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A Least-Cost optimisation Model of Co2 Capture Applied to Major uK Power Plants Within The Eu-ETS Framework

A.G. Kemp and A.S. Kasim

Year: 2008
Volume: Volume 29
Number: Special Issue
DOI: 10.5547/ISSN0195-6574-EJ-Vol29-NoSI-7
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Abstract:
Concerns about the cost of CO2 capture and sequestration, and the effective�ness of carbon abatement policies loom large in discussions on climate change mitiga�tion. Several writers address the issue from various perspectives. This paper attempts to add relative realism to discussions on CO2 capture costs, and, the deployment of carbon capture technology in the UK by using publicly available company data on the long term capacity expansion and CO2 capture investment programmes of selected power plants in the UK. With an estimated �8 billion plan to install a generation ca�pacity of 11 GW and capture capability of 44 MtCO2/year, it is imperative to optimise this huge potential investment. A least-cost optimisation model was formulated and solved with the LP algorithm available in GAMS. The model was then applied to ad�dress a number of issues, including the choice of an optimal carbon abatement policy within the EU-ETS framework. The major findings of the study include (a) the long term total cost curve of CO2 capture has three phases � rising, plateau, rising; (b) alternative capture technologies do not have permanent relative cost advantages or disadvantages; (c) Government incentives encourage carbon capture and the avoid�ance of emission penalty charges; and (d) the goals of EU-ETS are more effectively realised with deeper cuts in the EUA ratios than merely hiking the emission penalty, as proposed in EU-ETS Phase II.



The Profitability of Energy Storage in European Electricity Markets

Petr Spodniak, Valentin Bertsch, and Mel Devine

Year: 2021
Volume: Volume 42
Number: Number 5
DOI: 10.5547/01956574.42.5.pspo
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Abstract:
In this work, we study the profitability of energy storage operated in the Nordic, German, and UK electricity day-ahead markets during 2006–2016. During this time period, variable renewable energy sources (vRES) have been rapidly penetrating the markets and increasing the volatility of the residual load, which is often assumed to be associated with improving financial viability of energy storages. However, storage operator profits are not publicly available, in particular not at plant level. We therefore develop a linear optimisation model which maximises profits from arbitraging hourly prices and use the model output of profits and storage operating hours in further econometric analyses. This is a novel approach merging two strands of literature (optimisation and econometrics) in a single energy storage study. Specifically, we quantify and disentangle the effects of electricity demand, solar and wind generation, the spread between gas and coal prices, carbon emission prices and structural breaks on profits and operation of 1–13MWh/MW energy storages. Among others we find that solar generation is associated with lower profits but higher operating frequency of energy storages in Germany. Wind power generation is associated with positive effects on profits in the UK and Germany. vRES does not affect profits or operation of new Nordic energy storages.



Offshore Market Design in Integrated Energy systems: A Case Study on the North Sea Region towards 2050

Juan Gea-Bermúdez, Lena Kitzing, and Dogan Keles

Year: 2024
Volume: Volume 45
Number: Number 4
DOI: 10.5547/01956574.45.4.jgea
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Abstract:
Offshore grids, with multiple interacting transmission and generation units connecting to the shores of several countries, are expected to have an important role in the cost-effective energy transition. Such massive new infrastructure expanding into a new physical space will require new offshore energy market designs. Decisions on these designs today will influence the overall value potential of offshore grids in the future. This paper investigates different possible market configurations and their impacts on operational costs and required congestion management, as well as prices and emissions. We use advanced integrated energy system optimisation, applied to a study case on the North Sea region towards 2050. Our analysis confirms the well-known concept of nodal pricing as the most preferable market configuration. Nodal pricing minimises costs (0.2-1.6 b€/year lower) and CO2 emissions (0.6-5.6 Mton/year lower) with respect to alternative market designs investigated. The performance of the different market designs is highly influenced by the overall architecture of the offshore grid, and the rest of the energy system. E.g., flexibility options help reducing the spread between the designs. But the results are robust: nodal pricing in offshore grids emerges as the preferable market configuration for a cost-effective energy transition to carbon neutrality.





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