Should the regulatory two-step give way to a new, performance-based dance? RSS Feed

Should the regulatory two-step give way to a new, performance-based dance?

Critics say traditional cost-of-service ratemaking is behind the times, but newer models require a complex production from a variety of industry players.

Is the process used to set the prices customers pay for electricity biased against new energy technologies?

Regulated utilities traditionally go through two separate processes to arrive at the rates they charge customers for electricity — long term Integrated Resource Plans and short term revenue requirements based on Cost-of-service ratemaking.

Some stakeholders say the disconnect between those two processes creates an unfair disadvantage for new technologies now becoming available to utilities and system operators, like distributed solar, energy storage and advanced demand management.

Several states, utilities and policymakers are trying to address the slant against these distributed energy resources (DERs) with a different ratemaking model. Traditional ratemaking, they say, fails to attribute long-term value to new technologies located on the distribution system, leaving those benefits out of IRP planning. The disadvantage is furthered if the new technologies are customer-owned, not offering return-on-investment opportunities for utilities.

Those dynamics could amount to a violation of regulators’ obligations to keep the power system fair and open, critics of traditional ratemaking say.

IRPs and cost-of-service regulation do allow the utility to determine the least-cost portfolio of resources and infrastructure to serve its customers, said Sonia Aggarwal, vice president at the clean energy think tank Energy Innovation.

“But,” she added, “they are not really thinking about maximizing value to customers, and they are modeling their resource choices on the assumption of the traditional one-way flow of the system from utilities to customers.”

The power system is evolving and customer demand is emerging as its central driver, Aggarwal said. As utilities face this new reality, today’s ratemaking two-step is giving way to a newer, performance-based ratemaking model built around a new business paradigm for electric utilities.

The new approach begins by identifying what utility customers want and then uses a stakeholder-based regulatory forum to create opportunities for utilities to earn money by meeting those demands. Should they succeed in driving greater volume to customers, these new performance-based ratemaking models could reshape the electric utility industry across the continent.

The ratemaking two-step
​Each of the two traditional ratemaking processes plays an important role, Arizona Public Service (APS) Director of Rates and Rate Strategy Leland Snook emailed Utility Dive.

The IRP process uses projections of costs and benefits to determine “whether we should procure a resource,” he said. Cost-of-service ratemaking, meanwhile, uses “actual, measurable data and answers the question of how much customers should pay for a resource once procured.”

The first of the two processes a utility uses to arrive at rates is integrated resource planning (IRP). The IRP process models a wide range of costs and benefits from possible expenditures and expenses, usually over a period of 20 years or more. It determines the “least-cost, best fit” portfolio of resources and infrastructure.

The second process is identifying the utility’s revenue requirement for its next rate period, which is typically one year to three years. Cost-of-service ratemaking (COSR) is applied. It is based on historical usage and cost data. The final revenue requirement includes a percentage of the utility’s proposed capital expenditures as a rate of return for shareholders whose investments provide the utility with operating capital.

The formal rate case proceeding follows. Regulators evaluate the utility’s projected revenue requirement in a public proceeding and, in a ruling based on the utility’s proposal and interveners’ responses, the utility is granted the right to apply “just and reasonable” charges to various customer classes. Those charges typically appear on customers’ bills as a per-kWh volumetric charge for usage, various fixed charges, and administrative charges.

“The total amount of money that is collected and the total amount of the utility’s revenue requirement always have to match,” EI’s Aggarwal said.

The trouble with the two-step
Aggarwal said the typical planning process does not use the most up-to-date modeling tools and capabilities to evaluate potential least-cost portfolios. Underlying that, many utility planners still “envision a system with big central station power plants and transmission lines and the distribution system is pretty much left out,” she said.

Better analytics and modeling can include the benefits and costs of resources on the distribution system in the IRP analysis, Aggarwal said. The system cannot be optimized with an IRP analysis that disadvantages new DERs and other new technologies.

A few specific shortcomings in the IRP and COSR processes disadvantage DERs, according to Karl Rabago, a former Texas regulator who is now executive director of the Pace Energy and Climate Center and a frequent rate case expert witness.

The COSR “retrospective” analysis fails to consider long term benefits available to new technologies, Rabago emailed Utility Dive. At a higher level, it biases utilities against customer-owed resources on the distribution system through its limitation on utility earnings to capital expenditures.

Rabago called this the “you have to spend capital in order to earn” bias.

“On the customer side, there is another huge gotcha,” he added. “It is ‘thanks for investing in DER, but since our sales went down, your rates are going up!'”

Where the two-step works
Traditonal COSR and ratemaking work for utilities that keep the projected values of distributed technologies out of the process.

APS’s Snook said COSR “fully values DERs by permitting customers to reduce their electricity bills with DERs by the amount of grid costs that they save.” This calculation is made in a separate DER valuation process.

Arizona regulators have explicitly rejected ratemaking based on the projections used in IRPs and ruled rates must be based on a retrospective analysis of “measurable data,” Snook said. “Basing rates on actual data protects customers by ensuring that they only pay for costs actually incurred.”

The process also works in disputes, like those over net energy metering for solar, in which conflicting cost-benefit analyses incline regulators to rely on traditional COSR analyses.

Brattle Group Principal Ahmad Faruqui, a frequent rate case expert witness, said advocates for new technologies “become frustrated if rates don’t help them.” Aside from the temporary retail electricity rate compensation for solar generation through net energy metering, “rates have generally not been built to encourage technologies,” Faruqui said.

In the IRP, “we need to include all technologies, with their costs and benefits, to have a level playing field,” he added. “Rates are a separate conversation. The cost-of-service study used for ratemaking is based on well-known, traditional — and some new — principles of rate design going back to Bonbright.”

James Bonbright’s text on ratemaking remains the established ratemaking standard for electric utility commissions.

It is true that COSR does not recognize benefits like environmental costs that advocates for some new technologies want recognized, Faruqui said. But if policymakers want benefits of a technology compensated, they can provide incentives through policy mechanisms like rebates or tax credits.

The cost of those incentives must be recovered, he added. “But putting it in rates creates needless complications and subsidies. That’s just how the process works. Regulators approve the cost of those incentives in procedures outside of the ratemaking process.”

That leaves the traditional well-established, workable process in place. It begins with planning to identify the utility’s least-cost portfolio of resources, “based on their costs and benefits and other factors,” he said. “It then moves to ratemaking. It is like a flowchart.”

Beyond the two-step
The power system is transitioning from one in which utilities have forecasted their needs, proposed and built accordingly, and translated that downward to rates, Rocky Mountain Institute (RMI) Electricity Practice Manager Dan Cross-Call told Utility Dive.

Read full article at Utility Dive