1. Evolution of energy system indicators and variables in main scenarios used in this Impact Assessment
This section presents the results of REF2016, of the CRA scenario (baseline scenario for assessing electricity policy options), the EUCO27 scenario, the EUCO30 scenario and
279
the EUCO3030 scenario. This last scenario corresponds to a sensitivity analysis performed, looking at the specific impacts of higher ambition level in renewable
energy 61 . These scenarios help illustrate the scale of the challenge in each renewable
energy sector depending on assumptions as regards overall policy ambition and specific targets in other areas than renewable energy alone.
6.1.1. Energy system indicators
The table below presents the outcome of the various scenarios regarding main energy system indicators. Except in REF2016, the overall renewables share in 2030 is an exogenous input to the scenarios, as scenarios are meant to achieve specific shares of renewable energy. The same logic applies for primary energy consumption, in line with various potential energy efficiency targets.
On the contrary, renewables shares per sector are an outcome of the model. Here, it can be seen that the various scenarios in line with a 27% share in renewable energy do not fundamentally differ, although a scenario with additional energy efficiency (EUCO30) indicates an extra contribution from the electricity and transport sectors, as an overall decrease in heating and cooling demand leads to smaller requirements for renewable energy in that sector. Looking at the variant reaching a 30% share of renewables by 2030, together with 30% energy efficiency, it can be seen that a significant increase in the share of renewable energy in all sectors is projected, and notably in the electricity sector.
Energy System indicators (2030) Ref2016 CRA EUCO27 EUCO30 EUCO3030
Overall RES share (% of GFEC) 24% 27% 27% 27% 30%
RES-E share 42% 49% 47% 49% 54%
RES-H&C share 25% 27% 27% 26% 30%
RES-T share 14% 18% 18% 19% 21%
Total RES consumption (Ktoe) 272957 295374 291507 279377 310262
Gross final consumption of RES for 123824 127007 128049 116637 132899 heating and cooling
Gross final consumption of 128391 147848 142971 142436 156049
electricity from RES
Biofuels consumption 20742 20519 20486 20304 21314
Gross Final Energy Consumption 1133091 1085207 1086070 1040139 1038151 (Ktoe)
61 In this case, a 30% share of renewables by 2030 is assumed, together with 30% energy efficiency
levels.
280
Electricity 302437 299252 302057 292307 287843
Heating and Cooling 485055 455346 453540 422926 424876
Transport 274253 256245 256086 251778 252237
Primary Energy Consumption 1436069 1358072 1369069 1321337 1306157 (Ktoe)
Final Energy Demand (Ktoe) 1081368 1031259 1031401 987097 986214
Source: PRIMES
6.1.2. Environmental indicators
The following table illustrates the GHG emission reductions in the various scenarios. By construction, the CRA, EUCO27 and EUCO30 scenarios are meant to achieve the same level of GHG emissions reductions, overall and between ETS and ESD sectors. This is not the case for the EUCO3030 scenario, where emission reductions are not constrained. In this scenario, much more additional GHG emission reductions come from the ETS sector, which is notably explained by the exogenous assumption of keeping constant the ETS price, as compared to EUCO30. The carbon intensity of power generation is also reduced by 15% compared with EUCO30, mostly due to the decrease of gas use. As such, this scenario illustrates potential additional deployment in the renewable electricity sector, although the scenario outcome does not reflect interactions with the ETS carbon market and would not be in line with the current Commission proposal for a reformed ETS.
Higher ambition in energy efficiency leads to additional GHG emission reductions in demand sectors. Conversely, no drastic change is projected between the CRA and the EUCO27 scenario in decarbonisation patterns.
Environmental indicators (2030) Ref2016 CRA EUCO27 EUCO30 EUCO3030
Total GHG emissions (% change to
1990) -35.2% -40.8% -40.7% -40.8% -43.2%
ETS sectors emissions (% change
to 2005) -37.7% -43.4% -43.1% -43.1% -48.1%
ESD sectors emissions (% change
to 2005) -23.7% -30.1% -30.2% -30.3% -30.7%
CO 2 emissions (in kt CO 2 ) thermal
power plants 881933 760720 773423 756853 646027
Carbon intensity power
generation (per MWhe+MWhth) 0.202 0.177 0.179 0.182 0.157
Power generation, CHP and -41% -49% -48% -49% -56%
district heating GHG emissions (%
281
change compared to 2005)
Industry (only energy related) (Mt -41% -43% -44% -44% -46%
CO 2 eq), (% change)
Residential GHG emissions (%
change compared to 2005) -25% -35% -35% -40% -41%
Tertiary GHG emissions (% change
compared to 2005) -33% -42% -43% -46% -47%
Transport GHG emissions (%
change compared to 2005) -12% -18% -18% -19% -19%
Power generation, CHP and district heating GHG emissions (Mt of CO 2 eq for REF and % 977.5 -13% -12% -14% -26% change from REF for other scenarios
Industry (energy + processes) (Mt
CO 375.8 -3% -5% -5% -9% 2 eq), (% change)
Residential (Mt CO 2 eq), (%
change) 360.8 -13% -12% -20% -20%
Tertiary (Mt CO 2 eq), (% change) 183.2 -15% -15% -21% -21%
Transport (Mt CO 2 eq), (% change) 946.9 -6% -6% -8% -8%
Source: PRIMES, GAINS
6.1.3. Social impacts indicators
From a social impacts perspective, it can be seen that the CRA scenario lead to a higher increase in electricity prices, as compared to EUCO scenarios, showing signs of lack of efficiency in the continuation of current practices, as opposed to a situation where renewables deployment is more cost-effective. This is even more visible when focusing on the calculated renewables supporting costs passed on to final consumers, which increase significantly in CRA as opposed to EUCO scenarios.
