Electricity Production

Producing electricity from renewable energy sources and green hydrogen will cost 15 percent less up

to 2045 than relying on lignite or gas. A full decarbonisation of the region’s power system will require

a total investment of 43 billion euros over 30 years, 12 billion euros more than the fossil baseline. Even if investments are higher, renewables deployment can largely be financed from market revenues.

A reliable yet carbon-free power system can be achieved with a combination of renewables, storage (hydro, batteries, thermal storage) and 5 GW of green hydrogen fuelled power plants. Deeper regional integration can further reinforce security of supply.

The need for more ambitious climate action together with high and volatile fossil gas prices and ever cheaper renewables undermine the business case for new fossil gas infrastructure: any new fossil gas plant risks becoming a “stranded asset”. If the Western Balkan countries invest in hydrogen-ready infrastructure and storage technologies instead, they can reduce cumulative fossil gas demand by 50 percent up to 2045 while cutting overall costs by 12 percent compared to a strategy that bets on fossil gas to replace aging lignite.

Greater energy storage capacity enables rapid growth in PV, the most easily scalable renewables

technology. Storage also lowers the need for hydrogen power plants that will replace gas plants. It

is important not to overestimate hydrogen needs when planning for corresponding infrastructure. 5 GW of green hydrogen plants, covering 7 percent of demand in 2045, are needed for power system security of supply.

The CBAM is a necessary tool for the EU to prevent carbon leakage; it is not an instrument to force trading partners to adopt similar policies.

Export markets for goods with high carbon intensity will shrink, impacting the region far beyond the power sector. The CBAM will to some extent also reduce opportunities to export carbon free flexible power generation. There is a tight timeline concerning the numerous re-forms that must take place before 2030.

Such projects will be loss-making in context of the CBAM. Establishing domestic carbon pricing will assist countries in gathering revenues that should be used to fund the transition to clean power systems.

Specific support is needed for establishing the data and technical backbone of carbon pricing systems. In addition, the West-ern Balkan countries should use a larger share of available EU funds for supporting a just transition and socio-economic convergence with the EU.

A 2030 coal phase-out provides a CO₂ emission reduction potential of 1 billion tons beyond the 40 percent emissions reduction scenario at little additional cost to consumers (wholesale prices rise by 0.5 cent/kWh).

The required emission reduction of the power sector can only be achieved if coal is overwhelmingly replaced by solar PV and wind energy. A phase-out of the remaining 38 GW coal capacities in the six countries that do not have a 2030 phase-out date yet (Bulgaria, the Czech Republic, Germany, Poland, Romania and Slovenia) must be met with 100 GW of PV and wind.

The coal phase-out may require additional deployment of 15 GW of gas plant capacity to safeguard security of supply – while gas-fired power generation needs to fall 15 percent by 2030 in the EU. To avoid stranded assets, all new fossil gas investments should be hydrogen ready.

The EU ETS should be tightened as proposed by the European Commission. Several Member States should quickly develop or accelerate their plans for national coal phase-out, potentially complemented by a national carbon floor price. Member States should rapidly scale renewables.

2  GW of new lignite capacity is currently planned in the region. If built, these plants will generate a cumulative loss by 2040. This is because of low efficiency of lignite mining, costs to comply with air pollution regulation and limited export opportunities after establishment of the EU  Carbon Border Adjustment Mechanism (CBAM). A phase-in of carbon pricing in Energy Community countries would further increase losses.

A 2040 lignite exit increases system costs by 3–4 €/MWh in an unlikely scenario without carbon pricing. With the EU CBAM regime or any other form of domestic carbon pricing, closing lignite plants by 2040 lowers system costs.

Security of supply is not an issue if the gradual phase-out of lignite is accompanied by a rapid scaling of renewables, enhanced interconnections, regional power market integration, strengthening of existing hydro-storage and targeted investments in flexible gas plants. Expanding renewables also reduces import dependency of the power and energy sectors.

Replacing lignite generation by renewables lowers wholesale prices, hedges against carbon prices and avoids that fossil gas infrastructure will become stranded. Renewables deployment can largely be financed from market revenues, especially in case of carbon pricing. Renewables also come with many co-benefits such as improved air quality and new job opportunities. ‘Just transition’ policies would ensure that no one is left behind.

. In 2025, the LCOE of utility-scale PV should reach about 6.3 ¥/kWh (5.2 €cts/kWh). Onshore wind could reach those levels in 2030. Those costs will be significantly lower than those of new fossil-fuelled power plants, comparable to lifetime extensions of nuclear and far below new nuclear and CCS projects.

