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. We find that thermal generation unit owners increase or decrease their day- ahead offer price depending on the probability that their final output will be increased or decreased because of real-time operating constraints. We estimate generation unit- level models of the probability of each of these outcomes conditional on forecast demand and renewable production in Italy and neighbouring countries. Our most conservative estimate implies an offer price increase of 50 EUR/MWh if the predicted probability of day-ahead market schedule increases from zero to one. If the predicted probability of a day-ahead market schedule increases from zero to one the unit owner’s offer price is predicted to be 60 EUR/MWh less. We find that these re-dispatch costs averaged approximately nine percent of the cost of wholesale energy consumed valued at the day-ahead price during our sample period.

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. These include: (1) the match between the short-term market used to dispatch generation units and the physical operation of electricity network, (2) effective regulatory and market mechanisms to ensure long-term generation resource adequacy, (3) appropriate mechanisms to mitigate local market power, and (4) mechanisms to allow the active involvement of final demand in the short- term market. This is followed by a discussion of how these lessons can be applied to developing countries and small markets, so that these regions can benefit from wholesale electricity competition at lower cost and with less administrative burden than larger markets. Market design enhancements that support the cost effective integration of both grid-scale and distributed renewables is briefly discussed. The paper closes with proposed directions for future research in the area of electricity market design.

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. Because of the different planning criteria in the two regimes, the economically efficient choice of transmission capacity in the wholesale market regime is generally greater than that in the vertically-integrated monopoly regime. A number of arguments are presented for why the transmission planning and regulatory process for the wholesale market regime requires substantially more engineering and economic modeling sophistication than is required in the vertically-integrated monopoly regime. A forward-looking framework is proposed for evaluating transmission network expansions in the wholesale market regime. This includes a general methodology for computing the distribution of realized economic benefits from an upgrade in the wholesale market regime. How the measurement of the economic benefits of transmission expansions to support the deployment of renewable resources differs between the wholesale market regime and vertically-integrated monopoly regime is also discussed.

We investigate the relationship between accumulated experience completing wind power projects and the cost of installing wind projects in the U.S. from 2001-2015. Our modeling framework disentangles accumulated experience from input price changes, scale economies, and exogenous technical change; and accounts for both firm-specific and industry-wide accumulated experience. We find evidence consistent with cost-reducing benefits from firm-specific experience for that firm’s cost of future wind power projects, but no evidence of industry-wide learning from the experience of other participants in the industry. Further, our experience measure rapidly depreciates across time and distance, suggesting a stable industry trajectory would lower project costs.

This paper identifies the key features of successful electricity market designs that are particularly relevant to the experience of low-income countries. Important features include: (1) the match between the short-term market used to dispatch generation units and the physical operation of the electricity network, (2) effective regulatory and market mechanisms to ensure long-term generation resource adequacy, (3) appropriate mechanisms to mitigate local market power, and (4) mechanisms to allow the active involvement of final demand in a short-term market. The paper provides a recommended baseline market design that reflects the experience of the past 25 years
with electricity restructuring processes. It then suggests a simplified version of this market design ideally suited to the proposed East and Western Sub-Sahara Africa regional wholesale market that is likely to realise a substantial amount of the economic benefits from forming a regional market with minimal implementation cost and regulatory burden. Recommendations are also provided for modifying the Southern African Power Pool to increase the economic benefits realised from its formation. How this market design supports the cost-effective integration of renewables is discussed and future enhancements are proposed that support the integration of a greater share
of intermittent renewables. The paper closes with proposed directions for future research in the area of electricity market design in developing countries.

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.  The policy question is what long-term resource adequacy mechanism will facilitate a least-cost transition to this future electricity supply industry with these pricing policies and technologies?

This report provides recommendations on the six topic areas in the transformation and modernization theme “Competition, participation and structure of the electricity market.” These are: (1) investment, reliability charges, and contracts; (2) generation diversification, of Non-Conventional Renewable Energy Sources (NCRES) and greater number of agents; (3) new services and agents: storage systems and aggregators; (4) restrictions, nodal prices and infrastructure; (5) market structure; and (6) pathways to de-carbonization and implications for market design. These recommendations are aimed at enhancing the efficiency of the short-term electricity market design and the long-term resource adequacy process in Colombia. They also provide policy pathways for the government of Colombia to support the deployment of NCRES, the entry of new market participants and technologies, and the active participation of final consumers in the wholesale market in manner that increase the competitiveness of wholesale and retail market outcomes.

California’s decision to allow Pacific Gas and Electric (PG&E) to shut off electricity to hundreds of thousands of Californians because high winds and dry conditions may cause a downed powerline to start a wildfire is a third-world solution to a first-world problem.