On the demand side, the energy purchases are more affected by energy efficiency requirements than by different renewables pathways, as most significant differences appear when comparing EUCO27 and EUCO30 results.
Social impacts and affordability issues
(2030) Ref2016 CRA EUCO27 EUCO30 EUCO3030
Avg. electricity price incr. compared to
2010 price (%) 18% 25% 21% 18% 21%
282
RES supporting costs passed on to
consumers 19 26 19 20 21
Energy Purchases in bn EUR'13
(average annual 2021-30) 1448 1422 1415 1388 1391
Industry 272 273 271 269 268
Residential 417 413 410 397 400
Tertiary 249 245 243 235 236
Transport 510 492 491 486 487
Source: PRIMES
6.1.4. Energy security impacts indicators
Deployment of renewables – together with energy efficiency – is expected to contribute to increased energy security, by lowering the needs for non-diversified energy imports. This can be observed by comparing the results of the various EUCO scenarios, where, as energy efficiency and/or renewable energy ambitions increase, the volume and value of imports decrease. Significant savings in terms of fossil fuel import bills are therefore projected, in particular in the case of the EUCO3030 scenario. In this latter scenario, due to the higher rate of renewables deployment, import dependency is the lowest of all scenarios. However, the increasing net import dependency for biomass (energy and nonenergy uses, including food) should be taken into account.
Impacts on energy security
(2030) Ref2016 CRA EUCO27 EUCO30 EUCO3030
Net Energy Imports
Volume (2005=100) 93 86 86 82 79
Solid 67 57 57 59 53
Oil 88 80 80 79 78
Gas 116 110 110 97 89
Renewable Energy Forms 796 846 848 804 863
Import Dependency 57% 55% 54% 53% 52%
Gas imports (bcm) 325 306 306 270 248
reduction compared to
REF2016 (in bcm) 0 -18 -18 -54 -77
reduction compared to 0% -6% -6% -17% -24%
283
REF2016 (% change)
Value of Fossil Fuel Net
Imports (bn EUR'13)
(average annual 2021-30)
Oil 326 309 309 307 306
Gas 111 107 107 102 99
Solid 12 11 11 12 11
Fossil Fuels Import Bill: absolute results for
REF2016 and % change
compared to REF2016 for 4494 -4.6% -4.9% -6.4% -7.2%
other scenarios (bn EUR '13
-
-cumulative 2021-30)
Source: PRIMES
6.1.5. Total system costs
The table below presents the evolution of overall energy system costs across the scenarios. The most striking feature in the context of this impact assessment is that system costs increase in the CRA scenario as compared to EUCO27, showing the negative overall impacts of the continuation of current practices and policies. This is true for the 2021-2030 period as well as for the whole period up to 2050. As opposed to more energy efficiency or renewable energy scenarios, there are no trade-offs in this case between short and long term costs for the energy system.
The most ambitious scenario, the EUCO3030 scenario, is also the most costly over the 2021-2030 period. The increase in system costs compared to EUCO30 over the 2021- 2030 period corresponds to € 4 billion on average annually. Conversely, costs of EUCO3030 are among the lowest over the 2030-2050 period and EUCO3030 system costs fall closer to EUCO30 results when looking at the 2021-2050 period.
Energy system costs Ref2016 CRA EUCO27 EUCO30 EUCO3030
Total System Costs in bn EUR'13
(average annual 2021-30) 1 928 1 953 1 943 1 952 1 956
change in system costs compared to
Ref2016 (in bn EUR'13) 0 24 15 24 28
Total System Costs as % of GDP
(average annual 2021-30) 12.28% 12.43% 12.37% 12.43% 12.46%
Total System Costs in bn EUR'13
(average annual 2021-2050) 2130 2274.7 2264 2255 2257
284
change in system costs compared to
Ref2016 (in bn EUR'13) 0 145 134 125 127
Total System Costs as % of GDP
(average annual 2021-2050) 11.62% 12.41% 12.35% 12.31% 12.32%
Source: PRIMES
6.1.6. Macro-economic and employment impacts
Macro-economic impacts (including employment and GDP) have been estimated using the E3ME model and the GEM-E3 model, mirroring the approach used in the Impact Assessment for the revision of the Energy Efficiency Directive. The description of these two models and the methodology used for testing potential macroeconomic impacts are presented in detail in the Energy Efficiency Impact Assessment (see for instance Annexes 4.8 and 4.9 of the EE IA).
Both models use as input energy system and investment developments coming from PRIMES scenarios. In the context of this Impact Assessment, the E3ME and GEM-E3 models were calibrated and run for the CRA and EUCO3030 scenarios. Results developed in the context of the Energy Efficiency Impact Assessment, namely for assessing the macroeconomic impacts of REF2016, EUCO27 and EUCO30 scenarios, are also reported.
In terms of methodology, one important element to highlight concerns the treatment of the CRA scenario. In the CRA scenario, the financing conditions for renewable electricity projects are different than in the other scenarios reported in this section, reflecting different status-quo (and more difficult) access to capital market conditions across EU Member States. As such, as compared to EUCO27 results, investment costs are higher, but not so much due to increased capacity installed but rather due to higher risk premiums assumed for the financing of investments. In the GEM-E3 model this has been modelled by the introduction of inefficient capital (i.e. increasing the cost of capital to deliver the same service without increasing the demand for equipment). In the E3ME model, the different financing costs across Member States were also reflected, mirroring the different access to capital market conditions across Member States.
