Variable renewable energy droughts, so called Dunkelflaute events, emerge as a challenge for climate-neutral energy systems based on variable renewables. Here we characterize European drought events for on- and offshore wind power, solar photovoltaics, and renewable technology portfolios, using 38 historic weather years and an advanced identification method. Their characteristics heavily depend on the chosen drought threshold, questioning the usefulness of single-threshold analyses. Applying a multi-threshold framework, we quantify how the complementarity of wind and solar power temporally and spatially alleviates drought frequency, return periods, duration, and severity within (portfolio effect) and across countries (balancing effect). We identify the most extreme droughts, which drive major discharging periods of long-duration storage in a fully renewable European energy system, based on a policy-relevant decarbonization scenario. Such events comprise sequences of shorter droughts of varying severity. The most extreme event occurred in winter 1996/97 and lasted 55 days in an idealized, perfectly interconnected setting. The average renewable availability during this period was still 47% of its long-run mean. System planners must consider such events when planning for storage and other flexibility technologies. Methodologically, we conclude that using arbitrary single calendar years is not suitable for modeling weather-resilient energy scenarios.

To ensure security of supply in the power sector, many countries are considering capacity mechanisms. Simultaneously, the expansion of variable renewables increases the need for power sector flexibility, with promising options on the demand side. We analyze how a centralized capacity market and an advanced reliability reserve with a moderately high activation price affect demand-side flexibility investments in a German 2030 case study. Using a capacity expansion model with detailed demand-side flexibility potentials, we show that a centralized capacity market caps wholesale market prices, thereby reducing incentives for flexibility investments. The reliability reserve induces seven times higher flexibility investments in energy-intensive industries and twice as high investments in district heating storage, while achieving security of supply at similar electricity supply costs. The reliability reserve could create a learning environment for flexibility technologies to support the transition to climate neutrality, and policymakers should consider it in forthcoming capacity mechanism decisions.

The transition to decarbonized energy systems has fueled a controversial debate over the necessity of traditional “baseload” power. Skepticism remains regarding the reliability and economic feasibility of power systems relying mainly on cheap variable renewable energy (VRE) sources. Addressing this, the German Academies' project “Energy Systems of the Future” (ESYS) analyzed the role of baseload power plants within a decarbonized, continental-scale energy system. Their findings indicate that a secure, net-zero European electricity system is technically robust and economically viable when based on VRE paired with extensive flexibility, storage, and grid interconnections, without requiring new baseload capacity. The integration of new low-carbon baseload technologies, such as nuclear fission or fusion, natural gas with carbon capture and storage (CCS), or geothermal energy, has a marginal impact on overall system costs. While low-cost baseload technologies could be efficiently integrated to achieve high utilization, their future role is contingent on achieving cost reductions beyond current realities.

Coping with prolonged periods of low availability of wind and solar power, alsoreferred to as variable renewable energy droughts or"Dunkelflaute",emergesas a key challenge for realizing decarbonized energy systems based onrenewable energy. Here we investigate the role of long-duration electricitystorage and geographical balancing through transmission in dealing with suchevents in Europe, combining a time series analysis of renewable availabilitywith power sector modeling of 35 historical weather years. Wefind thatextreme droughts define long-duration storage operation and investment.Assuming policy-relevant interconnection, the least-cost system in our modelcapable of coping with the most extremeevent requires 351 terawatt hourslong-duration storage capacity, corresponding to 7% of yearly Europeanelectricity demand. While nuclear power can partially reduce storage needs,the storage-mitigating effect of fossilbackup plants in combination with car-bon removal is limited. Policymakers and system planners should prepare for arapid expansion of long-duration storage to safeguard the renewable energytransition in Europe.

Prosumer households that generate and store electricity from rooftop PV installations play an increasing role in electricity markets around the world. As retail tariffs usually do not convey time-varying wholesale price signals to households and the rollout of smart meters is low in many countries, prosumers do not necessarily self-consume and feed-in solar electricity in a system-friendly way. The effects of such system-blind behaviours are typically neglected in energy system models, which rarely account for prosumers. In this paper, we embed a calibrated self-generation constraint into a linear capacity expansion model to approximate the incentives of prosumers to minimise their electricity bills. We apply our method to a German case study for 2030 featuring sector coupling with battery electric vehicles. We show that parametrising the self-generation constraint such that the prosumer electricity bill is as low as possible approximates prosumer decisions well for a broad range of tariff schemes. Based on this, we quantify distortions that might arise in energy models that do not account for prosumers. For our case study, we find that the optimal battery storage capacity increases by up to 200 prosumer constraints are included. The main driver is the imperfect substitutability between home and utility-scale batteries. We conclude that energy system models could benefit from implementing this straightforward method.

