TODAY’S STUDY: A NEW WAY OF THINKING ABOUT ELECTRICITY RATES
Performance-Based Regulation In A High Distributed Energy Resources Future
Mark Newton Lowry, Pacific Economics Group Research Tim Woolf, Synapse Energy Economics Project Manager and Technical Editor: Lisa Schwartz, Lawrence Berkeley National Laboratory January 2016 (Lawrence Berkeley National Laboratory)
Performance-based regulation (PBR) of utilities has emerged as an important ratemaking option in the last 25 years. It has been implemented in numerous jurisdictions across the United States and is common in many other advanced industrialized countries. PBR’s appeal lies chiefly in its ability to strengthen utility performance incentives relative to traditional cost-of-service regulation (COSR). Some forms of PBR can streamline regulation and provide utilities with greater operating flexibility. Ideally, the benefits of better performance are shared by the utility and its customers.
The shortcomings of traditional COSR in providing electric utilities with incentives that are aligned with certain regulatory goals are becoming increasingly clear. In particular, COSR can provide strong incentives to increase electricity sales and utility rate base. Further, some parties express concern that traditional COSR does not provide utilities with appropriate financial incentives to address evolving industry challenges such as changing customer demands for electricity services, increased levels of distributed energy resources (DERs), and growing pressure to mitigate carbon dioxide emissions. In addition, attention to potential new regulatory models to support the “utility of the future” has renewed interest in PBR.
This report describes key elements of PBR and explains some of the advantages and disadvantages of various PBR options. We present pertinent issues from the perspectives of utilities and customers. In practice, these different perspectives are not diametrically opposed. Nonetheless, this framework is useful for illustrating how various aspects of PBR may be viewed by those key groups. Regulators have a unique perspective, in that they must balance consumer, utility, and other interests with the goal of achieving a result that is in the overall public interest.
PBR Includes Many Elements and Variations
PBR is not a one-size-fits-all construct designed uniformly wherever it is applied. Instead, PBR is made up of several elements intended to strengthen utility performance incentives that can be applied in different ways and in different combinations. Some of these elements are applied as stand-alone elements in regulatory systems that are largely traditional.
The most common approach to PBR worldwide is the multi-year rate plan (MRP), which combines a rate case moratorium with an attrition relief mechanism (ARM) and some performance incentive mechanisms (PIMs). MRPs may also feature revenue regulation (also called revenue decoupling), earnings sharing mechanisms and other techniques. These elements are briefly described in Table ES 1.
Key Advantages and Disadvantages of Multi-Year Rate Plans
MRPs can strengthen incentives for utilities to improve performance in a wide range of initiatives, and the benefits ideally are shared between utilities and their customers. If designed well, MRPs can provide strong incentives for utilities to support or implement DERs. MRPs can also provide utilities with additional marketing flexibility where regulators deem this desirable, while providing some protection for customers taking service under standard tariffs. MRPs can also reduce regulatory cost.
However, some regulators and consumer advocates may lack the expertise and funding needed to effectively consider the implications of MRPs and to address design issues. A utility’s revenue may exceed its costs for extended periods. When regulators introduce tools to contain these variances, such as earnings sharing mechanisms, utility performance incentives may be weakened.
MRPs give utilities more opportunities to profit from improved performance. They can provide utilities with greater marketing flexibility to meet competitive challenges, retain large load customers, and satisfy the complex, changing demands of customers. Improved performance can become a new profit center for a utility at a time when traditional opportunities for earnings growth are diminishing. Less frequent rate cases can help utility managers focus on their basic business of providing customerresponsive services cost-effectively. Reduced regulatory cost is particularly valued by utility companies that operate in multiple jurisdictions.
On the other hand, MRPs can increase operating risk, without providing the utility with a compensatory adjustment to the authorized return on equity. Revenue may occasionally fall short of cost. Further, rate plans can be designed in such a way that customers receive most benefits, leaving the utility at a disadvantage.
Key Advantages and Disadvantages of Performance Incentive Mechanisms
Customers’ Perspective PIMs allow regulators and stakeholders to provide detailed guidance to utilities with regard to specific performance areas and the desired outcomes. They can be offered incrementally and gradually, thereby reducing customer risk.
This detailed guidance can also create tension among the parties involved. If there are significant incentives at stake, proceedings to design and approve PIMs can be complex, contentious and resource intensive. In practice, PIMs tend to focus on performance areas that are relatively easy to identify and evaluate, such as service quality, reliability and demand-side management (DSM) implementation, but may overlook other performance areas that also require improvement.
If not well-designed, PIMs can suffer from several pitfalls that would be detrimental to customers, such as disproportionate rewards, lax standards or unintended consequences. Financial rewards and penalties need to strike the right balance: low enough to mitigate regulatory risk, but strong enough to incentivize correct utility behavior. This balance can sometimes be difficult to achieve.
PIMs alert utility managers to special concerns of regulators and customers, helping to maintain good relationships among the parties to regulation. PIMs, like MRPs, can provide new earnings opportunities in an era when traditional opportunities are diminishing for some utilities.
