Jonas Egerer

EU Involvement in Electricity and Natural Gas Transmission Grid Tarification

Each semester the THINK project publishes two research reports based on topics proposed by the European Commission

Development Scenarios for the North and Baltic Sea Grid: A Welfare Economic Analysis

The North and Baltic Sea Grid is one of the largest pan-European infrastructure projects raising high hopes regarding the potential of harnessing large amounts of renewable electricity, but also concerns about the implementation in largely nationally dominated regulatory regimes. The paper develops three idealtype development scenarios and quantifies the technical-economic effects: i) the Status quo in which engagement in the North and Baltic Sea is largely nationally driven; ii) a Trade scenario dominated by bilateral contracts and point-to-point connections; and iii) a Meshed scenario of fully interconnected cables both in the North Sea and the Baltic Sea, a truly pan-European infrastructure. We find that in terms of overall welfare, the meshed solution is superior; however, from a distributional perspective there are losers of such a scheme, e.g. the incumbent electricity generators in France, Germany, and Poland, and the consumers in low-price countries, e.g. Norway and Sweden. Merchant transmission financing, based on congestion rents only, does not seem to be a sustainable option to provide sufficient network capacities, and much of the investment will have to be regulated to come about. We also find strong interdependencies between offshore grid expansion and the subsequent onshore network.

National-strategic investment in European power transmission capacity

The transformation of the European energy system requires substantial investment in transmission capacity to facilitate cross-border trade and to efficiently integrate renewable energy sources. However, network planning in the EU is still mainly a national prerogative. In contrast to other studies aiming to identify the pan-European (continental) welfare-optimal transmission expansion, we investigate the impact of national regulators deciding on network investment strategically, with the aim of maximizing consumer surplus and generator profits in their jurisdiction. This reflects the inadequacy of current mechanisms to compensate for welfare re-allocations across national boundaries arising from network upgrades. We propose a three-stage equilibrium model to describe the Nash game between zonal planners (i.e., national governments, regulators, or system operators), each taking into account the impact of network expansion on the electricity spot market and the resulting welfare effects on the constituents within her jurisdiction. Using a four-node sample network, we identify several Nash equilibria of the game between the zonal planners, and illustrate the failure to reach the first-best welfare expansion in the absence of an effective compensation mechanism.

Power System Transformation toward Renewables: Investment Scenarios for Germany

We analyze distinctive investment scenarios for the integration of fluctuating renewables in the German power system. Using a combined model for dispatch, transmission, and investment, three different investment options are considered, including gas-fired power plants, pumped hydro storage, and transmission lines. We find that geographically optimized power plant investments dominate in the reference scenarios for 2024 and 2034. In scenarios with decreased renewable curtailment, storage and transmission requirements significantly increase. In an alternative scenario with larger investments into storage, system costs are only slightly higher compared to the reference; thus, considering potential system values of pumped hydro storage facilities that are not included in the optimization, a moderate expansion of storage capacities appears to be a no-regret strategy from a system perspective. Additional transmission and storage investments may not only foster renewable integration, but also increase the utilization of emission-intensive plants. A comparison of results for 2024 and 2034 indicates that this is only a temporary effect. In the long run, infrastructure investments gain importance in the context of an ongoing energy transition from coal to renewables. Because of long lead times, planning and administrative procedures for large-scale projects should start early.

Power System Transformation towards Renewables: An Evaluation of Regulatory Approaches for Network Expansion

We analyze various regulatory regimes for electricity transmission investment in the context of a transformation of the power system towards renewable energy. We study distinctive developments of the generation mix with different implications on network congestion, assuming that a shift from conventional power plants towards renewables may go along with exogenous shocks on transmission requirements, which may be either of temporary or permanent nature. We specifically analyze the relative performance of a combined merchant-regulatory price-cap mechanism, a cost-based rule, and a non-regulated approach in dynamic generation settings. Through application in a stylized two-node network, we find that incentive regulation may perform satisfactorily only when appropriate weights are used. While quasi-ideal weights generally restore the beneficial properties that incentive regulatory mechanisms are well-known for in static settings, pure Laspeyres weights may either lead to overinvestment (stranded investments) or delayed investments as compared to the welfare optimum benchmark. Stranded investments could then be avoided through proper handling of weights. Model results indicate that using average Laspeyres-Paasche weights appears to be an appropriate strategy in the context of permanently or temporarily increasing network congestion. Our analysis motivates further research aimed to characterize optimal regulation for transmission expansion in the context of renewable integration.

