The previous blog post in this series examined embedded cost of service studies — but some states choose to look ahead, considering marginal costs. This approach stems from the economic theory that today’s consumption drives tomorrow’s costs and customer classes should be responsible for the future impact of their usage. These states, notably California, Oregon and Nevada, require utilities to base cost allocation on marginal cost of service studies.

A marginal cost of service study typically measures the cost of expanding system capability to meet additional requirements for capacity at peak periods, additional transmission and distribution capacity, and additional energy usage, with at least energy-related costs differentiated by time period. Just as it does for embedded cost studies, our manual, Electric Cost Allocation for a New Era, features an extensive discussion of best practices in completing marginal cost studies.

Key principles for the cost analyst to keep in mind for modern marginal cost studies include:

  • The time horizon examined should be consistent across all of the cost elements.
  • Capital costs often substitute for short-run variable costs, for example in the choice of wind or solar generation as an alternative to burning fuel in conventional power plants.
  • If the capital cost of new distribution service extensions to serve new customers is included, then the capital cost of new generation and transmission facilities must also be included.
  • Demand response, not new generating capacity or storage capacity, may be the lowest-cost capacity resource to meet short-duration peak loads.
  • Smart grid technologies, including smart meters and data managements systems, are used to save energy, to reduce capacity requirements, to collect data for system planning and to bill customers.

The “NERA methodology,” named for the consulting firm that originally developed it in the late 1970s, has many shortcomings in today’s electric system marked by significant quantities of wind, solar, storage, and demand response providing both energy and localized capacity services. Analysts using this dated method will need to update their models to reflect current resource options.

A common error in marginal cost studies is the failure to recognize that temporary excess capacity in one or more parts of the system — generation, transmission, or distribution — may distort the results of the study. This is a particular problem in systems where renewable portfolio standards may be causing the development of new generating capacity before it is required for reliability purposes. This can result in a temporary excess of capacity that distorts cost study results.

New problems emerge in a modern grid, where some particularly flexible capacity may be needed to provide “ramping” service during hours when renewable generation drops off, rather than to meet peak-hour needs. The analyst needs to understand this to properly determine how these capacity costs should be treated in the cost study.

With a marginal cost study in hand, the analyst needs a means for reconciling its findings to the allowed revenue requirement. Two methods are typically used, one that relies on the “inverse elasticity rule,” and a second, more commonly used, that employs the “equal proportion of marginal cost” framework. A key finding of the handbook is that the better choice is to reconcile cost elements within functional categories — that is to ensure that generation, transmission, and distribution costs are adjusted to reconcile with the revenue requirement within those categories, rather than across all costs as a whole. This avoids inequitable shifting of cost responsibility between customer classes, a common problem if generation or transmission investment is temporarily in surplus or shortfall.

As we’ve made clear here and in our previous posts, the transformative technological changes in the power sector — including the amount of new data now available — mean that modern cost allocation studies can, and must, take into account factors that older approaches could not and, in that old world, did not need to.

In our next, and last, post in this series, we’ll take a big-picture look at this changing landscape and recommend more cutting-edge ways in which regulators can ensure a more efficient and equitable assignment of utility costs.