But chosen metrics are sometimes difficult to control. Targets can be unreasonable at the outset or ratcheted unfairly as performance improves. Many PIMs involve penalties but no rewards, which is counter to the workings of competitive markets, where good performance typically results in higher revenue. When PIMs do offer rewards, they are often relatively small due to low reward rates and the limited scope of PIMs.
Are Stand-Alone PIMs Better Than Multi-Year Rate Plans?
The recent resurgence of interest in PBR in the United States has often focused on the addition of stand-alone PIMs to existing regulatory systems, rather than implementing MRPs or refining MRPs when they are already in use. This report discusses the advantages and disadvantages of MRPs and stand-alone PIMs.
Relative to MRPs, PIMs tend to be simpler, more transparent, less risky, and more focused on specific performance areas of interest to regulators. While the design of PIMs is also subject to some controversy and complexities, the stakes are generally much lower than in MRP design, and the process may be less contentious. On the other hand, stand-alone PIMs have to provide sizable incentives if they are to induce utilities to fully embrace energy efficiency and other DERs wherever they are preferable to utility capital expenditure. Important areas of utility performance such as general cost containment could in principle be addressed by PIMs, but typically are not.
MRPs incentivize a broader array of performance improvement initiatives. A well-designed MRP with revenue regulation and appropriate PIMs for DERs may be the most effective way to promote DERs. MRPs may also reduce the frequency of general rate cases and can therefore substantially reduce regulatory cost, unlike stand-alone PIMs.
Stand-alone PIMs can make more sense for utilities when the current regulatory system yields adequate revenue, investment opportunities are ample, and regulators and stakeholders are resistant to the types of sweeping changes associated with MRPs. It is sometimes difficult for the utility and stakeholders to agree on compensatory revenue escalation in an ARM.
MRPs make more sense for utilities when the regulatory community is receptive and containing regulatory cost is a special concern due, for example, to ownership of multiple utilities. In some cases, it is relatively easy for the utility and stakeholders to agree on a set of revenue escalation provisions.
MRPs can increase utility marketing flexibility by allowing a utility to provide alternative prices and products to some customers without a rate case and without affecting customers in other rate classes. The need for flexibility may increase in coming years in order to: (a) contend with increased competition from distributed generation; (b) provide customers with tailored clean energy products; and (c) offer optional rates and new services that advanced metering infrastructure makes possible.
What Can the United States Learn From the British Approach to PBR?
The United Kingdom’s RIIO approach to regulation has been mentioned in several recent papers as a promising new regulatory model for the “utility of the future.” It offers numerous regulatory innovations. For example, converting multi-year cost forecasts into ARMs with inflation adjustments provides more inflation protection than the “stair-step” ARMs that are popular in the United States. Incentive-compatible menus have promise in the design of ARMs and other plan provisions. RIIO uses PIMs to creatively address new performance areas.
Despite its innovation, RIIO is an unusually expensive and time-consuming approach to MRP design. Further, requiring eight years between rate cases significantly reduces the ability of regulators and stakeholders to review utility investments. North American regulators have developed alternative approaches to MRP design that are also worth considering. These include ARMs based on indexes, PIMs for DSM, efficiency carry-over mechanisms, and the use of settlements to establish MRP terms.
ARMs based on multi-year cost forecasts can help fund expected cost increases and sidestep controversial indexing and benchmarking research. Inflation adjustments reduce operating risk.
On the other hand, some utilities may resist the extensive use of independent benchmarking and engineering studies in the British approach to ARM design. Eight-year ARMs do not provide utilities with much flexibility for dealing with unforeseen challenges, even if they are based on a utility’s own forecast.
A Roadmap for Regulators
Whether any jurisdiction should take steps toward adopting MRPs or PIMs depends on how well existing regulation is working and the extent to which regulators and stakeholders wish to accept the risks and transition costs associated with new policies. In general, discussions of PBR options in a high DER future should evaluate and balance the range of potential PIM and MRP options that might fit any one jurisdiction.
Table ES 2 presents a summary of how various PBR options might match different regulatory goals. The left column identifies the performance improvement goals a state might have; the middle column indicates the extent to which regulators and stakeholders are open to making regulatory changes; and the right column indicates the combination of PBR options that might be appropriate for that state.
Regulators and stakeholders who are satisfied with current utility performance, and expect continued satisfactory performance in a high DER future, may prefer to maintain current regulatory practices.
Regulators and stakeholders who would like to promote improvements in utility performance should consider what areas of performance are most in need of improvement and are most critical in a high DER future. If their main concern is to improve performance in specific areas, stand-alone PIMs might be sufficient to address these areas. 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 wish to focus on some specific areas of performance in need of improvement should consider MRPs with an appropriately tailored package of PIMs. For example, an MRP with revenue decoupling, tracker treatment of DER-related costs, and PIMs related to cost-effective DERs can provide strong encouragement for utilities to support cost-effective DERs.