Japan can reach a share of at least 45% renewables in 2030 (corresponding to a share of 35% wind and solar power) with integration costs below 1.5 ¥/kWh. Integrating 66% renewables (corresponding to 50% wind and solar power) would come only at a slightly higher cost of 2 ¥/kWh.

These costs are estimated at below 1 ¥/kWh for Japan. Various measures exist to minimize those costs, in particular through optimal grid planning, optimised grid operation, and well-functioning and non-discriminatory intraday and balancing markets.

The calculation of those costs can vary tremendously depending on the assumptions. A total system cost approach would circumvent some of the uncertainties, in particular the controver-sial attribution of system effects to specific technologies. Rather than to speak about integra-tion costs, we should speak about interaction costs. If the system adapts to renewables (reduc-ing baseload power plants), the cost of variability for integrating 50% PV and wind energy in Japan is estimated at about 1.25 ¥/kWh. If not, the costs of variability could be much higher. This finding calls for a refinement of energy markets design, so as to incentivize rather than to hamper flexibility.

The net-zero decarbonization scenarios contained in the European Commission’s Long-Term Strategy assume some 400 to 450 GW of offshore wind capacity by 2050. Additional demand of up to 500 GW may be created by dedicating offshore farms to electrolysis for renewable hydrogen production.

Given the 8 GW of installed capacity today and current plans for 20 GW by 2030, the pace of spatial planning for offshore wind deployment needs to pick up significantly. The slowing of onshore wind development could further enhance the importance of offshore wind in achieving net zero.

The more turbines are installed in a region, the less efficient offshore wind production becomes due to a lack of wind recovery. If Germany were to install 50 to 70 GW solely in the German Bight, the number of full-load hours achieved by offshore wind farms would decrease considerably.

In order to maximize the efficiency and potential of offshore wind, the planning and development of wind farms – as well as broader maritime spatial planning – should be intelligently coordinated across national borders. This finding is relevant to both the North and Baltic Seas. In addition, floating offshore wind farms could enable the creative integration of deep waters into wind farm planning.

Hard coal generation dropped by 32%, while lignite decreased by 16%. This development is driven by CO₂ price increases and deployment of renewables. Gas replaced around half of the coal, solar and wind the other half. The decline of coal will continue: Greece and Hungary both made commitments in 2019 to phase out coal, bringing the total of member states phasing out coal to 15. Only Poland, Romania, Bulgaria and Slovenia are yet to start.

This is likely to be the largest ever fall. EU Emissions Trading Scheme (EU ETS) stationary emissions, including heavy industry, fell by 7.6% in 2019, implying that industrial emissions are likely to have decreased by only 1%. Nevertheless, overall emissions covered by the EU ETS are falling much faster than the cap; showing the central role of a further strengthening of the EU ETS to accelerate climate action in Europe.

For the first time, wind and solar combined provided more electricity than coal, contributing 18% of EU electricity in 2019. This is more than a doubling of market share since 2013. The increase in wind and solar generation was strongest in western Europe, while Poland and Greece have started to engage. The rest of eastern Europe is significantly lagging behind. The economic opportunities of low-cost renewables became increasingly visible. 2019 saw record low auction prices for offshore wind (UK) and solar (Portugal) - below wholesale prices – and the largest wholesale price decreases in countries where wind and solar expanded most.

The European Green Deal has put the fight against the climate crisis at the very core of all EU policy work over the next five years: EU heads of state have endorsed Europe to become the first greenhouse gas neutral continent by 2050, and the EU commission is putting forward proposals to raise Europe’s 2030 greenhouse gas reduction target to -50% or -55% below 1990 levels. This implies power sector emissions will keep falling, even if electricity demand increases as transport, heating industry continue to electrify.

Meanwhile, CO2 emissions from the buildings and transport sectors have risen due to an increase in oil and gas consumption. The decline in CO2 emissions can be attributed to the higher CO2 prices in the EU ETS, a significant increase in renewable generation and lower electricity consumption. The rising share of SUVs in the transport sector is responsible for rising emissions.

Whilst annual growth in renewables has been consistently in the 15 terawatt hours in recent years, the lack of available space and permits for wind capacity puts its continuation in jeopardy. Decisive political action is now required if the 2030 renewable energy targets are to be achieved.

Older, more expensive power plants will then increasingly fall out of the support scheme. In addition, from 2021, part of the revenue from the Fuel Emission Trading Act (BEHG) will be used to reduce the EEG levy. As a result, the price of electricity is likely to fall slightly in the 2020s rather than rise.

