This study quantifies the economic and environmental impacts associated with the change from a zonal to nodal design in the Texas electricity market. To begin, we present a framework to understand the mechanisms that lead to inefficient outcomes under a zonal market model. Then, we estimate a semiparametric partially linear conditional mean function to quantify changes in selected market metrics for the same set of underlying system conditions after versus before the implementation of the nodal market design.
Electricity retailing is at a crossroads. Technological change is eroding revenues from the traditional electricity retailing business model. However, many of these new technologies have the potential to create new products and revenue streams for electricity retailers. We assess the future of electricity retailing under two possible approaches by policymakers and regulators to addressing these challenges and new opportunities: a reactive approach and a forward-looking approach.
The basic features of an efficient short-term wholesale market design do not need to change to accommodate a significantly larger share of zero marginal cost intermittent renewable energy from wind and solar resources. A large share of controllable zero marginal cost generation does not create any additional market design challenge relative to a market with a large share of controllable positive marginal cost generation. In both instances, generation unit owners must recover their fixed costs from sales of energy, ancillary services, and long-term resource adequacy products.
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 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.
Californians like to think of themselves as environmentally conscious and forward-thinking. The state’s energy and environmental policies reflect these sentiments. With the passage of SB 100, California has one of the nation’s most ambitious renewable energy goals for its electricity supply industry. The California Solar Initiative rebate program has led to more rooftop solar capacity in the state than the total rooftop solar capacity installed in the next eight highest-capacity states.
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.
An increasing number of wholesale electricity markets employ locational pricing mechanisms where energy prices account for some or all aspects of the transmission network configuration. A major concern of regulators is that suppliers may have the ability to exercise unilateral market power by impacting the extent to which transmission constraints bind. We extend the residual demand curve as a measure of the ability to exercise unilateral market power from a single price market to residual demand hypersurfaces in locational pricing markets.
We extend the competitive benchmark pricing model of Borenstein et al. (2002) to locational-pricing markets. We further extent this model to account for transmission network security constraints as well as technical constraints on thermal power plants that introduce non-convexities in their operating cost functions. We apply both models to assess the performance of the Italian wholesale electricity market for the year 2018.
Electricity tariff reforms will be an essential part of the clean energy transition. Existing tariffs rely on average cost pricing and often set a price per unit that exceeds marginal cost. The higher price encourages over-adoption of residential solar panels and under-adoption of electric alternatives to fossil fuels. However, an efficient tariff based on fixed charges and marginal cost pricing may harm low-income households. We propose an alternative methodology for setting fixed charges based on the predicted willingness-to-pay of each household.
The electricity supply industry in a low-carbon world will have over 50 percent share of intermittent renewables. This large share of intermittent renewables will require investments in both grid-scale and distributed storage, active demand-side participation by customers, and automated distribution network monitoring and on-site load-shifting technologies. Market design should support business models that lead to adoption of these pricing policies and technologies.
Using hourly offer curves for the Italian day-ahead market and the real-time re-dispatch market for the period January 1, 2017 to December 31, 2018, we show how thermal generation unit owners attempt to profit from differences between a simplified day- ahead market design that ignores system security constraints as well as generation unit operating constraints, and real-time system operation where these constraints must be respected.
The variability of solar and wind generation increases transmission network operating costs associated with maintaining system stability. These ancillary services costs are likely to increase as a share of total energy costs in regions with ambitious renewable energy targets. We examine how ecient deployment of intermittent renewable generation capacity across locations depends on the costs of balancing real-time system demand and supply.
Wholesale electricity market design requires an explicit regulatory process to set the market rules for compensating and charging market participants for their actions. This has led to market designs tailored to the initial conditions in the industry and the political forces driving the restructuring process in that region. The experience of the past 25 years with wholesale market design has led to increasing standardization, particularly within the United States and within Europe. This paper identifies the key features of successful electricity market designs.
The different incentives generation unit owners face for locating and operating their units in the wholesale market regime versus the vertically-integrated monopoly regime has wide-ranging implications for the design and operation of the transmission network in the two regimes. This logic implies different measures of grid reliability in the two regimes—engineering reliability in the vertically-integrated monopoly regime and economic reliability in the wholesale market regimes.