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.

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.

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. AB32 established California as the only state with its own cap-and-trade market for greenhouse gas emissions. This market currently sets the nation’s highest price for a ton of greenhouse gas emissions. California recently set a goal of five million electric vehicles in the state by 2030. Under AB 2514, California’s three investor-owned utilities are required to purchase 1,325 megawatts of grid-scale storage capacity and AB 2868 requires them to purchase 500 megawatts of behind-the-meter storage capacity. All of these policies have made California a global leader in the transition to a less carbon-intensive energy sector.

There is one major downside to California’s energy and environmental policies: they are extremely expensive for California consumers. Average residential electricity prices in California are among the highest in the nation—not because it is so expensive to produce electricity in the state, but because the costs of these policies are recovered from retail electricity prices. A comparison to Texas, another large state that also uses natural gas to power most of its electricity generation fleet, illustrates this point. According to the US Energy Information Administration (US-EIA), average residential electricity prices in California are currently about 20 cents per kilowatt-hour (kWh) versus 10 cents per kWh in Texas. However, average wholesale electricity prices in the two states are roughly equal.

This difference in retail prices is primarily due to different policy responses in the two states to the shale gas boom that started in the mid-2000s and ultimately led to a roughly 66 percent decline in the wholesale price of natural gas. California responded to these low natural gas prices with spending on the policies described above and no reductions in retail electricity prices, despite average wholesale electricity prices in California falling by one-half to two-thirds relative to their pre-shale gas boom levels. Texas responded to this decline in natural gas prices by implementing vigorous retail competition for all classes of customers, which passed on the resulting lower wholesale electricity prices into lower retail electricity prices.

What is more surprising about the Texas-versus-California comparison is that over this same time period Texas managed to build more zero-carbon wind and solar generation capacity than California. Texas currently has more than 22,000 megawatts (MWs) of grid-scale wind and solar capacity versus about 17,000 MWs in California. Different from California, Texas has accomplished this massive renewable generation buildout which also produces more renewable energy on an annual basis than California with no state-mandated financial support mechanisms beyond its competitive renewable energy zone (CREZ) policy that proactively expanded the state’s transmission network to regions with significant renewable resources. Texas’s market-based approach to fostering renewable generation entry has led to more capacity at significantly lower cost relative to California’s legislatively mandated and consumer-financed approach.

Because Californians are likely to want to continue to lead the energy transition, the relevant policy design question is: How can the state achieve these low-carbon energy goals in a more cost- effective manner?

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.