Indeed, the climate package adopted by the German government in September is not sufficient to achieve the 2030 climate protection targets. There is a considerable need for improvement, particularly in the areas of transport, buildings and industry.

The reason: countries in South East Europe face higher financing costs due to perceived higher investor risks. More costly than necessary renewables investments seriously hamper power system modernisation in SEE.

“De-risking measures” available to governments will reduce renewable energy project costs to levels comparable or lower than those of fossil fuel investments. Low cost renewable energy projects are thus a real alternative for replacing old and polluting lignite power plants.

De-risking measures with the highest impact include: (1) the proposed EU budget guarantee mechanism; (2) reliable, long-term renewables remuneration regimes and long-term renewables targets; (3) well-functioning, regionally integrated balancing and intraday markets; and (4) corporate power purchase agreements.

The budget guarantee alone accounts for 40 per cent of the decline in financing costs attributable to the de-risking measures analysed in this study. Overall, de-risking measures enable the expansion of renewables in South East Europe at lower costs than coal, natural gas or nuclear, with attendant benefits for the climate and for human health.

For decades, Germany's economy was reliant on energy from lignite and hard coal; in the future, renewables will serve as a basis for economic prosperity.

In the absence of implementation, CO₂ emissions from coal-fired power plants will only decline at a slow rate. However, the Coal Compromise is not sufficient for Germany to meet its 2030 carbon emissions target. Considerable additional measures are required, especially in the industrial, building, and transport sectors.

The compromise guarantees that no worker will be left high and dry and that coal mining regions will have sufficient time and resources to adapt economically. To this end, the compromise foresees 2 billion euros in federal spending per year - which in parts can also be understood as compensation for structural policy failures since German reunification especially in Eastern Germany.

Periodic reviews in 2023, 2026, 2029, and 2032 will offer policymakers an opportunity to react to a worsening climate crisis with additional measures. Furthermore, the Commission’s compromise creates a foundation for a socially equitable acceleration of the phase-out.

By 2030, renewables will account for 55% of power generation in Europe, and 50% of power generation in SEE. Nearly 70% of renewable power in SEE will stem from wind and solar, given the excellent resource potential of these renewables in the region.

For example, wind generation can fluctuate from one hour to the next by up to 47% in Romania, whereas the comparable figure for Europe is just 6%. Moving from national to regional balancing substantially lowers national flexibility needs. Increased cross-border interconnections and regional cooperation are thus essential for integrating higher levels of wind and PV generation.

Accordingly, conventional power plants will need to flexibly mirror renewables generation: When renewables output is high, conventionals produce less, and when renewables output is low, fossil power plants increase production. Flexible operations will become an important aspect of power plant business models.

The available reserve capacity margin in SEE will remain above 35% in 2030. More interconnectors, market integration and regional cooperation will be key factors for maximising national security of supply and minimising power system costs. SEE can be an important player in European power markets by providing flexibility services to CEE in years of high hydro availability.

Half of this was structural, from new wind, solar and biomass displacing hard coal. The other half was weather-related, as increased hydro generation reversed the temporary rise in gas in 2017. Overall EU ETS emissions, we estimate, fell by 3%, from 1754 Mt in 2017 to 1700 Mt in 2018.

Hard coal generation fell by 9% in 2018, and is now 40% lower than in 2012. In 2018, Germany and Spain announced that coal phase-out plans were imminent. That would now put three quarters of Europe’s 2018 hard coal generation under national coal phase-outs. The remaining quarter is almost all in Poland.

Lignite generation fell by only 3% in 2018. Half of Europe’s lignite generation in 2018 was in Germany; the Coal Commission announcement for a 2038 phase-out includes lignite. The other half is in countries where this is not yet the case: Poland, Czech Republic, Bulgaria, Greece, Romania and Slovenia.

Renewables rose to 32.3% of EU electricity production in 2018. While this year’s rise was mainly due to wind growth picking up and hydro returning back to normal, solar will be the next big thing: solar additions increased by more than 60% to almost 10 GW in 2018 and could triple to 30 GW by 2022. Module prices fell by 29% in 2018. Solar outperformed during the 2018 summer heatwave, when coal, nuclear, wind and hydro all stumbled. Bold national plans for solar in 2030 were drafted in Italy, France and Spain in 2018. The EU’s 2030 RES target, agreed in 2018, will result in even more.

