European electricity markets experienced an exceptional stress test in 2021–2023, raising renewed questions about how marginal pricing and the merit‑order mechanism perform under extreme fuel and carbon price shocks. This paper provides a unit‑level empirical assessment of these dynamics for Poland, an electricity system still dominated by coal, with a smaller but growing Combined-Cycle Gas Turbines (CCGTs) fleet and rapidly rising renewables. A transparent short‑run marginal cost (SRMC) model for all centrally dispatched hard‑coal, lignite, and gas‑fired units has been constructed and presented annual merit‑order stacks for 2021–2023. The analysis decomposes SRMC into fuel, transport (hard coal), and EU ETS (Emissions Trading System) components to attribute observed reranking to interpretable cost channels rather than aggregate price movements. The results document a clear crisis‑related reshuffling: record gas prices in 2022 pushed CCGT units markedly rightwards, while the highest‑cost tail remained anchored in the oldest hard‑coal units in all three years. A structured ±25% sensitivity analysis demonstrates robust, technology‑specific exposure profiles: SRMC is fuel‑driven for CCGT, carbon‑driven (EU-ETS) for lignite, and jointly driven by coal and EU ETS costs for hard coal. These results provide a replicable empirical basis for economically coherent phase‑out sequencing and clarify how fossil‑price shocks transmit through marginal pricing to the European electricity market. Policy implications align with the emerging European consensus: maintain marginal pricing for dispatch efficiency, while reducing exposure to fossil‑driven marginality through long‑term contracting, targeted adequacy mechanisms, and accelerated deployment of low‑carbon flexibility
Number 2
ISSN 2160-5890 (Online)
Carbon Capture Technologies for a Decarbonized Energy System –An Update of the Scenario-Reality Gap
In this paper we explore the development of two specific carbon capture technologies, namely Carbon Capture, Transport, and Storage (CCTS) and Direct Air Capture (DAC) with respect to the role attributed to them by long-term climate scenarios. We ask whether the critical assessment in earlier literature of the gap between ambitious targets in top-down energy and climate models and the modest level of real-world implementation still persists. We provide a survey of the full set of projects on CCTS in the energy and industry sectors, as well as of all DAC projects world-wide. For CCTS, we find that although several demonstration projects have been implemented over the past 15 years, the scale of deployment remains low. In the power sector, only a few large-scale projects remain operational as of 2025; others have been delayed or cancelled. Industrial CCTS shows broader engagement, yet most projects remain below the 1 MtCO2 /year threshold. The deployment of DAC, too, has remained at very low levels: While integrated assessment models (e.g., EMF-38 and AR6 scenarios) project deployment of several gigatons per year by 2050, the actual installed DAC capacity in June 2025 remains below 0.05 MtCO2 /year. The paper concludes that while carbon capture remains a compelling field for innovation, the gap between scenario optimism and real-world progress has not closed. This is not the “fault” of the models, but these findings suggest that optimal technology deployment strategies might be more complex to implement than these models suggest.
Demand-Side Flexibility under Alternative Electricity Market Designs: Insights from a Multi-Level Modelling Framework
The transformation of the European electricity system from centralized fossil-based generation to a decentralized renewable-based system poses challenges for the current market design with uniform national price zones. This design lacks spatially differentiated investment signals and market incentives for grid-supportive flexibility behavior. This study examines various market design options—such as bidding zone reconfigurations, capacity payments, and dynamic tariffs—and analyzes their combined effects on investment decisions, dispatch and ex-post congestion management. A multi-level electricity market model is applied to the German power system for the year 2030, incorporating market-driven investments and system operation. Results indicate that a uniform price zone leads to suboptimal investment signals and inefficient deployment of flexibility options. Capacity payments can ensure overall installed capacity levels but fail to provide regional incentives. In contrast, zonal pricing reflects structural congestion and aligns investment incentives with grid information, substantially improving flexibility deployment and reducing congestion. Overall, regional price differentiation emerges as the key driver of efficient investment and system operation, while capacity payments and dynamic tariffs only unfold additional value when combined with such locational signals.
Analysis of Natural Gas and Electricity Load Profiles for the Decarbonisation Strategy of a Commercial Area
The aim of the analysis is to create a database that maps the company-specific energy demand of a commercial area in hourly resolution. The focus is on determining the electricity and heat demand profile of companies in a commercial area using a combination of synthetic and real load profiles. These are necessary to map the heterogeneous energy requirements of industrial and commercial companies in a commercial area as realistically as possible. Due to the limited availability of real consumption data, 323 synthetic electricity and 125 gas load profiles from various studies were used. The comparison shows that synthetic profiles can only reflect the actual requirements of individual companies to a limited extent. However, as the temporal resolution becomes more aggregated and the number of companies increases, the synthetic data approximates the real consumption profile of the entire commercial area. The analysis carried out forms the basis for implementing an energy system model that examines the economic and technical synergies of local energy communities as part of decarbonisation strategies in commercial areas.
Assessing the Economic Impact ofPhotovoltaic Generation on Electricity Pricesand Consumer Economic Benefits underFeed-inTariff System: Evidence from Japan
In this study, the impact of photovoltaic generation on electricity prices and net consumer benefits is evaluated by accounting for the cost of a feed-in tariff system. A structural model is utilized to estimate electricity prices in a counterfactual scenario in which photovoltaics are not generated, and the results are compared with actual prices to evaluate the consumer economic benefits of photovoltaic adoption. To quantitatively estimate the consumer economic benefit, an empirical analysis is performed by using the data on electricity prices, electricity demand, and photovoltaic generation in Japan. The results indicate positive consumer economic benefits owing to the adoption of photovoltaics in recent years, particularly during the summer, which confirms the theoretical prediction that the net economic benefits from photovoltaics increase with increasing electricity demand and difference between photovoltaic generation and the demand. These results offer practical insight for implementing policies that balance renewable energy expansion with economic feasibility. By applying the insights on consumer economic benefits, policymakers could more accurately adjust the feed-in tariff to balance the cost of photovoltaic installation with the consumer burden.
What Underlies the Poor Financial Performance of Electric Utilities in Sub-Saharan Africa?
This study investigates factors responsible for the poor performance of 67 electric utilities in 47 countries in Sub-Saharan Africa (SSA) region using descriptive data available from the World Bank, International Energy Agency, United States Energy Information Administration and national sources. Both cost-and revenue-side factors are found responsible for the poor financial performance of electric utilities in the region. More than two-thirds of vertically integrated utilities (VIUs) and electricity distributional utilities (EDUs) are unable to cover their operational and debt service costs by their revenues. Higher fuel costs (particularly oil), lower capacity factors, lower capital and labor productivity, high transmission and distribution (T & D) losses and leakage in electricity bill collections are found mainly responsible for the poor financial performance. On the other hand, consumers face higher electricity tariffs than in many countries around the world despite their much lower per capita income. The study also investigates how much the reduction of the T&D losses and elimination of the leakages in bill collection improve the financial performance of utilities and finds that out of 25 utilities currently operating in loss, 11 will have higher revenue than their operating costs due to T&D loss reduction and elimination of bill collection leakage. The findings indicate that policymakers in the SSA region should focus on a portfolio of policies, including switching away from expensive generation to emerging cheaper options, improving factor productivities, efficient institutions/governance, reduction of T&D losses, improvement of bill collection and tariff reforms. Policy priority, however, could vary across countries depending on the roles of various factors contributing to the poor financial performance.