Modern wholesale electricity markets are quite good at optimizing the variable costs of energy supply within the physical limits of the grid. But if that is not complex enough for your tastes, there are always the industry issues around capacity adequacy!
Market operators optimize the use of installed capacity resources by minimizing the cost to produce energy. This sort of optimization occurs after investment decisions have been made and resources are installed. The regional markets, however, do not determine which resource investments should be made, even those regions that have “capacity markets” as part of their design. Instead most regional capacity markets optimize the residual long and short positions of load-serving entities and can form a basis for enforcing compliance with a resource margin obligation.
Regional markets provide an aggregate benefit by setting the minimum level of resource margin. Resource margins in a pooled regional market are generally lower for the same level of reliability, compared with each utility providing this level of reliability on their own. This results in lower costs for society.
What are some of the key considerations of capacity adequacy? On the resource menu there are many capacity options including hydro, nuclear, coal, gas, oil, wind, solar and biomass. There are demand response investment options. There are increasing options for energy storage investments as part of the resource mix. So for a moment, let’s discuss aspects of capacity resource selection and related adequacy issues.
First, there is the technical evaluation of how much margin is necessary. This is typically referenced with respect to the peak demand. So for instance, a 15% capacity adequacy margin is generally understood as 15% more installed than needed to cover peak demand obligations.
The right level of reserve margin is an important consideration. The magnitude of investments in capacity can deeply impact the quality of life and the competitive posture of the economy. If too little investment, we may suffer energy price spikes or blackouts due to shortage, along with the associated social disruption. If too much investment, our businesses are less competitive in a global marketplace and our homes and families can’t make ends meet. Technically, the size and availability of the resources in the pool influence the calculation of the minimum reserve margin level.
Second, there is a counting question. For a coal plant, how much nameplate capacity serves to meet the margin requirement? What about for gas plants? Does water or fuel availability impact how a resource should count towards sufficient supply margin? Not all plants are the same. A fossil generator without fuel does little to support reliability needs. What sort of forward time horizon should be used to evaluate compliance with sufficiency criteria? One starts to get an idea of the inherent complexity around capacity adequacy issues when the counting debate begins.
There is no industry standard on counting traditional resources like coal, gas and nuclear towards a margin requirement. In most areas traditional fossil resources count at or near 100% of their nameplate (maximum) production capability. Some regions reduce this percentage based on the historical reliability performance of the resource. In such cases a resource that has poor forced outage performance would see a reduction in its credit towards meeting the capacity adequacy margin. This sort of policy is seen as an incentive for resources to remain available when needed.
But if fossil resource counting is not yet standard, there is even less agreement on counting resources such as wind, solar and battery storage. Many regions today count wind resources at about 10-15% of nameplate and solar PV resources at 30-50% of nameplate. Batteries are so new to the game that most market areas do not allow any direct counting towards margin compliance. Batteries disguised as demand response may circumvent this obstacle but may lose options for some market dispatch benefits.
Accrediting wind and solar resources for capacity adequacy is good. It allows us to move beyond archaic concepts of “firming” for wind. These old concepts assert that a variable resource must provide some sort of counterbalance or purchase some ancillary service as part of integration. Modern markets no longer discriminate on this basis. Instead the resource need is addressed through compliance with capacity adequacy margins. Then the regional energy market provides sufficient operating headroom to assure balance for net variability challenges or resource contingencies. This helps illustrate the interplay between capacity adequacy and variable cost optimization.
Third, probably the most important issue around capacity adequacy is directing and recovering investments. Some independent power producers believe investment cost recovery should be managed through a central procurement process, administered by Federal regulators. But state-regulated utilities address their investment and portfolio cost recovery directly with state regulators. There is a patchwork of capacity policy in evidence through the country, but some trends are becoming clear. State-level integrated resource planning can best address investment. And regional capacity markets can help ensure compliance with the margin obligations.
Conditions were different in past decades when some states restructured their electric utilities, transforming state-regulated cost recovery for generating resources into “sink-or-swim” policy in competitive wholesale electricity markets. In that era it was a common paradigm that 5-25% of the annual hours there would be high-priced resources at the margin, burning oil or high-cost natural gas. The high market prices during these periods would create profits for cheaper baseload resources. The theory was the resulting “infra-marginal rents” would be sufficient to keep a portfolio of resources in business. Today that theory is falling short.
Now we have very little oil generation at the margin, we have cheap gas competing with baseload costs of production and we have wind and solar output further reducing energy prices in the markets. The infra-marginal rents have become quite low. Baseload nuclear plants in restructured states are closing, despite the adverse impact of such retirements on national carbon emissions. A few years back a study by the Brattle Group, performed for ERCOT, showed that regional US energy market prices are not high enough to ensure investments at a level that satisfies capacity adequacy criteria. These factors underscore the need for a rule or criteria that requires sufficient capacity margin outside of what would naturally result from infra-marginal rents in the energy markets.
One solution to the issues being encountered in these restructured states is to re-restructure. This involves making some sort of regulatory provision for the recovery of plant fixed costs outside the variable cost optimization employed in the regional energy markets. States that have elected to retain their vertical integration of utilities have fortunately avoided the need to evaluate this option. Most of these states use an integrated resource planning process to review the generation investment and planning process.
Lastly, a point supporting the state-level integrated resource planning process used to address generation investments. In contrast to areas that have placed reliance on federal centralized capacity markets to direct investments, state integrated resource planning avoids a big drawback. Namely the load-serving utility is more able to manage prudence in tailoring the portfolio of resources to meet its customer obligations. Portfolio differentiation is a means to manage supply risk by resource type. For instance, wind is a nice hedge against exposure to natural gas prices. In a market design where capacity investment decisions are centralized and merely allocated to load-serving entities, we could fall into the same pit as everyone else, instead of a pit of our own making, so to speak. We would be unable to design the supply cost hedge for our customers that our own portfolio can provide.
The state-level resource planning waters are not all calm, particularly for multi-state utility operating companies. Portfolio differentiation is challenged when supply assets are legislated into the mix. In some cases renewable resources, particularly wind generation, are economic in their own right despite resource portfolio standards. In other cases however, the portfolio stipulations amount to an indirect price support for the preferred resource of the day. This sort of price support, where it may exist, can create state-to-state regulatory dissatisfaction with some portfolio costs. But one may observe that states unhappy with other states’ capacity policy could also demonstrate unhappiness with regional wholesale markets directing capacity investments under federal regulatory market designs.
The current legal framework in the US largely reserves questions of capacity adequacy and related investment recovery to state regulatory jurisdiction. “Restructured” states that have attempted to rely on regional wholesale markets to address capacity investment cost recovery are reportedly realizing that they may have relinquished some of their authority in this area to the federal regulator. Hallway conversations at regional market meetings reference federal tinkering with the capacity market in ISO-New England, for instance.
The complexity of public policy issues related to capacity adequacy can be both intimidating and overwhelming. One must contend with a patchwork of policy and jurisdictional issues when dealing with capacity adequacy and associated investment risk and cost recovery. In this dialog one must keep in mind the best role and function of regional energy markets is to optimize the variable costs of energy supply, which is separate from the resource investment decision.
Director, Market Operations