Coal and gas generation costs rose in 2018: coal price rose 15%, gas rose 30%, and the CO₂ price rose 170%. Consequently, electricity prices rose to 45–60 €/MWh in Europe. This is the level at which the latest wind and solar auctions cleared in Germany.

Since Europe‘s hydro potential is largely tapped, the increase in renewables comes from wind, solar and biomass generation. They rose by 12% in 2017 to 679 Terawatt hours, putting wind, solar and biomass above coal generation for the first time. This is incredible progress, considering just five years ago, coal generation was more than twice that of wind, solar and biomass.

Germany and the UK alone contributed to 56% of the growth in renewables in the past three years. There is also a bias in favor of wind: a massive 19% increase in wind generation took place in 2017, due to good wind conditions and huge investment into wind plants. This is good news since the biomass boom is now over, but bad news in that solar was responsible for just 14% of the renewables growth in 2014 to 2017.

With Europe‘s economy being on a growth path again, power demand is rising as well. This suggests Europe‘s efficiency efforts are not sufficient and hence the EU‘s efficiency policy needs further strengthening.

Low hydro and nuclear generation coupled with increasing demand led to increasing fossil generation. So despite the large rise in wind generation, we estimate power sector CO2 emissions remained unchanged at 1019 million tonnes. However, overall stationary emissions in the EU emissions trading sectors rose slightly from 1750 to 1755 million tonnes because of stronger industrial production especially in rising steel production. Together with additional increases in non-ETS gas and oil demand, we estimate overall EU greenhouse gas emissions rose by around 1% in 2017.

Three more Member States announced coal phase-outs in 2017 - Netherlands, Italy and Portugal. They join France and the UK in committing to phase-out coal, while Eastern European countries are sticking to coal. The debate in Germany, Europe’s largest coal and lignite consumer, is ongoing and will only be decided in 2019.

At 65 per cent, coal provides the largest share of total generated electricity. Renewables account for 25 per cent. Consumption increased by 283 TWh, comparable to the entire consumption of Spain.

Since 2010, the share of renewables in the power mix has increased by 8 percentage points, while coal has decreased by 11 percentage points.

Some provinces, like Gansu and Xinjiang, plan to slow down wind capacity expansion in the coming years. Furthermore, the government is encouraging expansion of the transmission grid.

Full load hours for coal plants decreased from more than 5,000 hours in 2013 to 4,165 hours in 2016, and energy-related emissions have stagnated at 2013 levels. However, the government is reviewing its plans for new coal plants, and another 200 GW of coal-fired power plants are under construction and are expected to go online by 2020.

Coal-fired power plants are in most cases less flexible compared to gas-fired generation units. But as Germany and Denmark demonstrate, aging hard coal fired power plants (and even some lignite-fired power plants) are already today providing large operational flexibility. They are adjusting their output on a 15-minute basis (intraday market) and even on a 5-minute basis (balancing market) to variation in renewable generation and demand.

Targeted retrofit measures have been implemented in practice on existing power plants, leading to higher ramp rates, lower minimum loads and shorter start-up times. Operating a plant flexibly increases operation and maintenance costs — however, these increases are small compared to the fuel savings associated with higher shares of renewable generation in the system.

In some power systems, especially when gas is competing against coal, the flexible operation of coal power plants can lead to increased CO2 emissions. In those systems, an effective climate policy (e.g. carbon pricing) remains a key precondition for achieving a net reduction in CO2 emissions.

Proper price signals give incentives for the flexible operation of thermal power plants. Thus, the introduction of short-term electricity markets and the adjustment of balancing power arrangements are important measures for remunerating flexibility.

 in Morocco, Peru and Mexico, average winning bids ranged between 2.7 and 3.4 EUR ct/kWh in 2015/2016. This fundamental cost reduction trend is projected to continue.

The size of windmills is expected to be the major driver of future cost reductions, as costs for increasing turbine size grow at lower rates than the benefits. The limits to onshore turbine growth are most likely not of a technological nature but rather a question of local political consent.

The levelized cost of electricity at those sites ranges between 3 and 4.5 ct/kWh for turbines of the latest generation. Major potentials to further improve cost efficiency are reducing land and maintenance costs, which are far higher than the international average.

European coal generation fell by 94 TWh and gas generation increased by 101 TWh, resulting in 48 Mt less CO2 emitted. Half of this happened in the UK, but also Italy, Netherlands, Germany and Greece saw switching from coal to gas. However, gas generation was far from reaching a record – it is still 168 TWh below the 2010 level, showing that more coal-gas switching is possible without new infrastructure.