The following tables present the main results:
Levels (bln €2013) for REF2016 EUCO27 CRA EUCO30 EUCO3030
REF2016 and EUCO27 and % change wrt to EUCO27 for
the rest of scenarios GDP (bln GDP (bln €2013) €2013) GDP GDP GDP
E3ME
no crowding out 17,928.1 18,044.9 -0.08% 0.39% 0.53%
partial crowding out 17,928.1 18,044.9 -0.08% 0.39% 0.53%
GEM-E3
loan based 16,954.6 16,961.7 -0.06% 0.26% 0.13%
285
self-financed 16,954.6 16,907.4 -0.08% -0.22% -0.49%
Source: Cambridge Econometrics E3ME modelling and National Technical University of Athens, E3M- Lab, GEM-E3 modelling
In terms of GDP, the CRA scenario leads to lower GDP levels in 2030 than the EUCO27 scenario. This is a direct consequence of the inefficiencies considered in the financing of renewable energy projects in this scenario. This result is confirmed in both models used and for each variant considered.
The EUCO3030 scenario leads to additional RES investments, compared to EUCO30. In the case of the E3ME model, this leads to additional GDP benefits, with very limited
changes between the partial crowding out 62 and no crowding out variants, as investment
levels are not sufficient to breach the output growth constraint imposed in the partial
crowding out case 63 .
In the case of the GEM-E3 model, EUCO3030 results are overall less positive (or more negative) than for the EUCO30 scenario. Additional RES investments tend to shift away investments from other productive sectors in the economy. The increasing share of RES translates into higher average electricity prices and production costs, since additional investments need to be recovered via higher prices and therefore costs for electricity users, hence reducing the initial positive impact resulting from additional RES deployment. Still, overall, GDP effects remain positive in 2030, compared to EUCO27, in the loan-based variant, that is, when increased financial liquidity and the possibility for
borrowing is considered 64 , as crowding out effects tend to rather materialise post-2030. It
can be noted that, under current market conditions, RES investments are financed in majority through borrowing, either from banks or capital markets. When interpreting the scenario results, a key determinant will be the opportunity to finance additional RES – or other energy-related – investments without immediate crowding out on investments in other sectors of the economy.
Levels (mln people) REF2016 EUCO27 CRA EUCO30 EUCO3030
62 The "partial crowding out" imposes a constraint on activity expansion by introducing a rule that
would set a maximum amount that the sectors benefiting from the energy union target setting would be allowed to increase by, without adversely affecting other economic activities. This rule entails a 15% limit on additional energy-related policy induced output growth by 2030. For more information please see the section on macroeconomic impacts of the 2016 Impact Assessment for the revised Energy Efficiency Directive
63 However, as investment requirements increase with more ambitious renewable and/or energy
efficiency levels, this constraint is manifested by limiting the potential output growth in the partial crowding out case versus the no crowding out case. Please see the section on macroeconomic impacts of the 2016 Impact Assessment for the revised Energy Efficiency Directive for more discussion on this
64 In the case of GEM-E3, the two versions are referred to as loan-based finance and self-financing.
In the former, businesses and households can borrow in the markets, whereas in the latter no borrowing is possible and economic agents finance the required additional energy investments via firms increasing their prices and households spending less on other items. The self-financing variant corresponds to immediate financial closure in GEM-E3 and thus implies that the model will show full crowding out effects, meaning that any upward deviation from optimal baseline investments requires consumption to be reduced or investments in other parts of the economy to be cancelled. The loan-based variant mitigates such crowding out effects and defers these to later periods via increasing financial liquidity and allowing for borrowing to take place
286
for REF2016 and
EUCO27 and %
change wrt to Employment Employment
EUCO27 for rest of (mln people) (mln people) Employment Employment Employment
scenarios
E3ME
no crowding out 233.1 233.5 -0.03% 0.17% 0.18%
partial crowding
out 233.1 233.5 -0.03% 0.17% 0.18%
GEM-E3
loan based 216.4 216.6 -0.03% 0.20% 0.14%
self-financed 216.4 216.0 -0.03% -0.18% -0.29%
Source: Cambridge Econometrics E3ME modelling and National Technical University of Athens, E3M- Lab, GEM-E3 modelling
In terms of employment, the CRA scenario leads to negative impacts compared to EUCO27, due to the inefficiencies discussed above, and in line with GDP developments. Employment impacts for the EUCO3030 scenario are very similar to EUCO30 when considering the E3ME results. Using GEM-E3, employment impacts are more negative or less positive (depending on the variant) than for EUCO30, in line with GDP developments projected by the model and the resulting changes in sectorial labour intensities.
Overall, the results of these macroeconomic simulations are rather intuitive: inefficiencies in renewable electricity investments captured in the energy system impacts of the CRA scenario also lead to inefficiencies, and GDP losses, when looking at the macroeconomic implications. Regarding the scenario leading to a 30% RES share in 2030, its overall macroeconomic impacts very much depend on whether the additional RES investments it entails could be financed and implemented without negatively affecting the potential availability of finance for other sectors, or in other words without constraining the monetary liquidity of the overall economy.
6.2. A decomposition analysis of RES developments in the various policy scenarios modelled with PRIMES
6.2.1. Contribution of each RES sector to overall RES increases
The following figure presents the RES share evolution per sector, between 2010 and 2030, per main scenario. First, it can be seen that the most important contribution is expected to be from the electricity sector, followed by heating and cooling. Contributions from transport and from reduced energy demand are at similar lower levels.
The graph also highlights the fact that the CRA scenario projects an additional contribution from the electricity sector in the total renewables increase as compared to
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the other scenarios. It also clearly shows that additional energy efficiency translates into a lower contribution from the heating sector, while overall reduction in demand contributes more, by decreasing the denominator used to calculate the share of renewables.
Figure 1: Decomposition of change of overall RES Share in 2030 relative to 2010,
in percentage points – Main Scenarios
Source: PRIMES
6.2.2. Decomposition analysis for the renewable electricity sector
The figure below focuses on the evolution within the electricity sector across the main scenarios and variants. In all scenarios, the main contributor to the increase in RES-E share is wind. It influences more the overall increase than all other RES technologies put together.
