We show that the negative demand shock due to the COVID-19 lock-down has reduced net-demand system demand less the amount of energy produced by intermittent renewables and net imports that must be served by controllable generation units. Introducing additional intermittent renewable generation capacity will also reduce the net-demand, which implies the lock-down can provide insights about how electricity markets will perform with a large share of renewable generation capacity. We find that the lock-down induced demand shock in the Italian electricity market has reduced day-ahead market prices by 23 EUR/MWh (-45%) but re-dispatch cost have increased by 9 EUR/MWh (+103%) per MWh of load, both relative to the average to the same magnitude for the same time period in previous years. Relating the actual re-dispatch cost to a non-COVID-19 re-dispatch cost counter-factual derived from a deep-learning model estimated using pre-COVID-19 data yields an increase of 40%. We argue that the difference between these two re-dispatch cost increases can be attributed to the increased opportunities for suppliers with controllable units to exercise market power in the re-dispatch market in these low net-demand conditions. These results imply that an increased intermittent renewable energy share is likely to increase significantly the costs of maintaining a reliable grid because of the low levels of net-demand.

Small businesses are typically committed to providing a positive customer experience and therefore may exhibit a response to dynamic electricity prices different from residential or industrial customers. We conduct a field experiment to determine the extent to which small businesses respond through re-configuration of typical routines throughout the experiment period versus through adjustments to specific dynamic pricing events. Using a customer-level survey of appliance ownership, we estimate the hourly response patterns of individual appliances to participation in the experiment versus individual dynamic pricing events. Consistent with our re-configuration hypothesis, small businesses primarily curtail electricity usage throughout the experiment period, although we also find a small imprecisely estimated response to dynamic pricing events on top of the re-configuration effect. Appliances not critical to a positive customer experience such as dish dryers, food storage units, lights, electric motors & pumps, and industrial heaters are the major sources of the energy savings from the re-configuration actions of these small businesses.

We report on an economic experiment that compares outcomes in electricity markets subject to carbon-tax and cap-and-trade policies. Under conditions of uncertainty, price-based and quantity-based policy instruments cannot be truly equivalent, so we compared three matched carbon-tax/cap-and-trade pairs with equivalent emissions targets, mean emissions, and mean carbon prices, respectively. Across these matched pairs, the cap-and-trade mechanism produced much higher wholesale electricity prices (38.5% to 52.6% higher) and lower total electricity production (2.5% to 4.0% lower) than the \equivalent" carbon tax, without any lower carbon emissions. Market participants who forecast a lower price of carbon in the cap-and-trade games ran their units more than those who forecast a higher price of carbon, which caused emissions from the dirtiest generating units (Coal and Gas Peakers) to be signicantly higher (15.2% to 33.0%) than in the carbon tax games. These merit order \mistakes" in the cap-and-trade games suggest an important advantage of the carbon tax as policy: namely, that the cost of carbon can treated by rms as a known input to production.

If regulators and utilities want to avoid future consumer backlash from smart grid investments, they should adopt retail pricing policies best suited to maximizing the consumer benefits from smart grid technologies.

The desire to "reboot" the New Zealand electricity supply industry is understandable, but it is almost certainly not the best course of action. As a participant in many electricity industry restructuring processes around the world, one important lesson that I have learned is that all reforms start with significant unintended defects that can only be eliminated through a rigorous ongoing analysis of market outcomes and targeted regulatory reforms.  

Many features of the current industry are consistent with international best-practice and a number of positive changes have been implemented since I completed my report for the Commerce Commission in 2009.

Continuing these efforts to identify and fix flaws in the existing market is likely to provide greater long-term benefits than undertaking a major restructuring of the industry.

Last week, Stanford's Board of Trustees announced that the university would not directly invest funds from its endowment in coal mining companies.  Even the strongest advocates of this action acknowledge that it is a symbolic gesture with little direct effect on the coal industry or global greenhouse gas emissions.  But if a university administration wants to take symbolic (or real) action on climate change, is coal investment a wise choice?

This paper identifies the major political and economic constraints that impact the demandside 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.

This report points out a number of aspects of the existing electricity market design in Colombia that could be contributing to the periods of high short-term prices observed several times since early December of 2008. These issues are classified into four broad categories: (1) system-wide market power issues, (2) local market power issues, (3) market monitoring issues, and (4) broader electricity market issues.

This report proposes an ancillary services payment mechanism for the Chilean electricity supply industry. This is accomplished in three steps. The first section presents a set of economic principles for assessing the likely performance of candidate ancillary services payment mechanisms in the context of Chilean electricity supply industry. The second section uses this framework to assess the likely performance of the ancillary services payment mechanism recently proposed by the National Energy Commission (NEC) in its letter Number 715 dated September 21, 2010. The third section formulates an alternative payment mechanism that respects the existing electricity market structures and rules in Chile, but is likely to provide lower cost and more reliable solution than the one proposed by the NEC. An appendix outlines several examples of how the proposed procurement mechanism could be implemented and how potential exercise of market power by a dominant supplier of any ancillary service could be mitigated.