Solar and wind conditions were generally below average in 2016, compared to well above average in 2015. However, with new capacity installed, overall generation still saw small increases. As to prices, 2016 saw record low renewables auction results with only 49,9 Euros/MWh for wind offshore and 53,8 Euros/MWh for solar, both in Denmark.

Only two countries saw falls in electricity consumption in 2016, most had modest increases. Investment going into energy efficiency is apparently sufficient to prevent electricity consumption from rising but not enough for electricity consumption to begin structurally falling.

The reason is that ETS emissions are structurally below the cap – mocking the concept of a “cap-and-trade” system. To play a meaningful role in EU climate policy, the EU ETS needs to be fundamentally repaired.

2016 gave a glimpse of the rapid falls in emissions that are possible with decreased coal production. But a coherent European policy approach to continually increasing renewables and to a just transition in the context of a coal phase-out is needed to ensure that the CO2 reductions of 2016 are continued into the future.

The existing climate targets for 2030 imply a renewables share of some 50 percent in the electricity mix, with wind and PV contributing some 30 percent. The reason is simple: they are by far the cheapest zero-carbon power technologies. Thus, continuous investments in these technologies are required for a cost-efficient transition; so are continuous efforts to make the power system more flexible at the supply and demand side.

A more flexible energy-only market and a stable carbon price will however not be enough to manage the required transition to a power system with high shares of wind and solar PV. Additional instruments are needed.

Together, they form the Power Market Pentagon; all of them are required for a functioning market design. Their interplay ensures that despite legacy investments in high-carbon an inflexible technologies, fundamental uncertainties about market dynamics, and CO2 prices well below the social cost of carbon, the transition to a reliable, decarbonised power system occurs cost-efficiently.

For example, introducing capacity remunerations without actively retiring high-carbon, inflexible power plants will restrain meeting CO2 reduction targets. Or, reforming the ETS could trigger a fuel switch from coal to gas, but cannot replace the need for revenue stabilisation for renewables.

Nuclear power comes in second with 27 percent, coal (hard coal and lignite) amount to 26 percent. Among RES, wind power increased significantly by more than 50 terawatt hours to 307 terawatt hours in total. Hydropower produced much less due to less precipitation.

From 2010 to 2015, gas demand fell by more than a third, while renewables increased by 35.9 percent. Nuclear power production decreased slightly (-6.3 percent) and, following a slight decrease in 2014, coal (hard coal and lignite) returned to the 2010 level in 2015.

The average price of a tonne of CO₂ in 2015 was 7.60 euros, which leads to coal-fired power plants having lower marginal costs than gas-fired power plants. Coal therefore outcompetes gas throughout Europe, which has resulted, for example, in the high coal power exports in 2015 from Germany to its neighbours.

Additional capacity in mainly the onshore and offshore wind energy sector will increase RES production by another 50 terawatt hours. The carbon floor price in the UK, yielding a CO₂ price signal of some 30 euros per tonne, will push out coal in the UK in favour of gas. Further efficiency developments and the relatively mild winter will lower power consumption. The demand for CO₂ allowances will therefore decrease, leading to lower CO₂ ETS prices in 2016 than in 2015.

The calculation of these costs varies tremendously depending on the specific power system and methodologies applied. Moreover, opinions diverge concerning how to attribute certain costs and benefits, not only to wind and solar energy but to the system as a whole.

Certain costs for building electricity grids and balancing can be clearly classified without much discussion as costs that arise from the addition of new renewable energy. In the literature, these costs are often estimated at +5 to +13 EUR/MWh, even with high shares of renewables.

When new solar and wind plants are added to a power system, they reduce the utilization of the existing power plants, and thus their revenues. Thus, in most cases, the cost for “backup” power increases. Calculations of these effects range between -6 and +13 EUR/MWh in the case of Germany at a penetration of 50 percent wind and PV, depending especially on the CO? cost.

A total system cost approach can assess the cost of different wind and solar scenarios while avoiding the controversial attribution of system effects to specific technologies.

As part of Europe’s renewable energy expansion plans, the PLEF countries will strive to draw 32 to 34 percent of their electricity from wind and solar by 2030. The weather dependency of these technologies impacts power systems, making increased system flexibility crucial.

Different weather patterns across Europe will decorrelate single power generation peaks, yielding geographical smoothing effects. Wind and solar output is generally much less volatile at an aggregated level and extremely high and low values disappear. For example, in France the maximum hourly ramp resulting from wind fluctuation in 2030 is 21 percent of installed wind capacity, while the Europe-wide maximum is only at 10 percent of installed capacity.

