Event Debrief: The Future of Resource Adequacy in a Decarbonized Grid

Key Takeaways

• Concerns over resource adequacy during periods of peak demand or supply crises are rising with increasing deployment of renewable energy.
• Resource adequacy is a function of electricity markets, which contain both market-oriented and centralized planning elements. Marginal pricing in energy markets remains the optimal operational and investment signal.
• Managing price volatility for risk-averse investors and consumers is even more important in a decarbonized grid. This can be done through capacity markets or centralized procurement, but these have downsides.
• Mandatory forward market contracts, which already exist in certain circumstances and markets, could be a "close-to" first-best market solution that can help resolve resource adequacy challenges driven by the energy transition, including: reliability, cost to consumers, and accelerating construction of new generation capacity.

To achieve net-zero emissions goals, the world needs an estimated two to three times the amount of electricity generation in 2050 that we have today. So says Conleigh Byers, Environmental Fellow at the Harvard University Center for the Environment and Belfer Center for Science and International Affairs, echoing similar warnings given by other speakers in the Harvard Kennedy School’s ongoing Energy Policy Seminar. Byers’ current research focuses on power system resource adequacy in a decarbonized future. One of the most important aspects of grid reliability, resource adequacy is defined as the ability of a power system to supply enough electricity—at the right locations—to keep the lights on during all hours of the year, measured at a system level as the probability of an outage. As electrification increases overall power demand and increasingly distributed, varied, and intermittent renewable power sources come online, maintaining resource adequacy has become a greater challenge. With this in mind, Byers posed a rhetorical question to the audience: “is our current system design up for the challenge of a decarbonized world?” Her answer was a resounding “no.”  

Pointing to the Texas blackouts in the 2021 freeze, the recent suspension of the electricity market in Australia, and the price shocks affecting European consumers in the wake of Russia’s invasion of Ukraine, Byers noted that the tension between market outcomes and central planning has been heightened as a result of the strains placed on a resource-strapped power grid. With over 1,250 GW of zero-carbon generating capacity seeking access to power grids in the United States and wait times increasing every year, the interconnection backlog further challenges resource adequacy.

According to Byers, one result of the ongoing transition from fossil fuels to renewables is the transformation of the energy system from a capacity-limited paradigm (in which the question was how much thermal power generation to build to keep up with demand) to a variable, “energy-limited” paradigm complicated by the availability of intermittent generation, treating demand as fixed instead of flexible, and transmission constraints. To Byers, short-term markets are insufficient for protecting long-term resource adequacy, due to problems with reliability, cost, and need to build new generation capacity quickly. This is further complicated by zero-variable cost resources, the need for storage, and incentivizing risk-adverse investors, consumers, and system operators. As a result, Byers proposes a mandatory forward market model in lieu of traditional capacity markets or centralized procurement as a way to ensure long-term resource adequacy.

Forward contracts are customized contracts between two parties to buy or sell an asset at a specified price on a future date. Long-term forward contracting in power markets, which “contracts for energy rather than capacity,” can better incentivize reliability by providing a financial penalty for resources that fail to deliver. It reduces the need for long deliverable capacity studies that are mandatory in capacity markets and delay approvals, and hedges against volatility in “full-strength prices,” providing less expensive financing and protecting consumers from high prices. 

Given all these benefits, why isn’t there more forward contracting? Byers notes that many producers are willing to sign long-term power purchase agreements (PPAs), a form of long-term contracts for energy supply, but many load-serving entities and retail customers aren’t. Byers ascribes this reluctance to externalities: reliability is in part a common good, and consumers are insufficiently incentivized to pay for it. To address this problem, a few markets have made forward contracts mandatory. In New Jersey, the Board of Public Utilities designed the New Jersey Basic Generation Service (BGS), a default forward contract system for power that retail customers can opt out of, providing ex-post load hedging but no marginal incentives for flexible demand. In Australia, the Australian Energy Market Operator implemented a Retailer Reliability Obligation (RRO) that centralizes contracting for additional future power supply if there is an expected shortfall.

Several policy questions arise when one considers implementing such schemes more broadly. While a first-best solution would be to have each consumer voluntarily contract for its optimal quantity, with deviations then bought and sold on the spot market, what fixed quantities should be required for consumers to buy? Should it be based on ex-ante estimates, ex-post selection, percentage load share, or some other mechanism? Should this be mandatory for everyone, or only small consumers, because large consumers are assumed to be better able to find an optimal hedge? Which market price should be used – the day-ahead market price or the real-time market?

Acknowledging these challenges, Byers proposed a “close-to first best market solution” that would combine elements of locational marginal pricing and day-ahead markets with virtual transactions (but without capacity markets), plus ERCOT-style scarcity pricing, and elements of a New Jersey BGS-style consumer hedging approach. An alternative to this approach could be to leverage a fully centralized integrated resource planning approach, which would sacrifice efficiency derived from market signals and risk getting estimates wrong. A hybrid approach, in which short-term markets are kept largely as they are to preserve some market competition, would combine this market competition with competition for the market, with governments offering competitive tenders and entering long-term contracts. Relying on markets instead of central planning may complicate the timing of company entries and exits, taking decades to reach a new market equilibrium. Without a carbon market, this also runs the risk of only incrementally procuring clean energy when a rapid transition is needed.  

Byers is continuing to mull over these implementation challenges and tradeoffs, investigating how mandatory forward contracts compare with capacity markets on reliability during worst-case scenarios, how they might change the endogenous cost of capital, how to preserve marginal incentives while still hedging against high prices, and what the impact of subsidies could be on investor risk under mandatory forward contracting schemes. Despite these lingering questions, Byers demonstrated that mandatory forward contracting, in some form, is worth considering as a potential market model to ensure resource adequacy and speed up renewable energy deployment.