Residential electricity consumers equipped with photovoltaic (PV) systems and battery storage, also referred to as solar prosumers, are transforming electricity markets. While previous research has dealt with various aspects of solar prosumage, dedicated analyses of their interactions with the transmission grid under varying tariff designs are sparse. We explore the influence of different pricing regimes on prosumer investment and dispatch decisions and their subsequent impact on the transmission grid. Using an integrated modeling approach that combines two open-source dispatch, investment and grid models, we simulate prosumage behavior in Germany's electricity market under real-time or time-invariant pricing, as well as under zonal or nodal pricing. Our findings show that zonal pricing favors prosumer investments, while time-invariant pricing rather hinders it. In comparison, regional solar availability emerges as a larger driver for rooftop PV investments. The impact of prosumer strategies on grid congestion remains limited within the scope of our model-setup, in which home batteries cannot be used for energy arbitrage.

While battery electric vehicles (BEVs) play a key role for decarbonizing the transport sector, their impact on the power sector heavily depends on their charging strategies. Here we systematically analyze various combinations between inflexible, smart and bidirectional (or vehicle-to-grid, V2G) charging of 15 million electric cars in Germany. Using a capacity expansion model, we find that even a moderate share of bidirectional charging below 30

Hydrogen-based long-duration electricity storage (LDES) is a key component of renewable energy systems to deal with seasonality and prolonged periods of low wind and solar energy availability. In this paper, we investigate how electrified heating with heat pumps impacts LDES requirements in a fully renewable European energy system, and which role thermal storage can play. Using a large weather dataset of 78 weather years, we find that electrified heating significantly increases LDES needs, as optimal average energy capacities more than quadruple across all weather years compared to a scenario without electrified heating. We attribute 75 effect, as additional electric load amplifies storage needs during times of low renewable availability. The remaining 25 where exceptional cold spells coincide with periods of renewable scarcity. Furthermore, heat pumps increase the variance in optimal storage capacities between weather years substantially because of demand-side weather variability. Long-duration thermal storage attached to district heating networks can reduce LDES needs by on average 36 electrification, policymakers should expedite the creation of adequate regulatory frameworks for both long-duration storage types to de-risk investments in light of high weather variability.

Coping with prolonged periods of low availability of wind and solar power, also referred to as "Dunkelflaute", emerges as a key challenge for realizing a decarbonized European energy system fully based on renewable energy sources. Here we investigate the role of long-duration electricity storage and geographical balancing in dealing with such variable renewable energy droughts. To this end, we combine renewable availability time series analysis and power sector modeling, using 36 historical weather years. We find that extreme drought events define long-duration storage operation and investment. The most extreme event in Europe occurred in the winter of 1996/97. Assuming policy-relevant interconnection, long-duration storage of 351TWh or 7% of yearly electricity demand is required to deal with this event. As it affects many countries simultaneously, a storage capacity of 159 TWh or 3% of yearly electricity demand remains required even in the extreme case of unconstrained geographical balancing. Before and during Dunkelflaute events, we find complex interactions of long-duration storage with other flexibility options. Sensitivity analyses illustrate that firm zero-emission generation technologies would only moderately reduce long-duration storage needs. Thus, policymakers and system planners should prepare for a rapid expansion of long-duration storage capacity to safeguard the renewable energy transition in Europe. We further argue that using multiple weather years that include pronounced renewable energy droughts is required for weather-resilient energy system modeling.

Germany’s energy transition relies on variable renewables and electricity use across sectors, and it needs to accelerate. We argue that consistent policy commitments to proven technologies, such as wind and solar power, heat pumps and electric cars are needed. Germany’s energy transition relies on variable renewables and electricity use across sectors, and it needs to accelerate. This Comment argues that consistent policy commitments to proven technologies, such as wind and solar power, heat pumps and electric cars are needed.