Within this overall context, there are also important variations in the specific split between wind and other RES technologies. For instance, the CRA scenario leads to much more significant investments in wind, particularly wind offshore, than in solar. This is due to a mix of factors, including more favourable financing conditions in regions more favourable to wind than in regions more favourable to solar. The CRA_regio variant shows in this respect a much more balanced evolution in RES technology developments. This is also the scenario closest to the central policy scenario (EUCO27) in terms of RES deployment across technologies. The other three variants to the CRA scenario show much more limited impacts as compared to the baseline (CRA) scenario.
Finally, electricity demand negatively contributes to the evolution of the RES-E share. This is because electricity demand increases in all scenarios, and therefore this requires even more RES investments to increase the renewable electricity share than under constant electricity demand.
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Figure 2: Decomposition of change of RES-E share in 2030 relative to 2010, in percentage points --
various scenarios
Source: PRIMES
6.2.3. Decomposition of RES H&C share
The figure below represents the evolution of the various determinants of RES H&C in 2030, as compared to 2010, across scenarios.
The main determinant of the developments of RES H&C very much depends on the scenario considered. In the case of the Reference and of the EUCO27 scenarios, the main factor is the increase in RES in final heat, followed by heat pumps, RES in CHP and heat demand savings. However, in the case of EUCO30, the main determinant is heat pumps, followed by heat demand savings. This suggests that higher ambition in energy savings lead to, all else being equal, lower needs for additional investments in RES in final heat sector.
Figure 3: Decomposition of change of RES-H&C share in 2030 relative to 2010, in percentage points -- various scenarios Source: PRIMES
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A NNEX 6 - W HO IS AFFECTED AND HOW
Member States could be affected by the procedure to deliver pledges within their national renewables development path, as well as by the provisions for gap-filling instruments in case of difficulties in reaching the at least 27% target.
Local communities and municipalities will also be affected in the effort to coordinate national level and local level renewables planning. This might imply some additional administrative costs for coordination between governmental levels, but also ensure that local authorities are involved from the start so that public resistance issues can be better addressed.
The Revised RES Directive will also impact non-renewables producers and suppliers with regard to their market share as a consequence of the deployment of more renewables across the EU energy market.
Provisions on permit granting and authorisation could contribute to lower administrative and transaction costs associated with renewables project development, therefore impacting renewables projects developers at large and especially SMEs active in the industry.
As per renewables technology producers and renewables installers, the post 2020 renewables and Energy Union Governance policy framework could foster investment security and increase cross border business opportunities.
The investors and the financial sector will factor in an increased investment security in the post-2020 renewables provisions.
Businesses in general could benefit from the renewables cost reductions expected from new requirements for support to renewables and administrative procedures.
Transmissions service operators and distribution service operators could be affected by provisions to ensure that renewable electricity production and injection into the grids is guaranteed without discrimination vis-á-vis non-renewable electricity.
The Revised RES Directive could put in place a regulatory framework to enable consumers to self-produce and self-consume, and sell surplus renewable electricity (which so far only exists in 19 Member States) across the EU. This would enable energy consumers to become active market participants.
Energy service providers (ESCOs) and aggregators could exploit a new avenue both for entrepreneurs and consumers.
Citizens should be impacted in terms of higher local acceptance of renewables projects and increased utilisation of renewable energy in their energy mix, therefore reaping the ultimate benefit of a lower-carbonisation of the economy at large and related lower degrees of pollution.
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A NNEX 7 - O VERVIEW OF BIOFUELS MANDATES IN M EMBER S TATES
Table 1 : Biofuel mandates in the EU 65
EB: Energy Bioethanol Double
basis Vol: Year
Overall Biodiesel
mandate mandate mandate counting Comments
vol. basis
Austria 2012 5.75 % EB 6.3 % 3.4 % EB Y
EB
Belgium 6.0 4.0 %vol. N
%vol.
Bulgaria 2012 2015 6 %vol. N 7 %vol. N
2018 8 N 2019 9 N 2020 10 N
Croatia 2014 3.18 %EB Y 2015 3.88 Y
2016 4.89 Y 2017 5.89 Y 2018 6.92 Y 2019 7.85 Y 2020 8.81 Y
Czech Min. GHG red.
Republic 2014- 5.71 %EB N 35 % 2016 8.0 N 50 %
2017- 10.0 N 60 % 2018 2019- 2020
Denmark 2010 5.75 %EB N 2020 10 proposed
Estonia 5 %EB 2016, 10 % 2020 proposal rejected
2015
Finland 2014 6 % EB N 2015 8 N
EB: Energy Biodiesel Bioethanol Double
basis Vol: Year
Overall
mandate mandate mandate counting Comments
vol. basis
France 2010- 7 % EB 7 % EB 2013 7.7 7 Y
2014 min. 0.35 min. 0.25 % double % double counted counted 8 %
Future?
Germany Min. GHG red. 2015 3.5 % GHG N 35 %
2017 red. N 50 % 2018 4 N 60 % for new plants 2020 4 N 6 No co-processing
Hungary 2014- 4.9 % 4.9 % EB 2015 EB 304 ktoe Y
65 Biofuel Mandates in the EU by Member State. GAIN report GM15015. USDA 7/13/2015
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2020 202 ktoe
Ireland 2010- 4.166 N 2012 6.383 %vol Y
2013
Italy 2014 5 %EB. Y 2015 5 N
“Adv. Biofuels” 2018 mandate
2022 0.6 %EB 1 %
Latvia 2010 5.75 %EB No later info available
Lithuania No information available
The 2011 4.0 %EB Min 3.5 Min 3.5 % Y Mandates in place
Netherlands 2012 4.5 % Min 3.5 % Y since 2007 2013 5.0 Min 3.5 Min 3.5 % Y
2014 5.5 % Min 3.5 % Y 2015 6.25 Min 3.5 No longer Y A certificate system 2016 7.0 % required as Y has been introduced in 2017 7.75 Min 3.5 of 2015 Y 2015. 2018 8.5 % Renewable fuels 2019 9.25 No accepted since 2015 2020 10 longer required as of 2015
Poland 2014- 7.1 %EB N The on double 2016 7.8 Y? counting proposition
2017 8.5 did not pass parliament 2018 as planned in 2015,
expected for 2016 66 .
