Setting electric utility rates has traditionally been a three-step process: first, determining the revenue requirement; second, determining how to equitably divide costs among classes of ratepayers; and third, designing the rates themselves.

That second step, cost allocation, is a process that has been around for decades, and many jurisdictions have created detailed precedents for how it should be carried out. But these precedents were designed for the power system of the past, and today’s rapidly changing regulatory and technological landscape undermines the foundations of these methods.

To reflect modern technologies—such as wind, solar, storage, demand response, and smart grid systems—cost allocation techniques require significant updating. That’s why we have produced a comprehensive new manual, Electric Cost Allocation for a New Era, which describes the foundations of cost allocation, explains current best practices and sketches out the direction that it should travel in the future.

Cost allocation processes rely on two primary types of analytical studies: embedded cost of service studies (ECOSS) and marginal cost of service studies (MCOSS). A typical ECOSS first divides up all the costs reflected in the revenue requirement into several different functions, including generation, transmission and distribution. Then the costs within each function are classified as energy-related, demand-related or customer-related. Finally, these costs are allocated among the different rate classes, typically including residential, small commercial, large commercial, industrial and street lighting.

The analysis for an MCOSS starts with a similar functionalization step, but it is followed by estimation of marginal unit costs for each element of the system, calculation of a marginal cost revenue requirement (MCRR) for each class as well as for the system as a whole, and then reconciliation with the annual embedded cost revenue requirement.

While the best versions of these analytical techniques were based on solid theories and good practical experience, they used simplifications that were justified by the typical features of the electric system when they were developed. Our electric system at the beginning of the 21st century, however, has a wide array of new features that do not fit within the assumptions of these older analytical techniques. These new features include:

  • Distributed energy resources that provide benefits across the generation, transmission and distribution functions;
  • Investments in wind and solar that primarily provide energy benefits, rather than peak-serving benefits; and
  • Advanced metering infrastructure that provides a wide array of benefits beyond customer billing, including reliability and energy benefits.

We can develop new analytical techniques that account for these new realities. As a starting point, there are two high-level principles for cost allocation that help guide the way:

  1. Cost causation: Why were the costs incurred?
  2. Costs following benefits: Who is better off because the cost was incurred?

In some cases, these two conceptual frameworks point to the same answer, but in other cases they don’t. When they conflict, we believe that “costs follow benefits” should usually, but not always, take priority. The new manual considers these questions for a wide range of electric utility costs. While there are multiple reasonable techniques for each issue, there are high-level best practices that apply to both embedded and marginal cost of service studies:

  • Apportion all shared generation, transmission, and distribution assets and the associated operating expenses on measures of usage, both energy- and demand-based.
  • Ensure broad sharing of administrative and general costs, based on usage metrics.
  • Eliminate any distinction between “fixed” and “variable” costs, as capital investments (including new technology and data acquisition) are increasingly substitutes for fuel and other short-run variable operating costs.
  • Treat as customer-related only those costs that actually vary with the number of customers, a technique generally known as the basic customer method.
  • Where future costs are expected to vary significantly from current costs, make the cost trajectory an important consideration in the apportionment of costs.

Cost allocation may be as much art as science, since fairness and equity often lie in the eye of the beholder. In the first instance, cost allocation is a zero-sum process, where lower costs for any one group of customers lead to higher costs for another group. Thus, the best techniques used in cost allocation have been designed to fairly mediate these disputes between competing sets of interests. Applying both judgment and computation in a framework that accounts for the complexities of the modern power system will result in fairer and more equitable outcomes for all ratepayers. In addition, the cost allocation process can provide important inputs to rate design. One way it can do so is to identify seasonal and hourly cost variation by function and customer class, considering the time-varying portions of both capital investments and short-run variable costs.

This blog is the first of a series that will delve into today’s cost allocation issues in more detail, offering a path forward for regulators, utilities and stakeholders to incorporate newer, more innovative methods into the cost allocation process.