The following is a contributed article by Fritz Kahrl, director of research and international consulting at Energy and Environmental Economics.
There has been much fretting of late surrounding the viability of existing electricity markets in a future dominated by solar and wind energy. But these concerns, at least in the U.S., are misplaced. With moderate tinkering, existing independent system operator-run markets can support very low emission electricity systems that rely primarily on solar and wind energy.
Outside of perhaps Texas, the U.S. has never had "pure" electricity markets. Regulated utilities sell around 50% of our electricity and publicly-owned utilities and cooperatives account for nearly 30%.
In most states that allow retail choice, regulated utilities provide default service and regulators inadvertently shape long-run market outcomes through their regulation of utility procurement. In some states that allow limited or full retail choice, state agencies play an important role in backstopping resource adequacy and renewable generation procurement.
Most utilities have a long-term planning process through which they identify a least-cost portfolio of resources to meet forecasted demand, with regulatory or board oversight. Where competitive retail exists, this planning process is decentralized and unregulated but nevertheless also aims to supply expected demand at a competitive price.
For both utilities and competitive providers, ISO markets provide the balancing and reliability services to enable market participants to balance supply and demand in real-time at lower cost.
Although ISO real-time markets do provide the final arbitrage opportunity for electricity buyers and sellers, new generation investment is driven mainly by forward planning and procurement on the part of buyers.
In most of the U.S., planning and procurement is subject to some form of oversight. But even where it is not, there has historically been a significant forward premium in electricity markets because of the volatility and uncertainty in ISO real-time markets. Attaching too much emphasis to the ISO spot market stage of electricity markets puts the cart before the horse.
This forward leaning feature of electricity markets has a significant bearing on the question of whether existing market designs will be able to support the low-CO2 electricity systems of the future.
Concerns with solar and wind-heavy systems
The principal concerns around solar- and wind-heavy electricity systems are two-fold: (1) how meaningful is a real-time market that frequently clears at a price of zero, and (2) how can a market with prices that hover around zero attract the investment needed to maintain adequate supply?
Neither of these concerns should pose critical challenges for existing U.S. electricity markets.
The first concern assumes that, during most intervals, markets will clear at very low prices because low-emission, low-variable-cost resources — wind, solar, hydro, nuclear — will be on the margin. However, ISO markets will still play an important role in revealing opportunity costs for dispatchable wind and solar, hydro, loads and energy storage.
As long as the market is not perennially oversupplied in all hours, these resources will offer at opportunity cost (not variable cost) and market participants will need to internalize the risks of market exposure. Indeed, as electricity markets become increasingly interconnected, integrated and diverse, ISO markets will become an increasingly important tool for revealing opportunity cost and dealing with imbalances.
But will prices be high enough to induce investments in new generation and storage? This problem is as old as electricity markets. However, it is important to understand the problem as one of free rider prevention rather than simply a question of ISO market revenue adequacy.
ISOs have historically prevented market participants from free riding on ISO reliability services through a combination of short-term reserves and one of two mechanisms: decentralized coordination through scarcity pricing (ERCOT) and capacity obligations on load serving entities (all other ISOs and state regulatory commissions).
Both seek to ensure that market participants have sufficient incentives for forward planning rather than excessively leaning on the ISO as a backstop for reliability.
Supporting future generation investment
In principle, both mechanisms could support future generation investment in the same way they do today. (Ignoring, for brevity and expediency, questions around policy-driven transition.) Market participants would still plan their resource portfolios, including their energy and capacity market exposures, around expected demand and market conditions.
In energy-only markets, buyers buy some portion of their energy needs in advance to avoid spot market price volatility and risk. In markets with resource adequacy obligations, system operators or regulators impose capacity obligations on market participants to ensure that supply will be adequate to meet reliability metrics.
At much higher solar and wind penetrations, however, the mechanics of resource adequacy change.
Scarcity hours and loss-of-load probabilities shift from concentrations around summer or winter demand peaks to a larger, more diffuse number of hours throughout the year, driven by limits on solar and wind availability. As electricity systems become more dependent on solar and wind, the probability of prolonged periods of energy scarcity also increases, requiring some form of physical or chemical long-duration energy storage.
The question is whether solutions to these future resource adequacy challenges should be: (a) decentralized, resolved by market participants based on their own and ISO forecasts; (b) centrally coordinated by system operators and regulators through resource adequacy obligations; or (c) some hybrid of the two, for instance, where ISOs develop and procure longer-term reserves but allow market participants to self-supply.
Central coordination may seem to many an obvious solution, but this conclusion neglects the potential role of distributed energy resources in balancing supply and backstopping reliability. Centrally administered capacity obligations and highly responsive demand are, almost by definition, incompatible.
In a future world in which the demand side of the electricity system plays this more active role, the choice among options is less obvious.
Renewables and resource adequacy challenges
Although these physical resource adequacy challenges associated with renewable energy are likely a decade down the road, questions around how to augment ISO market designs to enable demand-side flexibility are relevant now. Current ISO market designs cannot accommodate highly responsive demand-side participation on shorter (intraday) timescales.
ISOs have historically preferred to put demand-side resources on the supply side of the market ledger, but as the lines among distributed generation, storage and demand response increasingly blur, and as the share of flexible load grows, this approach becomes untenable.
Putting demand-side resources back on the demand side, while at the same time allowing them to play an active role in shorter-term market price formation, will require a re-tooling of ISO intraday scheduling practices and markets that balances flexibility and reliability.
However, none of these challenges suggests that we should radically move away from the standard market design that all U.S. ISOs currently employ.
Instead, ISO markets will become increasingly indispensable to a future in which electricity systems have more diverse resources and market participants, have a more active demand side, and are more interconnected.