Optimal Resource Adequacy

The existing and expected portfolio of resources can then be assessed for its ability to meet that standard using probabilistic analyses. This is based on simulations of variables, such as how different kinds of resources have historically performed under different conditions, the likelihood of different weather scenarios and how the amount and shape of demand is expected to develop going forward. Such simulations must reflect the reality that power flows on a large electric grid do not recognize political boundaries. It has long been recognized that resource adequacy is most cost effectively achieved by cooperation across the largest practical geographic area, and as the resource base changes, this will only become more important. As illustrated by events over two days in California in August 2020, the risks for supply shortfall are changing as the nature of the resource portfolio changes, with the greatest risks occurring at times other than when demand is at its highest. Assessment methodologies must adapt as needed to reflect this new reality.

This all leads to the critical question of whether and how the market will support the investment in resources needed to comply with the standard. Much has been written about the money ‘missing’ from markets to pay for the extra resources needed to ensure resource adequacy. In theory there is no such thing as missing money, but because electricity consumers have historically been unable or unwilling to vary their consumption themselves based on their VOLL, it is valid, at least for the time being, to ask how the market design should compensate as needed. This involves administrative interventions of varying degrees of intensity.

The least invasive approach taken in some markets relies on the role of the system operator, acting as proxy for consumers’ demand for reliability, in maintaining reserves to supply different balancing services needed to comply with the reliability standard. It involves various combinations of co-optimisation (combining the demand for energy and the demand for reserves to set a price for energy that optimises the allocation of resources between them) and administrative reserve scarcity pricing (setting an energy price adder that reflects the increased risk of a supply shortfall when the demand for energy causes reserves to fall below the required level; see Scarcity Pricing factsheet).

The resulting wholesale market price and volume risks incentivise buyers and sellers to support needed investment through bilateral contracting and trading in financial and physical hedge products. An additional measure of confidence can be provided by a backstop mechanism that provides for direct intervention by the system administrator in the event of an imminent unresolved shortfall in resource commitments.

Other regions take more invasive approaches, based on setting a binding level of planning reserves at some future date and enforcing compliance through various forms of centrally administered forward procurement processes. The commitments awarded under these mechanisms can be for as little as six months or as long as 15 years. This approach presumes either that it is more costly to rely on market actors to deliver the desired margin or that a less prescriptive approach cannot or will not deliver the desired margin on its own. This can become self-perpetuating, with binding targets often set well in excess of what an efficient market would ever deliver based on net value to consumers.

Even where planning margins may be properly set, it is debatable whether administratively allocated long-term commitments are more cost effective than a portfolio of market-driven forward market options. Such long-term commitments, guaranteed by consumers or taxpayers, can reduce investment costs on a resource-by-resource basis by shifting volume and price risks away from investors. But they can also lock consumers or taxpayers into investment choices years into the future. The longer the terms of the commitments, the more significant the risk that the overall final cost of energy may be higher, not lower, due to overprocurement, ill-advised investment choices, exclusion of lower-cost alternatives or premature obsolescence (see Thriving Forward Markets factsheet).

This question of the optimal mix of investment risk management options is of particular concern in the energy transition, which is giving rise to historic levels of uncertainty about technology and service innovation, the future shape of demand for electricity and the value of adaptability to both. Both approaches outlined above — the less prescriptive approach, combining co-optimisation and administrative scarcity pricing, and the more prescriptive approach of centrally administered long-term resource procurement — can be described as capacity-based market interventions. But they can lead to very different outcomes, both in the opportunities they provide for nontraditional or not-yet-apparent alternatives and in the extent to which the power system can adapt to rapidly changing circumstances. As we proceed through the energy transition, where market design falls on this spectrum will determine whether or not adequacy is assured in a cost-effective, sustainable manner.