Suchergebnisse

Hourly generation unit-level output levels, detailed information on the technological characteristics of generation units, and daily delivered natural gas prices to all generation units for the California wholesale electricity market before and after the implementation of locational marginal pricing are used to measure the impact of introducing greater spatial granularity in short-term energy pricing. The average hourly number of generation unit starts increases, but both the total hourly energy consumed and total hourly operating costs for all natural gas-fired generation units fall by more than 2 percent after the implementation of locational marginal pricing.

This paper uses the results of a dynamic pricing experiment for households in the District of Columbia to determine whether the reduction in demand associated with an hourly price signal is economically different from the demand reduction associated with an equivalent price signal that is four times longer in duration. For both regular and all-electric customers, the percentage demand reduction associated with a given percentage increase in the hourly price is approximately equal to the percentage demand reduction associated with the same percentage price increase of a much longer duration.

This paper identifies the major political and economic constraints that impact the demand-side of electricity industry re-structuring processes. It then describes how these constraints have been addressed and how this has harmed market efficiency and system reliability. Finally, the paper proposes demand-side regulatory interventions to manage these constraints in a manner that limits the harm to wholesale market efficiency.

Alberta's electricity system is in transition. From a system dominated by coal generation less than a decade ago, Alberta's electricity is now largely supplied by natural gas generation with an increasing share of variable wind and solar energy. Falling clean technology costs, federal clean electricity regulations and a rising carbon price will further shift Alberta's supply mix away from unabated fossil fuels into one more reliant on a mix of renewables and new technologies, such as carbon-captured natural gas, small modular nuclear reactors and hydrogen generation.
In this report, we consider future market designs fit for purpose for this changing electricity mix. We assess market design options based on the criteria of reliability, affordability, investor confidence and complexity. At the heart of the matter is the question of which approach is best able to deliver reliable and low emission supply at low cost to Alberta consumers.
Importantly, we consider market designs suitable for the changing nature of 21st century grids with more variability on the supply side and more flexibility on the demand side. If the grid of the past involved forecasting demand and dispatching supply, increasingly grids of the future will flip this upside down by forecasting supply and dispatching demand. Alberta's market design needs to both reflect and enable this new reality.