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.
PESD Associate Director Mark Thurber co-authored a new paper in The Electricity Journal on the electricity grid improvements that are needed to unlock the full potential of wind and solar energy in Africa. Donors and development agencies need to devote more attention to these missing pieces, rather than assuming that bans on fossil fuel financing alone will spur the desired transition to cleaner energy.
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.
The Biden administration has pledged to reduce US greenhouse gas emissions to half of 2005 levels by 2030. A large share of these reductions would have to come from the power sector, with high-emitting coal-fired power plants being obvious targets for closure. Program on Energy and Sustainable Development (PESD) Associate Director Mark Thurber spoke on NPR's Here & Now about why phasing out coal-fired generation in the US by 2030 is an achievable goal -- and how we need to take care of affected workers along the way. Listen to the interview.
Stanford's Program on Energy and Sustainable Development (PESD) is collaborating with the California Public Utilities Commissions (CPUC) on an Impact Lab that tackles an urgent policy question: How do we make sure the lights stay on as the electricity mix climbs towards state targets of 50% renewable energy in 2026 and 60% in 2030? Wind and solar are essential zero-carbon energy sources, but they are only available when the wind blows and the sun shines. Blackouts in Northern California last August were a warning that system reliability is at risk if the state doesn't act quickly to implement policies that ensure backup generation is available when needed.
The existing regulatory instrument for ensuring long-term resource adequacy, capacity payments, is not well-adapted to a high-renewables future. Capacity payments aim to ensure enough "firm capacity" is always available to keep the lights on, but the firm capacity construct is not applicable to wind and solar, which cannot be turned on and increased at the system operator’s discretion.
The PESD/CPUC Impact Lab has proposed an alternative resource adequacy mechanism that is robust to a world of high and solar generation: auctions of Standardized Fixed-Price Forward Contracts (SFPFCs) that ensure every megawatt-hour of energy consumed in the state is hedged through long-term financial contracts. Unlike capacity payments, the SFPFCs provide a strong financial incentive for generators to meet their commitments to supply reliable energy wherever and whenever it is needed. PESD research suggests this novel policy mechanism can provide enhanced reliability and major cost savings relative to the capacity payment approach.
The CPUC has initiated a stakeholder process to consider possible implementation of this proposal, and PESD is assisting with research, policy outreach, and development of market simulation games that will allow stakeholders to gain hands-on experience with how the SFPFC mechanism would work in a realistic electricity market.