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.
It has been "one directional" and "linear" but a more distributed system with "bi-directional flows and bi-directional value transactions" is complicating both planning and price setting, he said. Prices and rates are no longer entirely based on the planning process. "We are building a more transactive system with more dynamic interplay between the pieces of the system."
The Xcel Energy 2017 solicitation's median bids of $36/MWh for solar-plus-storage and $21/MWh for wind-plus-storage for 2023 delivery changed the conversation, Cross-Call said. "We're moving toward a system in which we're defining what services the grid needs and then conducting all source solicitations to obtain them at the lowest cost to customers."
This new system will emerge through "an iterative process that will unfold over a number of years," he said. Initially, the solicitations will reveal the new capabilities and values of new technologies. Over cycles of solicitations and deployments, the planning process will deliver these values that "evolve into rates or tariff structures."
As new DER technologies allow customers to provide more services to the grid, the "underlying core business of the utility will need to be reconsidered," Cross-Call said. It is already becoming evident that basing utility earnings on an approved rate of return on capital expenditures is not the most efficient and effective form of regulation, he added.
"A lot of important decisions still rest in the rate case," he said. But general policy proceedings, exploratory proceedings, and solicitations for specified grid needs are emerging as equally important. The rate case is still the venue for the financial decisions and customer rate setting, but through the iterations of solicitations and deployments, that is likely to change.
Xcel's solicitation, for example, will likely lead to other utilities soliciting offers — a process that is likely to result in new thinking by utilities about how to acquire their resources, he added.
Bigger questions will have to be answered about "the utility of the future and what its core business is and how revenue and earnings can come from a different business model," Cross-Call said. But even in a more distributed system, the utility is an essential player and "we have to identify its role and compensate it appropriately. A performance-based regulatory structure would probably go a long way in doing that."
Stepping toward performance
RMI Electricity Practice Principal Leia Guccione said power system stakeholders are now saying they want to move to a performance-based regulatory structure but they don't yet know how to do it.
"They are ready in theory but have no experience with the design and execution," she said.
EI’s Aggarwal said performance-based ratemaking (PBR) values DERs because it compensates utilities for delivering what customers want. If utilities are rewarded with incentives for that, they will look for and find the low-cost opportunities in solicitations and the new DER technology options.
In response to customer demand and to flattening and uncertain load growth, the utility business model is already evolving, Aggarwal wrote May 7 in Forbes. PBR is transforming the COSR-based business model, in which profit depends on returns on capital investments, to rewards for meeting policymaker-set goals based on customer demand.
Led by Hawaii, Rhode Island and Minnesota, utilities and policymakers are building a new uility business model around the PBR concept, Aggarwal wrote. Thirteen states are working on PBR and utilities are paying attention. In Utility Dive’s 2018 State of the Electric Utility, 42% of more than 600 utility employees said they prefer a hybrid model that merges COSR and PBR, while 35% want predominantly performance-based regulation.
Only 4% of utilities now have a "predominantly PBR environment," but 81% of utilities "either already have or want" regulatory action on some type of business or revenue model reform, the report found. And almost three-fourths (73%) of utilities expect to face a COSR-PBR or PBR-based regulatory system in the next decade.
Hawaii is demonstrating one way forward by working with stakeholders to clearly articulate performance goals, Aggarwal said. Minnesota is demonstrating another way forward. "The stakeholders and the utility have been working on the PBR concept for years and understand the utility revenue model and where we're going," she said. "They are moving toward specific metrics and incentives for the utility."
The end of the two-step?
Faruqui is skeptical of the transition to PBR.
"At a high level, PBR cannot change ratemaking unless you specifically put the performance in a metric and that has become a great opportunity for stakeholders to bring all their favorite things into the discussion," he said. "Is it better than cost of service? People thought it would simplify ratemaking, but there are all those metrics. The debate continues."
Rabago agreed that the advance of DER can be aided by a shift toward PBR, but said that won’t mean an immediate end of the two-step. Cost-benefit analysis will gradually replace COSR "so that the utility can get compensated for making more DER a reality," he said.
"In the mostly backward-looking world of cost of service ratemaking, more non-utility stuff means less-utility stuff, which means lower rates," he said. "PBR aims toward reward — profit — based on doing what customers want. But we can’t settle on PBR incentive and compensation levels without a benefit-cost analysis that shows benefits outweigh the costs and justify the incentives."
But regulators, utilities and policymakers will need to make adjustments, and the transition could create "a bit of a monster arrangement" that has a "neither all old nor all new" regulatory structure, he said.