When no trading options exist, hours with high domestic wind and solar generation require that generation from renewables be stored or curtailed in part. With market integration, decorrelated production peaks across countries enable exports to regions where the load is not covered. By contrast, a hypothetical national autarchy case has storage or curtailment requirements that are ten times as high.

A more flexible power system is required for the transition to a low-carbon system. Challenging situations are manifold, comprising the ability to react over shorter and longer periods. To handle these challenges, the structure of the conventional power plant park and the way power plants operate will need to change. Renewables, conventional generation, grids, the demand side and storage technologies must all become more responsive to provide flexibility.

Cost of power from large scale photovoltaic installations in Germany fell from over 40 ct/kWh in 2005 to 9ct/kWh in 2014. Even lower prices have been reported in sunnier regions of the world, since a major share of cost components is traded on global markets.

Even in conservative scenarios and assuming no major technological breakthroughs, an end to cost reduction is not in sight. Depending on annual sunshine, power cost of 4-6 ct/kWh are expected by 2025, reaching 2-4 ct/kWh by 2050 (conservative estimate).

Cost of hardware sourced from global markets will decrease irrespective of local conditions. However, inadequate regulatory regimes may increase cost of power by up to 50 percent through higher cost of finance. This may even overcompensate the effect of better local solar resources.

Based on outdated cost estimates, most scenarios modeling future domestic, regional or global power systems foresee only a small contribution of solar power. The results of our analysis indicate that a fundamental review of cost-optimal power system pathways is necessary.

The introduction of competitivebidding for a specific renewable-energy technology in a given country needs to be preceded by a thorough analysis of the conditions for successful tendering, including market structure and competition. Specific project characteristics of the various renewable-energy technologies must be considered appropriately in the auction design.

Prior to adoption of tendering schemes, multiple design options should be tested in which the prequalification criteria, auction methods, payment options, lotsizes, and locational aspects are varied. Learning and gaining experience is of utmost importance, as poor auction design can increase overall costs or endanger deployment targets.

Experiences made with auctions for certain technologies (e.g. solar PV) cannot be readily applied to other types of renewable energy. Onshore wind is particularly difficult due to the complexity of project development, including extended project time frames (often over two years), the involvement of multiple permitting authorities and the need for local acceptance.

The auction should be designed to facilitate a sufficiently large number of participating actors, as this will minimise strategic behaviour and ensure a level playing field for all actors, thus enabling healthy competition. As renewable deployment often hinges critically on local acceptance, enabling the participation of smaller, decentralised actorsin auctions is important.

This is the result of a conservative comparison of current feed-in tari­s in Germany with the agreed strike price for new nuclear in the UK (Hinkley Point C) and current cost estimates for CCS, neglecting future technology cost reductions in any of the four technologies.

A meaningful comparison of the costs of di­erent energy technologies should take into account the need for backup capacities and peak load plants. Such a comparison shows that while additional costs arise for backup gas capacity in a system based on wind and solar PV, these costs are small compared to the higher power generation cost of nuclear.

The reason for this paradox is not to be found in thedecision to phase out nuclear power – the decrease of nuclear generation is fully offset by an increasedgeneration from renewables. Rather, the paradox is caused by a fuel switch from gas to coal.

Since 2010, coal and CO2 prices have decreased, whilegas prices have increased. Accordingly, Germany’s coal-fired power plants (both new and old) are able to produceat lower costs than gas-fired power plants in Germany and in the neighbouring electricity markets thatare coupled with the German market. This has yielded record export levels and rising emissions in Germany.

Sharp decreases in generation fromlignite and hard coal of 62 and 80 percent, respectively, are expected in the next 15 years while theshare of gas in electricity generation will have to increase from 11 to 22 percent. This goes in line with thegovernments’ renewables and climate targets for 2030.

Such a strategy – call it a coal consensus –would bring power producers, labour unions, the government and environmental groups together in findingways to manage the transformation.

Regional distribution of this renewable energy has little impact on the total cost of power supply.

To promote technology development and reduce the cost of electricity for consumers, expansion should be continued, but on a lower level than current plans foresee.

Solely in terms of cost, a few years of delays for the additional transmission lines foreseen in the German Grid Development Planning act would not be critical. Further expansion of renewables does not have to wait for these new transmission lines.

Only if cost of such systems drop by 80 % in the next 20 years would a renewable expansion path focusing on photovoltaics + storage be an economically viable option.