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.
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.
With a renewable electricity target of 40% in France and 65% in Germany by 2030, the two countries will significantly increase their production of wind and solar energy. Their conventional power plant fleet will have to be resized accordingly to avoid stranded costs.
A nuclear fleet exceeding 40 GW in 2030 would increase the national electricity export surplus and additionally postpone the achievement of the objective of reducing the share of nuclear power to 50% beyond 2030. The profitability of a nuclear fleet greater than 50 GW would not be assured in 2030, even when assuming a 60% increase in French export capacity, a doubling of interconnectors capacity in Europe and a CO2 price of 30 euros per ton of CO2.
In this case, Germany’s electricity trade balance with its neighbours is balanced. The new planned target of 65% renewable energy in electricity consumption by 2030 will ensure that Germany will not depend on undesired electricity imports while phasing-out coal.
Over the last 18 months, the French government has abolished the wealth tax, increased flat-rate social security contributions, reduced housing subsidies and increased the tobacco tax. Taken together with the energy tax increase and a lack of compensation, these measures have contributed to the widening of economic inequalities in French society.
Like any consumption tax, the CO2 surcharge on energy consumption has a greater effect on low-income households than high-income households in percentage terms. This was also the case in France. A per capita redistri-bution of revenue or other redistribution mechanisms are necessary to balance this.
In France, most of the revenue from the CO2 surcharge on energy taxes was used for consolidating the budget. The contribution climat énergie was therefore not recognised by large parts of the population as a climate protection measure. In addition to so-cial compensation, it is therefore necessary to use the revenues for climate protection measures which are transparent and easily accessible.
Some key design elements of intraday and balancing markets as well as imbalance settlement rules distort wholesale power price signals, increasing the cost of providing flexibility. This highlights the need to adjust key market design elements and requires continuous political momentum to coordinate efforts regionally.
Restrictive requirements for market participation, mainly relating to demand response and renewables, constrain the flexibility potential. In the balancing markets, small minimum bid sizes and short contracting periods would be required. A regulatory framework enabling independent aggregation should be implemented for fully tapping the flexibility potential.
A joint balancing market design in the PLEF region with short product duration, late gate closure and marginal pricing would enable efficient cross-border competition for flexibility services. Getting the pricing right in balancing mechanisms is important as it support sefficient pricing in preceding day-ahead and intraday markets – where most of the flexibility is traded.
Intraday markets are critical for integrating wind and solar, as they allow for trades responding to updated generation forecasts. Today, explicit cross-border capacity allocation as well as misalignments in gate closure times across the region and differing product durations result in inefficient intraday energy and interconnector capacity allocation. Thus, harmonised rules and improved implicit cross-border allocation methods are needed, e.g. improved continuous trading or intraday auctions.
The Danish power system has been undergoing a transformation, moving from a highly centralised to a more decentralised structure in electricity generation. There has been a significant increase not only in wind power but also in distributed generation from combined heat and power plants since the 1980s. Broad-based political agreements on energy policy have provided security for investors while enabling a smooth and continuous transition to a sustainable power sector.
The interdependencies among these different sectors are reflected in Danish energy policy goals, in scenario analyses as well as in concrete initiatives for implementing the transition to a renewables based energy system.
The Danish tendering scheme is characterised by Contracts for Difference with guaranteed support payments, a guaranteed grid connection and a one-stop-shop authority for preliminary site assessments when new offshore wind energy projects are developed.
The challenge of integrating a high share of wind power led Danish institutions and market participants to develop several flexibility options early on, including use of interconnectors to other countries, increasing the flexibility of thermal power plants, making district heating more flexible, encouraging system friendly wind power, implementing demand side flexibility as well as introducing alternative options for procuring ancillary services.
With 6.4 GW of net transfer capacity to Norway, Sweden and Germany (Danish peak demand: 6 GW), Denmark is able to sell electricity during times of high wind production, and to import electricity in times of low wind production. The use of the 2.4 GW net transfer capacity to Germany is sometimes limited for export depending on the wind conditions in Northern Germany.
Danish coal power plants have been optimised to allow very steep ramp-up gradients, shorter start-up times and low but stable minimum generation levels. Flexibility in providing ancillary services has further reduced must-run capacity
Regulation has been reshaped to reduce heat bound electricity generation in situations with high wind energy feed-in. In the future district heating systems are envisioned to become electricity consumers rather than producers in times of high wind power production. In spite of changes already adopted to the energy tax system, further regulatory measures are still needed to tap the full potential of using power for heat.
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.
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.