Variable renewable energy droughts, so called Dunkelflaute events, emerge as a challenge for climate-neutral energy systems based on variable renewables. Here we characterize European drought events for on- and offshore wind power, solar photovoltaics, and renewable technology portfolios, using 38 historic weather years and an advanced identification method. Their characteristics heavily depend on the chosen drought threshold, questioning the usefulness of single-threshold analyses. Applying a multi-threshold framework, we quantify how the complementarity of wind and solar power temporally and spatially alleviates drought frequency, return periods, duration, and severity within (portfolio effect) and across countries (balancing effect). We identify the most extreme droughts, which drive major discharging periods of long-duration storage in a fully renewable European energy system, based on a policy-relevant decarbonization scenario. Such events comprise sequences of shorter droughts of varying severity. The most extreme event occurred in winter 1996/97 and lasted 55 days in an idealized, perfectly interconnected setting. The average renewable availability during this period was still 47

As variable renewable energy sources increasingly gain importance in global energy systems, there is a growing interest in understanding periods of variable renewable energy shortage (``Dunkelflauten''). Defining, quantifying, and comparing such shortage events across different renewable generation technologies and locations presents a surprisingly intricate challenge. Various approaches exist in different bodies of literature, such as hydrology, wind and solar energy analysis, or energy system modeling. The subject of interest in previous analyses ranges from single technologies in specific locations to diverse technology portfolios across multiple regions, focusing either on supply from variable renewables or its mismatch with electricity demand. We provide an overview of methods for quantifying variable renewable energy shortage. We explain and critically discuss the merits and challenges of different approaches for defining and identifying shortage events and propose further methodological improvements for more accurate shortage determination. Additionally, we elaborate on comparability requirements for multi-technological and multi-regional energy shortage analysis. In doing so, we aim to contribute to unifying disparate methodologies, harmonizing terminologies, and providing guidance for future research.

Shared pooled mobility has been hailed as a sustainable mobility solution that uses digital innovation to efficiently bundle rides. Multiple disciplines have started investigating and analyzing shared pooled mobility systems. However, there is a lack of cross-community communication making it hard to build upon knowledge from other fields or know which open questions may be of interest to other fields. Here, we identify and review 9 perspectives: transdisciplinary social sciences, social physics, transport simulations, urban and energy economics, psychology, climate change solutions, and the Global South research and provide a common terminology. We identify more than 25 000 papers, with more than 100 fold variation in terms of literature count between research perspectives. Our review demonstrates the intellectual attractivity of this as a novel perceived mode of transportation, but also highlights that real world economics may limit its viability, if not supported with concordant incentives and regulation. We then sketch out cross-disciplinary open questions centered around (1) optimal configuration of ride-pooling systems, (2) empirical studies, and (3) market drivers and implications for the economics of ride-pooling. We call for researchers of different disciplines to actively exchange results and views to advance a transdisciplinary research agenda.

Heat pumps play a major role in decreasing fossil fuel use in heating. They increase electricity demand, but could also foster the system integration of variable renewable energy sources. We analyze three scenarios for expanding decentralized heat pumps in Germany by 2030, focusing on the role of buffer heat storage. Using an open-source power sector model, we assess costs, capacity investments, and emissions effects. We find that investments in solar photovoltaics can cost-effectively accompany the roll-out of heat pumps in case wind power expansion potentials are limited. Results further show that short-duration heat storage substantially reduces the need for firm capacity and battery storage. Larger heat storage sizes do not substantially change the results. Increasing the number of heat pumps from 1.7 to 10 million units could annually save more than half of Germany's private and commercial natural gas consumption and around half of households' building-related CO2 emissions. Investments in solar photovoltaics could cost-effectively support the expansion of heat pumps by 2030, and small thermal storage of heat pumps could reduce the additional need for firm capacity and battery storage, according to an analysis that uses an open-source power sector model.

Abstract The German “traffic light” (Ampel) coalition has set ambitious new energy transition targets. Using an open data tool developed at DIW Berlin, we discuss the progress and challenges of selected indicators. Since the government took over, photovoltaic capacity increased by 45 % to 87 GW by April 2024, with a planned doubling by 2030. However, onshore wind power grew by only 11 % to 62 GW. The installation rates of heat pumps and electric vehicles are also insufficient to reach the 2030 targets of six million and 15 million, respectively. Currently, only about 1.8 million heat pumps and 1.5 million electric cars are in use. Accelerated efforts and policy measures are necessary to achieve the energy transition goals, focusing on strategic planning and implementation.