Portugal 2014 5.5 %EB Y Ethanol includes also 2015- 7.5 2.5 %EB Y ETBE
2016 9 2.5 Y 2017- 10 2.5 Y 2018 2019- 2020
Romania 2014- 5 %EB 4.5 %EB ?
2015 6 4.5 ? 2016
Slovak 2015 5.5 %EB 6.8 %EB 4.5 %EB N ETBE 3 % in gasoline, republic 2016 5.5 7.0 4.6 N 1.41 % bio-ethanol
2017 5.8 7.0 4.7 N 2018 7.2 7.0 5.9 N 2019 7.5 7.0 6.2 N 2020 8.5 7.0 7.0 N
Slovenia 2010 5 %EB Y
EB: Energy Year Overall Biodiesel Bioethanol Double
basis Vol: mandate mandate mandate counting
Comments
vol. basis
66 Poland to postpone double-counting biodiesel ruling to 2017. Platts March 1 2016.
https://www.platts.com/latest-news/agriculture/london/poland-to-postpone-double-countingbiodiesel-26383952
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Spain 2013- 4.1 %EB 4.1 % 3.9 % ?
Sweden 2007- Y Tax based system eligible for approved renewable fuels. Coprocessing accept. Proposal for new system 2017?
UK 2013- 4.75 vol % Y RTFO system in place 2017 in overall > 50 % GHG red.
2018 supply eligible > 60 % GHG red. eligible for new installations New rules on coprocessing expected April 2016?
Table 2: Classification of BIO, CCUS, e & Hydrogen transport fuels
Classification of BIO, CCUS, e & Hydrogen Transport Fuels
Raw material Technology Type of biofuel Status TRL 1 Application
Sugar* Fermentation Ethanol Commercial Gasoline
blend, E10,
E85, E95,
Starch*
l Vegetable oils* Esterification or FAME/Biodiesel Diesel transesterification blend, B7,
ona Fats B10, B30,
enti 100%
nv Food crops Biogas production & Biomethane 100% in Co removal of CO 2 heavy duty
transport, captive fleets, injected in the gas grid
Waste streams of Esterification or FAME/Biodiesel Commercial Diesel oils & fats transesterification blend, B7, B10, B30, 100% MSW 2 , sewage Biogas or landfill Biomethane 100% in sludge, animal production & heavy duty manures, removal of CO 2 transport, agricultural captive residues, energy fleets, crops injected in the gas grid Vegetable oils*, Hydrotreatment Hydrogenated Diesel dropfats, used cooking in or 100%, oils, liquid waste biostreams & kerosene
effluents 7
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Lignocellulosics, Enzymatic hydrolysis Ethanol TRL 8-9 Gasoline
MSW, solid + fermentation blend, E10,
industrial waste E85, E95,
streams/residues 3 upgrade to
Other alcohols TRL 6-7 biokerosene
Gasification + Ethanol TRL 6-7
fermentation
Lignocellulosics, Gasification + Synthetic 4 TRL 6-7 Depends on
MSW, liquid catalytic synthesis fuel type;
industrial waste can be used
streams & for blends
effluents 5 or with diesel,
intermediate gasoline,
energy carriers 6 kerosene,
bunker fuel
d , drop-in ce Algal oils 8 and Hydrotreatment Hydrogenated TRL 5-6 Diesel dropvan
other non-food in or 100%,
Ad oils biokerosene
Esterification FAME/Biodiesel TRL 5-6 Diesel
blend, B7,
B10, B30,
100%
Pyrolysis oils from Hydrotreatment Hydrotreated TRL 4-5 Diesel droplignocellulosics,
in or 100%
MSW, waste
streams
Co-processing in Ethanol, diesel, TRL 5-6 All of the
existing petroleum kerosene above
refineries 9
Non Various as above Ethanol, diesel, TRL 5-6 Various as lignocellulosic hydrogenated above biomass, (algae, non-food
biomass) 10 Sugars 11 Microbial Ethanol, diesel TRL 5-6 Diesel drop(cellulosic,
nonin or 100%, food) biokerosene
Supply of Technology Type of biofuel Status Application
waste/byproduct
gases
Steel & Chemical Fermentation Ethanol TRL 6-7 Gasoline
Industry blend, E10,
S E85, E95,
CCU Upgrading & Methanol TRL 5-6 Shipping, Catalysis blends with
gasoline
Methane TRL 5-6 100% in
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heavy duty transport, captive fleets, injected in the gas grid
Waste polymers, Gasification + Synthetic 4 TRL 6-7 Depends on
plastics, noncatalytic synthesis fuel type; biodegradable can be used fraction of MSW for blends with diesel, gasoline, kerosene, drop-in
CO 2 from RES Reaction with RES H 2 Synthetic 4 TRL 6-7 Depends on
systems fuel type;
can be used
for blends
with diesel,
gasoline,
kerosene,
drop-in
Supply of H2 Technology Type of biofuel Status Application
RES electricity Catalysis Methanol TRL 6-7 Shipping,
blends with
gasoline
RES electricity Methane TRL 7-8 100% in
heavy duty
transport,
captive
els fleets, injected in
e Fu the gas grid
RES electricity Synthetic 2 TRL 5-6 Depends on
fuel type; can be used for blends with diesel, gasoline, kerosene, drop-in
Source Technology Type of Status Application
2 Biofuel
S H RES electricity Electrolysis H 2 TRL 5-8 Fuel cells, H2 engines,
RE Ethanol or Reforming (on H2 natural gas grid 12 Methanol vehicle)
Methane 12 Reforming H2
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A NNEX 8 - M ODELLING METHODOLOGY FOR THE GHG EMISSION REDUCTION OPTIONS
ICCT assessment tool for option 4
The model used to estimate potential alternative fuel volumes, greenhouse gas impacts, costs and jobs for the various scenarios presented in this memo was developed by Dr. Stephanie Searle and Dr. Chris Malins at the International Council on Clean Transportation. The model is private and has not undergone peer review or been discussed with external experts. The model was developed specifically for understanding the impacts of various potential alternative fuel policies in the EU in the year 2030.
