Clemens Gerbaulet

Power system impacts of electric vehicles in Germany: Charging with coal or renewables?

We analyze the impacts of future scenarios of electric vehicles (EVs) on the German power system, drawing on different assumptions on the charging mode. We find that the impact on the load duration curve strongly differs between charging modes. In a fully user-driven mode, charging largely occurs during daytime and in the evening, when power demand is already high. User-driven charging may thus have to be restricted because of generation adequacy concerns. In contrast, cost-driven charging is carried out during night-time and at times of high PV availability. Using a novel model formulation that allows for simulating intermediate charging modes, we show that even a slight relaxation of fully user-driven charging results in much smoother load profiles. Further, cost-driven EV charging strongly increases the utilization of hard coal and lignite plants in 2030, whereas additional power in the user-driven mode is predominantly generated from natural gas and hard coal. Specific CO2 emissions of EVs are substantially higher than those of the overall power system, and highest under cost-driven charging. Only in additional model runs, in which we link the introduction of EVs to a respective deployment of additional renewables, electric vehicles become largely CO2-neutral.

Cost-minimal investments into conventional generation capacities under a Europe-wide renewables policy

For the future development of the European electricity system, renewable generation is assigned a dominant role with the underlying aim to reduce the carbon intensity. This has direct implications for conventional, dispatchable generation capacities and their future development. The objective of this paper is to investigate the investments in conventional generation technologies for a given renewable development path. We develop an integrated dynamic investment model that endogenously determines cost-minimal investments into generation and network infrastructure. Our results show that the overall level of investment is comparable to other studies, but the underlying investment cost assumptions determine the choice of technology.

Power System Impacts of Electric Vehicles in Germany: Charging with Coal or Renewables

We analyze future scenarios of integrating electric vehicles (EV) into the German power system, drawing on different assumptions on the charging mode. We use a numerical dispatch model with a unit-commitment formulation which minimizes dispatch costs over a full year. While the overall energy demand of the EV fleets is rather low in all scenarios, the impact on the system’s load duration curve differs strongly between charging modes. In a fully user-driven mode, charging largely occurs during daytime and in the evening, when power demand is already high. User-driven charging may thus have to be restricted in the future because of generation adequacy concerns. In contrast, cost-driven charging is carried out during night-time and at times of high PV availability. Using a novel model formulation that allows for intermediate charging modes, we show that even a slight relaxation of fully user-driven charging results in much smoother load profiles as well as lower charging costs. Different charging patterns go along with respective changes in power plant dispatch. By 2030, cost-driven EV charging strongly increases the utilization of lignite and hard coal plants, whereas additional power in the user-driven mode is predominantly generated from natural gas and hard coal. Specific CO2 emissions of EV are substantially larger than those of the overall power system, and highest under cost-driven charging. Only in additional model runs, in which we link the introduction of EVs to a respective deployment of additional renewable generation capacity, electric vehicles become largely CO2-neutral.

European electricity grid infrastructure expansion in a 2050 context

The European climate policy targets until 2050 require an adaption of the generation portfolio in terms of renewable and fossil based generation. Assumptions on the timeline of the targets and the availability and costs of generation technologies are used in energy system models to optimize the cost minimal system transformation. The results include investments in generation technologies and their national allocation. Yet, the models are limited to the national aggregation and lack the spatial resolution required to represent individual network investments and related costs. In this paper, we analyze the impact the results of an energy system model have on demand for network expansion in the European power grid in a line-sharp representation. A cost minimizing mixed-integer problem (MIP) model calculates where in the European electricity grid extension needs to take place for different time steps (2020/30/40/50) in order to obtain the minimization of total costs for power plant dispatch and grid expansion. Scenarios based on the generation infrastructure options from the PRIMES EU-wide energy model scenarios invoke different expansion needs and a comparison is conducted. The model allows investments in the AC network and an overlay DC grid. Resulting investment costs are compared to the numbers of the European Energy Roadmap 2050.

Combining Energy Networks: The Impact of Europe's Natural Gas Network on Electricity Markets Until 2050

The interdependence of electricity and natural gas is becoming a major energy policy and regulatory issue in all jurisdictions around the world. The increased role of gas fired plants in renewable-based electricity markets and the dependence on gas imports make this issue particular striking for the European energy market. In this paper we provide a comprehensive combined analysis of electricity and natural gas infrastructure with an applied focus. We analyze different scenarios of the long-term European decarbonization pathways sketched out by the Energy Roadmap 2050, and identify criteria related to electricity and/or natural gas infrastructure and the interrelation between both markets.

