Conference Agenda

We develop a merit model with a continuum of facilities and test its predictions for the German power market over the years 2019-2024, including the COVID-19 period and the 2022 EU energy crisis. First, the model formalizes how demand and fuel prices continuously and jointly determine the marginal plant and thereby the non-linear pass-through of input prices into wholesale power prices. Second, the paper estimates gas and coal price pass-through in electricity prices, showing that the gas-price pass-through increased with renewable supply in 2020, yet decreased with renewable supply in 2022, consistent with a crisis-driven reshuffling of the merit order. Third, using the estimated pass-through model, the analysis quantifies the economic benefits of additional renewable generation in 2022 by simulating how extra wind and solar capacity lower residual coal and gas use and reduce electricity prices, shifting rents away from thermal generators toward consumers. Together, these contributions link a new continuous-facility merit framework to empirical evidence on fuel price pass-through and to welfare effects of renewables in a period of extreme energy market stress.

This paper studies the short-run effects of wind energy integration on market power in wholesale electricity markets using data from the ERCOT real-time market. A semi-structural framework decomposes bid–cost markups into static market power and dynamic operating cost components. Preliminary results suggest that higher wind generation is associated with lower markups on average, consistent with wind flattening residual demand. However, transmission congestion amplifies local market power. In particular, markups are higher during periods of low wind availability and binding transmission congestion, when residual demand becomes steeper and local market power can emerge. These findings suggest that the competitive effects of renewable integration depend critically on short-run transmission conditions, highlighting the importance of congestion management in wholesale electricity markets.

We construct a full network model of the European power grid and use it to solve a model that explicitly prices all 6,980 transmission network operating constraints included in the model. We use a detailed dataset of 20,416 generation units in Europe, including 1,014 thermal generation units, and estimate marginal costs of generation using data on thermal efficiency and daily spot prices of input fuels and European Union carbon allowances for the year 2023. We use detailed data on the layout of the European power grid to construct shift factors which govern the operation of the power grid, comparable to those used by wholesale market operators in the United States. We use the generation unit marginal cost estimates and transmission network shift factors to to solve for the European network-wide minimum operating cost dispatch to meet forecast and realized hourly nodal demands given forecast and realized hourly intermittent renewable generation. This yields potentially 5,324 distinct hourly locational marginal prices (LMPs) and generation unit operating levels at all nodes of the transmission network using shift factors and the implied prices of network operating constraints. We find that the simulated aggregate generation mix is similar to the one actually observed in 2023, but there is a notable increase in the output from natural gas and hard coal units, and a decrease in output from lignite units. We observe an 8% increase in the aggregate magnitude of cross-border imports and exports and significant reallocations of aggregate generation between countries. We observe significant regional and locational price differences within and across countries, which we use to analyze how increased spatial granularity in wholesale pricing would change the compensation received by different generation units depending on their location. Finally, we estimate the differences in as-offered costs and carbon dioxide emissions between our simulation and observed data from the year 2023 using our marginal cost and emission factor estimates. We find that our simulation yields slightly lower total as-offered costs compares to observed data, and we find evidence to suggests that emissions may have been lower in our simulation compared to observed data. We find that the total variable costs to operate the wholesale market were 3 % lower in our simulation compared to actual data and total carbon dioxide emissions were 1% lower while theoutput from fossil-fired generators was 2.5 % higher in our simulation compared to actual data.

The Net Zero Industry Act (NZIA) promotes non-price criteria in renewable auctions. It aims to unlock green willingness-to-pay and scale up manufacturing capacity for net-zero technologies in the European Union (EU). This paper builds a partial equilibrium model of the European solar module sector and investigates how renewable auction design impacts industrial output. First, a formal analysis evaluates the complementarities between the different non-price criteria. Most notably, we find that if local manufacturing development is aligned with climate goals, then non-price criteria in solar auctions do not necessarily increase costs to consumers. Then, a numerical simulation estimates solar module production in 2030 based on NZIA targets, considering various degrees of market integration within the EU. The results show that market fragmentation can inhibit economies of scale and thus increase manufacturing costs by €1.7 billion per year. The development of a common framework for the implementation of non-price criteria at the country level is a no-regret solution. Leveraging the common European market with an integrated policy approach represents the first-best strategy. Forming coalitions of willing Member States is a second-best strategy that can significantly reduce fragmentation costs.