The model structure is linear. The amount of alternative fuel supplied in each scenario is multiplied by its carbon intensity value and then compared to the carbon intensity of diesel or petrol in order to calculate greenhouse gas savings. Alternative fuel amounts are multiplied by projected fuel prices for each type and compared to the projected price of diesel or petrol to calculate total cost of each fuel type in each scenario. The number of permanent jobs that would be directly supported by the production of each type of fuel was estimated on a per ton oil equivalent basis, and this was multiplied by alternative fuel volumes to calculate total jobs that would be supported by each fuel type in each scenario. Maximum volumes of advanced fuel technologies that have not yet been widely commercialized (cellulosic ethanol and synthetic diesel from pyrolysis or Fischer Tropsch processes) were calculated by estimating the number of facilities that could plausibly be constructed in each year from the present to 2030 with strong policy support. The estimated maximum volume of these advanced fuel technologies was not directly input into any of the scenarios presented in this memo, but was used as a comparison point to contextualize whether particular scenarios were likely achievable or not. The volumes of each type of alternative fuel in each scenario were largely determined by (a) the GHG reduction target in each scenario, and (b) the amounts of biodiesel and ethanol that could be consumed with current blend limits in diesel and petrol. REF2016 used in this modelling exercise was provided by the European Commission; volumes of specific fuel types was inferred from the given material using the information available.
Because the model projects future conditions, there is inherent and unavoidable uncertainty in the results. The maximum potential volumes of each type of fuel in 2030 will depend heavily on a number of factors, including but not limited to: the perceived strength of policy support, technology development, diesel and petrol prices, financial markets, and local policies and regulations throughout the EU. This model relies on inputs from several other sources that each carry uncertainty – for example, the fuel price projections taken from the UK Transport Energy Task Force report have uncertainty associated with them, and actual fuel prices in 2030 will depend on a variety of factors, including technology development and petroleum prices. There is uncertainty in the estimates of indirect land use change emissions used in this model, and to a lesser extent, in our assumptions on direct production emissions for alternative fuels in 2030. The number of permanent agricultural jobs that would be directly supported by the production of each type of alternative fuel was estimated in a simple approach by looking at the EU agricultural sector as a whole, and this estimation could be refined. The estimates of jobs both in feedstock production and in facility operation were made considering current conditions, but the number of jobs in alternative fuel production could change to 2030 depending on technology development. Uncertainty in this model has been minimized by focusing on the factors that most strongly influence the policy conclusions. For example, assumptions about ILUC emissions greatly affect the results about the net GHG impacts
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of each scenario; we therefore present results using two sets of ILUC emission estimates that were produced for the European Commission (the IFPRI study and the GLOBIOM study). The quality of the results from this model were otherwise assured by relying on published studies for the assumptions when such information was available.
Modelling assumptions for GHG mandate
GHG savings: It is assumed that the 60% GHG reduction requirement for direct lifecycle emissions under the RED sustainability criteria will continue to apply, and that some operators will achieve higher GHG savings. Food-based biodiesel is assumed to have an average direct GHG savings of 65% and food-based ethanol of 70%. All nonfood based fuels are assumed to have higher GHG savings. For all scenarios, it is assumed that ILUC accounting will not apply towards eligibility or reportable GHG savings. In estimating real GHG savings including ILUC, ILUC results from the 2011 IFPRI study are used (Laborde, 2011). The composition of food-based biodiesel and ethanol by crop was taken from the 2020 EU crop mix in Valin et al. (2015).
Potential volumes: A 7% blendwall is assumed to apply for biodiesel blended in diesel and a 10% blendwall for ethanol blended petrol. 20% of the gasoline pool was assumed to be E85 (51-83% ethanol blended in gasoline, at an average blending rate of 75%) for scenarios B1, B2, and B3, and 5% of the gasoline pool was assumed to be E85 for all other scenarios under Options B, C, and D. While E85 availability may increase in the EU, the experience from the US, where corn ethanol consumption is strongly supported by the Renewable Fuel Standard, shows that biofuel mandates are an inadequate driver for increased use of higher biofuel blends, as the high cost of infrastructure changes presents a significant barrier (e.g. see EPA, 2016). The blendwall does not apply to drop in fuels, such as hydrogenated vegetable oil (HVO) or pyrolysis synthetic diesel. For the purpose of estimating volumes under the blendwall, diesel and gasoline projections are taken from REF2016 provided by the European Commission. Volumes of second generation fuels, such as cellulosic ethanol or cellulosic synthetic diesel, are estimated based on a deployment model, and are assumed to have preferential access under the blendwall when it applies. The use of electricity in vehicles follows Lutsey (2015). A category for “Other Annex IX fuels” is intended to include alternative fuels from glycerine and other sources for which individual projections are not possible at this time. A category for “Other advanced fuels” is intended to include non-biological fuels from waste, and other, unforeseen, types of low carbon, alternative fuels. The blendwall is not assumed to apply to “Other Annex IX fuels” and “Other advanced fuels.”