Wind Providing Balancing Reserves: An Application to the German Electricity System of 2025

This paper analyzes the influence of wind turbines as new participants on prices and allocation within balancing markets. We introduce the cost-minimizing electricity sector model ELMOD-MIP, that includes detailed unit-commitment constraints, complex combined heat and power constraints, and minimum bid sizes for balancing capacity reservation. The model also features a novel approach of modeling balancing reservation by considering possible activation costs already during the reservation phase, mimicking the activation anticipation of market participants. The model includes the spot and balancing market of Germany and is applied to scenarios for 2013 and 2025. The results for 2025 show, in comparison to 2013, a price increase for positive and negative reserves, in case no new participants enter the market. With the participation of wind turbines the cost for balancing provision is reduced by 40%, but above 2013 values. The relative cost savings from wind participation are higher for negative reserve provision than positive reserve provision, as wind turbines can use their full capacity if not activated and do not have to be curtailed ex ante. The participation of wind turbines especially reduces the occurrence of peak prices for positive and negative reserves in 2025. This reduction effect occurs even with a relatively low share where wind turbines participate with only five percent of their capacity. Therefore, further fostering the process of allowing wind turbines to participate in the German reserve market seems favorable.

Robust transmission planning — An application to the case of Germany in 2050

Technological advances and climate considerations drive substantial changes within the electricity sector. Yet, these changes, although their thrust might be intuitive, are subject to large uncertainties: Technologies may be available earlier or later, international/regional co-ordination may work better or worse etc. This poses significant challenges to the task of transmission planning: Therefore, in this paper, we analyze how these uncertainties may impact transmission planning and how these impacts can be mitigated. We put a special focus on “robust” optimization techniques and analyze a stylized model of Germany in 2050. We find, somewhat counter-intuitively, that “classical” robust optimization techniques may lead to imbalanced decisions, focusing on only one of several possible realizations, especially when the absolute impact of the exogenous uncertainties leads to strongly differing costs. In that case, minimizing the maximum regret may be more preferable. Overall, we find evidence that techniques of robust transmission planning allow for savings in transmission investment and power system operations.

Scenarios for decarbonizing the European electricity sector

Since the climate conferences in Paris and Marrakesh the outstanding question is not if but how and how fast to enable a decarbonization of the European electricity sector. Nuclear power has a difficult time to survive in electricity markets in all Western countries, such as the U.S., Europe, Japan, etc., and is getting increasingly under pressure due to high costs, and the falling costs of alternative sources, such as renewable energies in combination with storage technologies. This paper compares different approaches to decarbonize the electricity sector in Europe using a specific model developed by the authors called dynEL-MOD. We find that, renewables carry the major burden of decarbonization. Scenario analysis suggests that only in the case of a breakthrough of CCTS some biomass-CCTS plants can play a role by 2050 through their negative CO2-emissions. Nuclear power (3rd or 4th generation), on the contrary, is unable to compete with other fuels even by then, and will, therefore, rely on dedicated national programs to survive until 2050. Incorporating the climate targets makes the investment into any additional fossil capacity uneconomic from 2025 onwards, resulting in a coal and natural gas phase-out in the 2040s. The model is run using different foresight assumptions. Limited foresight thus results in stranded investments of fossil capacities in the 2020s. Using a CO2 budgetary approach, on the other hand, leads to an even sharper emission reduction in the early periods before 2030, reducing overall costs.

Is There Still a Case for Merchant Interconnectors? Insights from an Analysis of Welfare and Distributional Aspects of Options for Network Expansion in the Baltic Sea Region

Despite the ongoing appetite of financial investors for merchant investments into the European electricity network, the EC is reluctant to approve such undertakings, thus implicitly favoring regulated investments. Based on a two-level model, we analyze the impact of profit-maximizing merchant transmission investment as compared to welfare-maximizing regulated transmission investment. We apply the model to the Baltic Sea region, which has in the past been subject to rapid interconnector development and still would benefit from increased interconnection. We obtain stable results indicating that merchant investment may well contribute to overall welfare, but at the same time, “the merchant takes it all”, i.e. in many cases merchant profits are close to the overall efficiency gain, and sometimes even higher. These results underline that that distributional aspects, besides mere welfare arguments should be taken into account when analyzing the impact of merchant transmission investment.

Merchant and regulated transmission investment: The case of the Baltic Sea region

Considering the current European framework in place, investment into (cross-zonal) electricity network interconnection can be merchant, profit-maximising (i.e. exempted according to Art. 17 of EC 714/2009) or regulated (i.e. rather welfare- than profit-maximising). We propose a framework for analysing the interaction of a profit-maximising merchant line investor and a cost-minimizing, regulated investor. We assume that the merchant line investor makes its decisions first, anticipating the reaction of the cost-minimizing regulator. The model is set up as a mathematical problem with equilibrium constraints. We apply the model to the Baltic Sea region (excluding the allowance for withholding capacity, which is in line with current legislation) and discuss the results. Our results indicate that - seen from a customer payments perspective - allowing for merchant investments is nearly as bad as having no merchant interconnector at all.