Charging full requirements customers for distribution network services using the traditional cents per kilowatt-hour (KWh) price creates economic incentives for consumers to invest in distributed generation technologies, such as rooftop solar photovoltaics, despite the fact that marginal cost of grid-supplied electricity is lower. This paper first assesses the economic efficiency properties of this approach to transmission and distribution network pricing and whether current approach to distribution network pricing implies that full-requirement customers cross-subsidize distributed solar customers. Using data on quarterly residential distribution network prices and distributed solar installations from California’s three largest investor-owned utilities I find that larger amounts of distributed solar capacity and more geographically concentrated solar capacity predict higher distribution network prices and average distribution network costs. This result continues to hold even after controlling for average distribution network costs for the utility, Using these econometric model estimates, I find that 2/3 of the increase in residential distribution network prices for each of the three utilities between 2003 and 2016 can attributed to the growth distributed solar capacity. The paper then investigates the extent of the legal obligation that distributed solar generation customers have to pay for sunk costs of investments in the transmission and distribution networks. The paper closes with a description of an alternative approach to distribution network pricing that is likely to increase the economic signals for efficient electricity consumption and the incentive for cost effective installation of distributed solar generation capacity.

Economists traditionally argue that forward commodity markets allow more efficient risk-sharing and information aggregation. However, there is little empirical evidence that commodity markets provide economic benefits to producers and consumers of the commodity. This paper demonstrates that the introduction of financial trading to California’s electricity market on February 1st, 2011 improved price discovery and lowered production costs. Specifically, we document that the average, standard deviation and maximum of the differences between day-ahead and real-time electricity prices across California fell after 2/1/2011. Moreover, variable input costs (input energy) per MWh fell by 3% (4%) in high demand hours after 2/1/2011.

We report results from a large field experiment that with a few hours prior notice provided Danish residential consumers with dynamic price and environmental signals aimed at causing them to shift their consumption either into or away from certain hours of the day. The same marginal price signal is found to cause substantially larger consumption shifts into target hours compared to consumption shifts away from target hours. Consumption is also reduced in the hours of the day before and after these into target hours and there is weaker evidence of increased consumption in the hours surrounding away target hours. The same into versus away results hold for the environmental signals, although the absolute size of the eects are smaller. Using detailed household-level demographic information for all customers invited to participate in the experiment, both models are re-estimated accounting for this decision. For both the price and environmental treatments, the same qualitative results are obtained, but with uniformly smaller quantitative magnitudes. These selection-corrected estimates are used to perform a counterfactual experiment where all of the retailer’s residential customers are assumed to face these dynamic price signals. We find substantial wholesale energy cost savings for the retailer from declaring into events designed to shift consumption from high demand periods to low demand perio ds within the day, which suggests that such a pricing strategy could significantly reduce the cost of increasing the share of greenhouse gas free wind and solar electricity production in an electricity supply industry.

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 show that accounting for the fact that firms face residuai demand surfaces improves our ability to explain the offer curves submit­ted by strategie suppliers. A supplier's residuai demand surface also explains why the location of a firm's capacity is an important factor in analyzing the extent to which divestment of generation capacity or a transmission network expansion ultimately ben­efits final consumers. 

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. Hourly competitive benchmark locational prices that ignore the impact of non-convexities in generation unit operation fail to provide credible estimates for the intra-day benchmark price profile. Augmenting the model to account for transmission network security constraints and non-convexities resolves this issue. We find that the average day-ahead market-clearing prices throughout the day are close to average com­petitive benchmark prices throughout the day during 2018. However, accounting for the cost of the re-dispatch market that makes final schedules from the day-ahead finan­cial market physically feasible, raises the average hourly cost of serving demand. Our preferred competitive benchmark pricing model implies annual market inefficiencies in the range of 1 to 2 billion Euros in the actual annual cost of serving load in 2018 in ltaly. 

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?