Cost: Cost estimates from the UK’s Transport Energy Task Force report are used for the cost of different types of fuel, including diesel, petrol, waste and crop-based biodiesel,
and crop-based and cellulosic ethanol in the year 2030. 67 The cost of pyrolysis and
Fischer Tropsch synthetic diesel and other advanced fuels are assumed to be the same as for cellulosic ethanol in 2030. Other Annex IX fuels are assumed to be slightly less expensive to produce. HVO is assumed to be slightly more expensive than crop-based biodiesel. The cost to obligated parties of electricity used in vehicles is assumed to be related to charger installation costs, which were estimated for level 2 home chargers in the year 2030 from EPA (2012). Only a portion of this cost is included in this analysis because other policies such as efficiency standards and purchase and tax incentives for
67 "Data and outputs spreadsheet": http://www.lowcvp.org.uk/projects/transport-energy-taskforce.htm
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electric vehicles contribute to electric vehicle deployment and thus petroleum displacement by electric vehicles; this cost therefore cannot be attributed solely to a low carbon fuel policy.
Employment: Only direct, permanent jobs were estimated; construction jobs and indirect employment impacts were not assessed here. For second generation ethanol, pyrolysis diesel, and Fischer Tropsch diesel, feedstock collection jobs were derived from Turley et al. (2013), using values for straw collection. For other advanced fuels and other Annex IX fuels, it was assumed that a portion of fuel would be waste-based with fewer feedstock collection jobs. For food-based crops, feedstock production jobs were estimated as the average number of agricultural jobs per harvested hectare in the EU in
2010, using employment data from Eurostat 68 and crop production data from FAOSTAT. 69 The fraction of additional crop demand from food-based biofuel that would
be met with increased agricultural production in the EU was taken from the recent GLOBIOM study (Valin et al., 2015). It is assumed that second generation fuel production (e.g. cellulosic ethanol from wheat straw) would result in 100% new feedstock collection in the EU. Biofuel facility jobs for second generation fuels was taken from a review in Pavlenko et al., (2016). Facility jobs for first generation biofuels was assumed to be half of this, per unit fuel on an energy equivalent basis, because second generation biofuel facilities tend to be more complicated than first generation facilities. The number of jobs created by electricity used in vehicles was estimated as labour required to install electric chargers (assuming 8 hours per charger, following costs from EPA (2012)); a portion of the employment created in charger installation was considered attributable to the low carbon fuel policy. Waste collection jobs were not included.
68 http://ec.europa.eu/eurostat/statistics-explained/index.php/Agricultural_census_2010_-
_main_results#Agricultural_labour_force. It was assumed that half of total agricultural jobs are in crop production, as opposed to livestock or other types of jobs.
69 http://faostat.fao.org/
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A NNEX 9 - REFIT EVALUATION
The REFIT evaluation concluded that the objective of sustainably increasing the share of renewable energy in the EU final energy consumption has been successful. The binding national targets, the National Renewable Energy Action Plans and the biennial
monitoring 70 provided for by the RES Directive have been particularly effective for
promoting transparency for investors and other economic operators, and have ensured high quality information on renewable energy markets and policies in the Member States. This is illustrated by the rapid deployment increase after the date of adoption of the
Directive, passing from 10.4% share of renewables in 2007 to 17% in 2015 71 .
These legal provisions, together with additional national policies and other nonregulatory measures, have contributed to the overall achievement of EU’s energy and climate policy goals, resulting in greenhouse gas emission saving, increased security of energy supply, innovation leadership, employment creation, public acceptance and regional development. They have proved their relevance, coherence, efficiency, effectiveness and added value for the overall EU energy and climate change objectives. Renewable energy is, currently, the only decarbonisation option in the power sector deployed at a rate that is close to what is required under long-term IEA scenarios to limit
global temperature rise to 2 ◦ C above pre-industrial levels 72 .
However, even if the EU and all but one Member States are currently on track towards its overall renewable energy 20% target for 2020, target achievement by 2020 will only be secured if Member States continue to meet their increasingly steep trajectories. Furthermore, further efforts are necessary to increase the current progress rate of renewables deployment in transport to ensure the sectorial 10% target is met. T he regulatory uncertainty caused by the long political discussion on ILUC, the late adoption of the amendments on ILUC to the RES Directive and the lack of a post-2020 policy for transport, together with the lack of commercial availability of alternative fuels and advanced biofuels at the needed scale and pace, have had a negative impact in the deployment of renewables in the transport sector.
In addition, the effectiveness of the national targets, based on a flat-rate/GDP approach (as opposed to an approach based on national potential, which would have been more
cost effective, but considered less equitable 73 ) was, however, compromised by the fact
that flexibility and trading options were not utilised by the Member States as expected during the reference period. However, intergovernmental negotiations that were held in 2015 and 2016 amongst several potential "selling" and "buying" Member States, demonstrate increasing mobilisation of efforts towards concluding the first renewable energy cooperation agreements.
Another issue which requires follow-up is the level of investments in renewable energy. Their decline after 2011 due to undermined inverstor confidence and some external factors highlights the need to reflect on how investors' legitimate interests can be better
70 National Renewable Energy Action plans and biennial national renewable energy progress reports
are legal requirements set out in Art. 4 and Art.22 of the Renewable Energy Directive
71 EUROSTAT
72 IEA, 2015
73 "Package of Implementation measures for the EU's objectives on climate change and renewable
energy for 2020", 2008, SEC(2008) 85
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protected.The REFIT evaluation of the RES Directive also pointed to a number of shortcomings in the Renewable Energy Directive:
• National renewable energy action plans: While the national renewable energy action plans provided transparency and information for investors on Member States' plans for renewable energy development, they eventually became outdated as the RES Directive does not require their regular updating to adjust them to policy and global economic changes. This shortcoming was largely compensated by biennial national RES progress reports that provided regular updates on national regulatory and financial measures in the renewable energy space. In the context of the new 2030 Climate and Energy Framework and Energy Union Governance process, the current legal provisions on the planning and reporting will need to be revised for post 2020 period.