Electrifying the car fleet is a major strategy for mitigating emissions in the transport sector. As electrification cannot solve all negative externalities associated with cars, reducing the size of the car fleet would be beneficial. Electric carsharing could reconcile current car usage habits with a smaller fleet, but this may reduce the potential of electric cars to align their grid interactions with variable renewable electricity generation. We investigate how electric carsharing may impact the power sector by combining three methods: sequence clustering of car travel diaries, generation of synthetic electric vehicle time series, and power sector modeling. We show that switching to electric carsharing only moderately increases power sector costs- less than 110 euros per substituted car in our main setting. This effect is largest with bidirectional charging. We conclude that the power sector interactions of shared electric car fleets could still be aligned with variable renewable electricity generation.

Various options are discussed to de-fossilize heavy-duty vehicles, including battery-electric vehicles (BEVs), electric road systems (ERS), and indirect electrification via hydrogen fuel cells or e-fuels. We investigate their power sector implications in future scenarios of Germany, with high renewable energy shares, using an open-source capacity expansion model and route-based truck traffic data. Power sector costs are the lowest for flexibly charged BEVs that also carry out vehicle-to-grid operations and the highest for e-fuels. If BEVs and ERS-BEVs are not optimally charged, power sector costs increase but are still substantially lower than in scenarios with hydrogen or e-fuels. This is because indirect electrification is less energy efficient, which outweighs potential flexibility benefits. BEVs and ERS-BEVs favor solar photovoltaic energy, while hydrogen and e-fuels favor wind power and increase fossil electricity generation. Results remain qualitatively robust in sensitivity analyses.

Integrated assessment models (IAMs) are a central tool for the quantitative analysis of climate change mitigation strategies. However, due to their global, cross-sectoral and centennial scope, IAMs cannot explicitly represent the spatio-temporal detail required to properly analyze the key role of variable renewable electricity (VRE) for decarbonizing the power sector and end-use electrification. In contrast, power sector models (PSMs) incorporate high spatio-temporal resolutions, but tend to have narrower scopes and shorter time horizons. To overcome these limitations, we present a novel methodology: an iterative and fully automated soft-coupling framework that combines the strengths of a IAM and a PSM. This framework uses the market values of power generation as well as the capture prices of demand in the PSM as price signals that change the capacity and power mix of the IAM. Hence, both models make endogenous investment decisions, leading to a joint solution. We apply the method to Germany in a proof-of-concept study using the IAM REMIND and the PSM DIETER, and confirm the theoretical prediction of almost-full convergence both in terms of decision variables and (shadow) prices. At the end of the iterative process, the absolute model difference between the generation shares of any generator type for any year is <5% for a simple configuration (no storage, no flexible demand), and 6-7% for a more realistic and detailed configuration (with storage and flexible demand). For the simple configuration, we mathematically show that this coupling scheme corresponds uniquely to an iterative mapping of the Lagrangians of two power sector optimization problems of different time resolutions, which can lead to a comprehensive model convergence of both decision variables and (shadow) prices. Since our approach is based on fundamental economic principles, it is applicable also to other IAM-PSM pairs.

To reduce greenhouse gas emissions, many countries plan to massively expand wind power and solar photovoltaic capacities. These variable renewable energy sources require additional flexibility in the power sector. Both geographical balancing enabled by interconnection and electricity storage can provide such flexibility. In a 100% renewable energy scenario of 12 central European countries, we investigate how geographical balancing between countries reduces the need for electricity storage. Our principal contribution is to separate and quantify the different factors at play. Applying a capacity expansion model and a factorization method, we disentangle the effect of interconnection on optimal storage capacities through distinct factors: differences in countries' solar PV and wind power availability patterns, load profiles, as well as hydropower and bioenergy capacity portfolios. Results indicate that interconnection reduces storage needs by around 30% in contrast to a scenario without interconnection. Differences in wind power profiles between countries explain around 80% of that effect.

The use of green hydrogen can support the decarbonization of sectors which are difficult to electrify, such as industry or heavy transport. Yet, the wider power sector effects of providing green hydrogen are not well understood so far. We use an open-source electricity sector model to investigate potential power sector interactions of three alternative supply chains for green hydrogen in Germany in the year 2030. We distinguish between model settings in which Germany is modeled as an electric island versus embedded in an interconnected system with its neighboring countries, as well as settings with and without technology-specific capacity bounds on wind energy. The findings suggest that large-scale hydrogen storage can provide valuable flexibility to the power system in settings with high renewable energy shares. These benefits are more pronounced in the absence of flexibility from geographical balancing. We further find that the effects of green hydrogen production on the optimal generation portfolio strongly depend on the model assumptions regarding capacity expansion potentials. We also identify a potential distributional effect of green hydrogen production at the expense of other electricity consumers, of which policy makers should be aware.