The building sector is central to Switzerland’s decarbonization strategy. To reduce CO2 emissions, a levy on fossil heating fuels was introduced in 2008, increasing operating costs for fossil-heated buildings and aiming to accelerate the transition to renewable heating systems. While the levy applies to both owner-occupied and rental buildings, cost allocation between owners and tenants is more complex in the rental sector. This paper examines whether the 2018 and 2022 CO2 levy increases were capitalized into rental market outcomes and whether they altered the risk–return profiles of owners of fossil-heated rental properties. Using a difference-in-difference framework we compare net rents in newly signed rental contracts between 2016 and 2024 for fossil-heated and non-fossil-heated buildings held by institutional investors. We find no systematic evidence that higher levy-induced operating costs translated into lower net rent growth for fossil-heated dwellings, suggesting that the additional costs were largely borne by tenants rather than capitalized into net rents. However, heterogeneity emerges across rent segments: net rent reductions are concentrated in the middle rent quintiles, while the lowest and highest rent segemtns show no siginificant effects. Using a complementary property-level panel, we further analyze vacancy cost shares to assess changes in property-level risk. Some specifications indicate modest increases in vacancy costs for fossil-heated properties following the levy increases, but these effects are not robust across all model specifications and again vary across rent segments. Overall, the results suggest that the CO2 levy generated limited and segment-dependent short-run financial incentives for property owners to switch heating systems, underscoring the importance of complementary policy instruments to support decarbonization in the Swiss rental housing sector.

The post-2022 energy crisis provides a natural setting to examine whether large demand shocks can generate persistent changes in household energy-use practices. In France, the crisis combined sharp price increases with intense public communication around shortage risks and explicit calls for energy sufficiency. This paper investigates whether the post-2022 decline in residential gas consumption is persistent, widespread, and potentially compatible with sufficiency-type behavior.We use an administrative dataset published by SDES and collected from gas distribution operators (notably GRDF), providing annual residential gas consumption at the IRIS level over 2018–2024. After constructing a balanced panel of approximately 10,870 IRIS correcting consumption for weather fluctuations, we estimate a fixed-effects demand model and build a counterfactual path based on pre-crisis price elasticity. The residual gap between observed and counterfactual consumption is interpreted as a non-price adjustment potentially reflecting persistent behavioral change. We document a significant and persistent post-crisis decline, with the largest reduction in 2023 and continued persistence in 2024. The decline is broadly diffused across territories, yet slighly heterogeneous: larger dwellings exhibit stronger reductions, while homeownership effects weaken once socio-residential controls are introduced. Finally, energy poverty and vulnerability indicators suggest that part of the decline may reflect constrained adjustments rather than voluntary sufficiency, highlighting the importance of integrating distributional considerations into demand-side policies.

Achieving the 2050 net-zero target requires fundamental technology transitions in energy-intensive, hard-to-abate industrial sectors. However, high upfront costs and insufficient market incentives have delayed the diffusion of low-carbon technologies. Despite these real-world constraints, existing climate policy models often treat technology transition as an exogenous and automatic process, oversimplifying industrial and economic dynamics. This study adopts Evolutionary Game Theory (EGT) to bridge this gap between policy design and modeling practice. Focusing on the global steel industry, where hydrogen-based direct reduction (H2-DRI-EAF) represents a promising but costly alternative to conventional blast furnace processes, the study analyzes strategic behavioral changes among agents facing a public goods dilemma in adopting high-cost abatement technologies and identifies policy conditions under which cooperation can be sustained over the long term. The model formalizes strategy dynamics using replicator dynamics and evaluates whether cooperative outcomes are evolutionarily stable (ESS). The results indicate that while high-cost technology adoption faces initial resistance, appropriately designed incentive structures can lead to long-term sustainable cooperation. Major steel-producing countries with large global production shares, such as China, are found to play a systemic role: their early cooperation amplifies learning-by-doing effects and environmental benefits across the system, accelerating transitions in other countries. In contrast, countries with low Social Cost of Carbon (SCC), such as Korea and Germany, lack intrinsic motivation for environmental benefits, and their cooperation levels tend to stagnate without strong policy interventions.