• Cooperation mechanisms: The cooperation mechanisms set out in the RES Directive have not yet been used to any significant extent by Member States, with exception of the joint Swedish-Norwegian support scheme. In the RES Directive, the use of cooperation mechanisms is voluntary and Member States have so far, for various reasons, preferred to use national renewable energy sources for target achievement. The opportunity given by the RES Directive to share the efforts to achieve the renewable energy target cost-effectively has, therefore, been rather underused. However, as national interim trajectories become steeper after 2015, a number of Member States are currently in active phase of negotiations aiming to conclude such cooperation mechanisms, in the form of a partial opening of national support schemes, or statistical transfers. .
• Renewable energy support schemes: Pursuant to Article 3(3) of Directive 2009/28/EC i, support schemes are but one instrument - amongst others - that can be chosen by Member States to achieve the binding national renewable targets. The majority of the Member States though used them as part of their renewable policies. In the absence of clear principles established in the RES Directive, Member States had wide discretion in their decisions on the design and scope of renewable energy support schemes. As the cost of renewable energy technologies fell, several national support schemes were unable to be adapted rapidly enough. As a result, technology bubbles were encouraged, resulting in market distortion and fragmentation.
• Administrative procedures: Administrative and planning systems are very diverse across the EU Member States and progress in simplifying them has been hampered due to the large margin of discretion left in the legal provisions of Article 13(1). Clear and transparent rules are not yet in place in all Member States and at all necessary levels. The absence of clear legal requirements to establish one administrative entity (one-stop shop) for the permit granting procedures and the absence of maximum time-limits for permit granting in Member States are still perceived as major administrative obstacles and an additional cost burden to project developers. In view of tackling investment bottlenecks and lengthy project approval procedures, further reinforcement of these provisions might need to be
considered for the amended post 2020 legislation 74 .
74 Building on the previous rather general requirement set out in Directive 2001/77/EC i for Member
States to take action to reduce and simplify administrative procedures, the impact assessment
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• Renewable energy in heating and cooling supply and in buildings: The RES Directive recommended Member States to promote and integrate renewable energy in the urban and local environment (e.g. newly developed areas, district heating and cooling systems), and to mandate renewable energy use through buildings codes for new buildings as of 2015, while leaving full discretion to the Member States as regards implementation modes. Despite the long term decarbonisation goal in the heating and cooling sector and in buildings, the existing framework did not provide sufficient incentives for fuel switching from fossil to renewable energy in the heat supply and buildings. Further reinforcement of these provisions might need to be considered in the revision of the Directive for post-2020.
• Grid access rules: Certain provisions of the RES Directive are not specific enough (e.g. providing deadlines for their implementation) for the purpose of enabling better monitoring and enforcement. The Directive also leaves discretion to Member States on whether shallow or deep grid charging is applied, which considerably changes the risk and thus the cost for new renewable installations across Member States. In view of the intended wider electricity market reform, some of the current legal provisions on RES electricity integration might need further streamlining and integration with the electricity market legislation.
• Self-consumption: The RES Directive does not contain specific provisions on self-consumption of renewable electricity, which has given Member States a wide discretion to regulate this type of emerging trend of consumers' empowerment. This has led to a wide range of policies across the EU, some of them hampering the cost-effective development of self-consumption. The benefits of introducing a EU framework enabling cost-effectives self-consumption (in line with the Energy Union's objective of empowering consumers) could be assessed in the revision of the legislative framework for post-2020.
• Guarantees of origin (GO): The regulatory framework in the RES Directive has not provided sufficient clarity and suitable provisions for the creation of a comprehensive, liquid and harmonised GO system for all energy sources throughout the EU. It enables the provision of "green" supply contracts which are dissociated from the physical delivery of renewable electricity. The revision of this provision in the context of the legislative work for the post-2020 energy framework could look at improving the consistency in the application of the system by Member States as well as extending their use.
• Bioenergy sustainability: Indirect land use effects were not included from the very beginning in the EU mandatory sustainability criteria for biofuels and bioliquids. The related policy debate and regulatory amendments have created investors uncertainty and, in turn, a serious slowdown in investments, including in advanced biofuels. Different national implementation modes of the EU sustainability criteria, including a lack of mutual recognition of national
accompanying the proposal for the RES Directive considered a reinforced "national action" approach without specific EU guidance as the most appropriate way forward. However, the REFIT evaluation concluded that even the reinforced provisions of Article 13(1) of the RES Directive have not substantially improved the situation and the public consultation for the present Impact Assessment demonstrated clear support for a more stringent approach and harmonised EU minimum rules in the post-2020 period.
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certification schemes, have led to some market fragmentation. The lack of EU sustainability framework for biomass and biogas used in heating/cooling and electricity has also resulted in a growing debate, which in turn has prompt the introduction of national scheme, with possible market distortion.
In a post-2020 scenario consideration should be given to the opportunity of extending the sustainability criteria to account, not only for biofuels and bioliquids as it is already the case, but also for solid and gaseous biomass, in a cost-efficient way. Furthermore, the future framework should give consideration to effective and pragmatic ways to enhance renewables deployment, notably advanced biofuels, in the transport sector. This should build on the experience gained by many Member States with the implementation of national incorporation mandates for biofuels/renewable energy. Improved information and tracking systems are also needed to prevent fraud and abuse.
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| 2 dec '16 |
Voorstel voor een RICHTLIJN VAN HET EUROPEES PARLEMENT EN DE RAAD ter bevordering van het gebruik van energie uit hernieuwbare bronnen (herschikking) PROPOSAL |
Secretary-General of the European Commission 15120/16 |