High and growing shares of wind and solar generation can lead to economic retirements of controllable capacity, which creates the need for long-term resource adequacy mechanisms that compensate units needed to maintain system reliability. We use game-based simulation to compare two approaches for ensuring long-term resource adequacy: capacity markets and forward contracting. We also conduct “policy prototyping” of a specific implementation of forward contracting, Standardized Fixed-Price Forward Contracts (SFPFCs). SFPFCs are standardized forward energy products sold through a centralized procurement process in which 100% of expected demand is auctioned off several years ahead of energy delivery. SFPFCs retroactively adjust contract quantities in each covered hour according to that hour’s share of total demand in the compliance period. This encourages generating companies to manage the risk of higher-than-expected demand in any given hour. Our game runs suggest that forward contracting can yield significantly lower cost to load than capacity markets because it removes the incentive for gencos to exercise unilateral market power in the short-term energy market. The SFPFC implementation in our games effectively maintained system reliability and delivered moderate costs to consumers while maintaining financial viability for gencos. It did this even in scenarios with high carbon prices and high renewable shares incentivized by a Renewable Portfolio Standard (RPS) with tradable Renewable Energy Certificates (RECs).

High and growing shares of wind and solar generation can lead to economic retirements of controllable capacity, creating the need for long-term resource adequacy mechanisms that compensate units needed to maintain system reliability. We use game-based simulation to compare two approaches for ensuring long-term resource adequacy: capacity markets and forward contracting. We also conduct “policy prototyping” of a specific implementation of forward contracting, Standardized Fixed-Price Forward Contracts (SFPFCs). SFPFCs are standardized contract products sold through a standardized procurement process in which 100% of expected demand is auctioned off several years ahead of energy delivery. SFPFCs retroactively adjust contract quantities in each covered hour according to that hour’s share of total demand in the compliance period, thereby encouraging generating companies to manage the risk of higher-than expected demand in any given hour. Our game runs suggest that forward contracting can yield significantly lower cost to load than capacity markets because it removes the incentive for gencos to exercise unilateral market power in the short-term energy market. In our games, the SFPFC implementation proved effective at safeguarding system reliability and delivering moderate costs to consumers while maintaining financial viability for gencos, even in scenarios with high carbon prices and high renewable shares incentivized by a Renewable Portfolio Standard (RPS) with tradable Renewable Energy Certificates (RECs). Game-based policy prototyping encouraged us to revise our SFPFC proposal to eliminate one policy element, the “true-up auction,” that proved to be of secondary importance.

Declines in the up-front costs of both wind and solar generation units over the past decide has significantly closed the gap between the levelized cost of energy (LCOE) for these resources and the LCOE of natural gas and coal-fired generation. This outcome has the potential to reduce the cost of increasing the share of intermittent renewable resources in a region significantly. The experience of regions with significant shares of intermittent renewables is used to provide recommendations for short-term wholesale market design, a long-term resource adequacy mechanism and a renewables support mechanism to achieve a substantial intermittent renewable energy share at least cost to electricity consumers. A multi-settlement locational marginal pricing short-term market design, a standardardized fixed-price forward contract approach to long-term resource adequacy and a renewables energy certificates market are the major market design elements proposed to achieve this goal.

We estimate the relationship between distributed generation investments and hourly net injections to the distribution grid across over 2,000 substations in France between 2005 and 2018. A 1 MW increase in solar PV capacity has no statistically significant impact on the highest percentiles of the annual distribution of hourly net of injections to the distribution grid. A 1 MW increase in wind capacity is predicted to reduce the 99th percentile of the annual distribution of hourly net injections to the distribution grid by 0.037 MWh. In contrast, a 1 MW investment in a distributed small hydro, non-renewable thermal, or renewable thermal generation unit predicts an almost five times larger MWh reduction in the 99th percentile of the annual distribution of hourly net injections to the distribution grid. A 1 MW investment in distributed solar PV or wind capacity predicts substantial absolute changes in both extremes of the annual distribution of hourly ramp rates of net injections to the distribution grid. For the remaining three distributed generation technologies, a 1 MW capacity increase does not predict a non-zero change in any percentile of the annual distribution of hourly ramp rates of net injections to the distribution grid. These results argue that, at least for the case of France, increases in distributed solar and wind capacity are more likely to lead to increases, rather than decreases, in distribution network investments.

Falling costs of wind and solar have encouraged development agencies and multilateral lenders to restrict financing for new fossil fuel developments. But African countries face significant obstacles to the grid integration of high shares of intermittent renewable energy. Donors that are genuinely interested in renewable development in Africa should invest in grid operator capability and transmission interconnection while remaining supportive of a range of technologies for dispatchable backup.

Market power has been a persistent challenge in designing wholesale electricity markets. Differences in the number or configuration of pricing zones does not impact the ability of a supplier to exercise unilateral market, but only what market outcomes are impacted by this exercise of market power. For this reason, tools able to detect market power conditions are crucial for ensuring the well functioning of all wholesale electricity markets, regardless of number of pricing zones. We first describe the trade-offs that must be balanced in designing a market power mitigation mechanism for any short- term wholesale electricity market. This is followed by a survey of the market power mitigation mechanisms that currently exist in the California Independent System Operator (ISO), the PJM Interconnection, the New York ISO, Mid-Continent ISO, and Electricity Reliability Council of Texas (ERCOT). Finally, we draw lessons from the US experience and try to address potential issues in the adoption of a market power mitigation mechanism in a low carbon electricity market.