Evaluating the cost of emissions in a pool-based electricity market. (15th September 2021) - Andrianesis, Panagiotis; Biskas, Pandelis; Liberopoulos, George
Highlights: Mid-term generation scheduling, with energy offers internalizing emissions cost. Scenarios with respect to gas/carbon prices and outage realization. Impact of emission cost on electricity price and generation scheduling. Instance of the Greek electricity market during EU ETS Phase III. Average pass through rates onto demand-side payments close to 60%. Abstract: This paper proposes a methodology that quantifies the impact of emissions cost on the electricity price, the generation scheduling outcome, and the overall emissions in a pool-based electricity market. It employs a mid-term (yearly) generation scheduling model, by sequentially solving a Day-Ahead Scheduling problem, in which power plants internalize their emissions cost in the energy offers that they submit to the day-ahead market. It further explores several scenarios with respect to gas and carbon prices, as well as the realization of random outages that affect the availability of the generation units. An illustration on an instance of the Greek electricity market during the European Union Emissions Trading Scheme Phase III indicates that: (i) A carbon price equal to 30 €/tCO2e combined with low gas prices results in a 18.7% reduction of CO2 emissions, due to the substitution of lignite units by gas units in the energy generation mix. (ii) An increase in the carbon price by 1 €/tCO2e results in an increase of the weighted average electricity price ranging from 0.52 to 0.61 €/MWh. (iii) The average pass-through rate of the carbon costs onto the demand-side payments for carbon prices up to 15 €/tCO2e is close to 60%.