Regulated Expansion of Electricity Transmission Networks: The Effects of Fluctuating Demand and Wind Generation

We study the performance of different regulatory approaches for the expansion of electricity transmission networks in the light of realistic demand patterns and fluctuating wind power. In particular, we are interested in the relative performance of a combined merchant-regulatory mechanism compared to a cost-based and a merchant-like approach. In contrast to earlier research, we explicitly include both an hourly time resolution and fluctuating wind power, which allows representing demand in a very realistic way. This substantially increases the real-world applicability of results compared to previous analyses, which were based on simplifying assumptions. We show that a combined merchant-regulatory regulation, which draws on a cap over the two-part tariff of the Transco, leads to welfare outcomes far superior to the modeled alternatives. This result proves to be robust over a range of different cases and sensitivity analyses. We also find that the intertemporal rebalancing of the two-part tariff carried out by the Transco so as to expand the network is such that the fixed tariff part turns out to be relatively large compared to extension costs.

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.

Optimal infrastructure investments for renewable energy integration in Germany

We analyze optimal infrastructure investments for the integration of variable renewables in the German electricity system. Using a combined dispatch, transmission, and investment model, we compare four scenarios with different investment options, including gas-fired power plants, pumped hydro storage and transmission lines. In a reference scenario of the year 2024, geographically optimized investments into gas-fired power plants dominate. However, system costs are only slightly higher in scenarios with increased investments into networks and storage. Considering additional system values of storage facilities that are not included in the optimization, additional pumped storage capacity in Germany appears to be beneficial. We also find that increased system flexibility may not only improve renewable integration, but also increase the utilization of emission-intensive plants during a transition period.

A Spatial Electricity Market Model for the Power System of Kazakhstan

Kazakhstan envisions a transition towards a green economy in the next decades which poses an immense challenge as the country heavily depends on (hydro-)carbon resources, for both its economy and its energy system. In this context, there is a lack of comprehensive and transparent planning tools to assess possible sustainable development pathways in regard to their technical, economic, and environmental implications. We present such a tool with a comprehensive techno-economic model of the Kazakh electricity system which determines the hourly least-cost generation dispatch based on publicly available data on the technical and economic characteristics of power plants and the transmission infrastructure. This modeling framework accounts for the particularities of the Kazakh electricity system: i) it has a detailed representation of combined heat and power, and ii) line losses are endogenously determined using a linear approximation. Model results are examined for a typical winter week (with annual peak load) and a typical summer week (with the hour of lowest annual load) presenting regionally and temporally disaggregated results for power generation, line utilization, and nodal prices. In an application to market design, the paper compares nodal and zonal pricing as two possible pricing schemes in Kazakhstan for the envisioned strengthening of the day-ahead market. In general, the model can be readily used to analyze the least-cost dispatch of the current Kazakh electricity system and can be easily expanded to assess the sectors development. Among others, possible applications include investment in transmission lines and in the aging power plant fleet, scenarios and policy assessment for emission reduction, and questions of market liberalization and market design.

Low-carbon transformation of the German and European electricity systems

This dissertation addresses the low-carbon transformation of the German and European electricity sectors. It applies techno-economic electricity sector models to research questions on market design and infrastructure investment. The first part consists of three chapters on Germany. It starts with a chapter on the nodal dispatch model for the German electricity system (ELMOD-DE) which implements the DC load flow approach. In March 2016, the respective model source code and a nodal and hourly dataset for 2012 were published to support the effort of increasing transparency in policy-oriented energy sector modeling. In the following chapter, ELMOD-DE is applied to analyze the effects of one northern and one southern bidding zone on the German electricity market. The results discuss the effect on re-dispatch levels, deviations in zonal prices, and distributional effects. The third chapter extends ELMOD-DE to a mixed-integer linear program (MILP) to determine nodal investment for renewable integration in gas-fired power stations, in pumped-storage hydroelectric plants, and in HVAC and HVDC transmission lines for the years 2024 and 2034. The second part consists of three chapters on transmission investment. It starts with a chapter on national-strategic decisions on network expansion. A game theory model determines stable expansion strategies, the effect of cost-allocation schemes, and changes in national welfare levels as results of cross-border transmission investment. The following chapter raises the issue of dynamic changes in network congestion during the low-carbon transformation. It applies a mathematical problem with equilibrium constraints (MPEC) to test different regulatory approaches and their effect on network investment. The last chapter, again, uses a MILP to determine network investment for the European transmission network up to 2050. The nodal model optimizes investments in HVDC lines and in the existing HVAC network for three different scenarios, comparing the results to the Roadmap 2050.