The growth of distributed energy resources is causing a transition in the utility industry as fundamental as the shift to competitive power markets in the 1990s.
Distributed energy resources (DERs) are diverse — from energy-efficiency and peak-shaving initiatives to distributed generation, storage, and microgrids — but they all enable customers to reduce their use of traditional grid services, and even to provide valuable services to the grid.
These resources fit like a square peg in the round hole of the traditional regulatory paradigm. As a result, regulators are taking a more serious look at a concept called performance-based regulation (PBR).
Consultants Mark Newton Lowry and Tim Woolf explore PBR as part of a new series of reports called Future Electric Utility Regulation from Lawrence Berkeley National Laboratory, funded by the U.S. Department of Energy.
In their paper, Lowry and Woolf ask: Do today’s utilities need PBR?
What’s wrong with traditional regulation?
Under traditional “cost of service” regulation, revenues are based on the utility’s total costs of providing service. All the investments made by the utility (net of depreciation) are known as the “rate base,” and utilities earn a percentage return on it. The bigger the rate base, the greater the profit. And if sales of electricity increase more than expected between rate cases, the utility keeps the additional margin.
As the Alberta Utility Commission put it in a 2010 proceeding that led to a PBR mandate, traditional regulation “offers few incentives to improve efficiency, and produces incentives for regulated companies to maximize costs and inefficiently allocate resources.”
Customer-side DERs erode utility earnings by reducing utility sales and opportunities for capital spending. This gives utilities “a material disincentive to accommodate DERs, even when DERs meet customer needs at lower cost than traditional grid service,” write Lowry and Woolf.
This is where the round hole comes in. Through proposed rate designs, engineering requirements, demand-side management budgets, and other means, utilities play a key role in determining whether DERs thrive. Because of the incentives inherent in traditional regulation, utilities are unlikely to support new programs and technologies for DERs — resources that offer considerable benefits to customers.
Regulatory approaches that align the interests of consumers and utilities can help achieve a reliable, affordable and flexible power system.
While New York’s Reforming the Energy Vision (REV) proceeding is the most high-profile attempt in the United States to solve this problem, states across the country are dealing with it in different ways. Regulators are witnessing increasingly complex dockets brought on by the electric sector’s transformation. Some are asking: Why not tie utility earnings to outcomes rather than to investments and throughput?
What is performance-based regulation?
PBR is an alternative to traditional utility regulation that emphasizes incentives for good performance. It can reduce utilities’ incentives to grow their rate base and use of their system and strengthen incentives to use DERs to reduce costs. PBR allows utilities to innovate and test new approaches, becoming more efficient in the process. If the utility succeeds, it gets to keep a share of the savings, creating a win for both customers and the utility. The flexibility inherent in PBR is especially important in a time of rapid technology change.
This is not to say that PBR is the right solution in every case. According to Lowry and Woolf, “It has its pros and cons, and it looks different from the perspective of consumers and utilities. Nor is it always the same; different states and countries have developed many variations.”
They document a variety of PBR tools that are available and in active use.
Revenue regulation: Also known as “decoupling,” revenue regulation sets utility revenues based on factors other than the megawatt-hours of throughput. This reduces the impact of lower throughput on utility profits, and thus makes utilities more open to the growth of DERs.
Multiyear rate plans: MRPs are the most common approach to PBR worldwide. Instead of coming in for a rate case every year or two, the utility operates under a rate plan that generally lasts four to five years. Formulas trigger automatic adjustments to the utility’s allowed revenues between rate cases without linking these adjustments to a utility’s actual cost. These formulas are known as attrition relief mechanisms, or ARMs. Stronger incentives for cost containment can help utilities to better appreciate the cost-saving potential of DERs.
Performance incentive mechanisms: PIMs strengthen incentives for good performance in targeted areas such as reliability, safety and demand-side management. PIMs for DERs could include things like the speed of the interconnection process and the success of peak load management programs. PIMs can be used with multi-year rate plans or added to traditional cost-of-service regulation. For example, nearly half of all U.S. retail jurisdictions already use PIMs to encourage demand-side management.
Regulators have tried PBR in many forms and places over the past 25 years. The “RIIO” approach in Britain has sparked particular interest in some regions. RIIO, short for Revenues = Incentives + Innovation + Outputs, brings all of these elements together into an eight-year plan, with an extensive set of performance metrics and PIMs.
While Lowry and Woolf consider the RIIO incentives to be strong and balanced, they note that RIIO plans are complicated, with each plan taking two and a half years to develop.
They cite other advantages and disadvantages that PBR offers to both customers and utilities.
As demand for power flattens or falls — as it has for the past decade — investment opportunities dry up. With PIMs, they note, “Improved performance can become a new profit center for a utility at a time when traditional opportunities for earnings growth are diminishing.”
MRPs can even “change the culture of utility management by fostering innovation, giving greater flexibility, and creating an increased focus on opportunities to reduce cost and improve long-term performance.” Another benefit is increased awareness of how a utility’s performance compares to those of peer utilities.
Customers can also benefit from PBR. If done right, customers could get better performance from the utility and possibly lower costs. They’ll find it easier to use DERs and may even get proactive help from their utility.
Of course, setting incentives and formulas is not easy, and mistakes can lead to problems. If the incentives are too low, utilities won’t respond. If they are too rich, profits will rise at the expense of consumers. PBR mechanisms can be complex and controversial. And having many years between rate cases — as is the case in Britain — can provide ample opportunity to go off track, especially in a period of rapid change.
While regulators in the United States may not go as far as RIIO, several states have approved MRPs, many states have approved PIMs without MRPs, and many states use decoupling. These PBR approaches, along with continuing adaptations to traditional cost of service regulation, can help support cost-effective use of DERs.
Since goals and situations vary widely from state to state, Lowry and Woolf stop short of recommending a single approach to regulators and stakeholders.
“If their main concern is to improve performance in specific areas, standalone PIMs might be sufficient. […] If they instead seek wide-ranging performance improvements, including better capital-cost management, MRPs may be better suited to these goals than PIMs alone. Regulators and stakeholders who wish to improve performance comprehensively and also focus on specific areas of performance in need of improvement should consider MRPs with an appropriately tailored package of PIMs.”
Additional reports, recorded webinars, and materials from the Future Electric Utility Regulation series are available at FEUR.lbl.gov.
Follow the Electricity Markets & Policy Group of Berkeley Lab on Twitter at @BerkeleyLabEMP.