A version of this article was published on Greentech Media on April 6, 2018
By Mike O’Boyle
If you’re a utility regulator, you’re undoubtedly hearing about new regulatory models, more specifically, performance-based regulation. At the 2017 NARUC Annual Conference, a panel of investment advisors described a focus on metrics and incentives for efficiency, and you might have been played the NARUC MegaModels game at or before the event. Or perhaps you were one of the “millions” of viewers Public Utilities Commission of Ohio (PUCO) Chair Asim Haque hoped were listening in to day five of Ohio’s PowerForward hearing on utility ratemaking on March 21.
As new opportunities to optimize the system meet the imperative to cost-effectively integrate low-cost variable generation, reforming utility business models to reward outcomes will become increasingly important, and may be coming to a state near you. But regulatory processes can constrain the ability to get policies designed well in the implementation and incentive design phase. And success depends on getting the details right.
In order to meet the challenge of designing new business models to achieve better outcomes and avoid unwanted consequences, regulators can take proactive steps to examine these issues – bringing stakeholders up the learning curve, creating a robust record, and quantifying existing incentives and historical performance.
The biggest lesson for regulators: it pays to get out in front of this movement and start the conversation now with stakeholders in your state.
Building towards implementation
Though the theory underlying performance-based regulation for utilities is sound, transitioning from theory to practice can appear difficult and risky. Even the best of intentions can yield unintended results when performance incentives are poorly designed, such as a disastrous customer service incentive that was gamed by Southern California Edison in the 1990s. As a result, these issues need due attention from stakeholders and regulators to get the details right and drive desired outcomes.
Changes to the utility revenue model to reward performance are often implemented in rate cases, which are already extremely resource and information intensive, and typically must be resolved within a matter of months. Without first building understanding and a substantive record to inform implementation, adding in major changes to how utilities make money may be incompatible with good policy design. Taken one step further, a robust record is required for getting these details right, since public utility commissioners (PUCs) must draw from the record when adjusting utility ratemaking.
An information gathering and learning phase for stakeholders, including utilities and regulators, can build understanding and a record to inform a rate case or formal proceeding introducing performance incentives. Leader states like Rhode Island, Minnesota, and New York are reaping the benefits of this foresight in later implementation stages; their experience can help inform a next wave of states reexamining utility incentives, such as Oregon, New Hampshire, Michigan, New Mexico, Pennsylvania, and Texas. Initial investigations on new utility regulatory models can benefit from common features like inclusively educating stakeholders, creating a robust record for the commission and stakeholders to draw upon the future, and cataloguing the historical performance and existing incentives of utilities.
Minnesota is one state that brought stakeholders, including utilities, up the learning curve on options for regulatory reform without politicizing the process and outside the restrictive environment of adversarial PUC proceedings. Minnesota’s e21 initiative, led by the Great Plains Institute (GPI) and the Center for Energy & Environment, started in February 2014 with the purpose of investigating whether the existing regulatory model was sufficient to achieve Minnesota’s policy goals. e21 convened Minnesota’s regulated investor-owned utilities, energy technology companies, environmental advocates, consumer advocates, academia, cities, the Minnesota Chamber of Commerce, as well as the Department of Commerce and regulatory staff.
GPI led the e21 stakeholder group in a structured process called transformative scenario planning, through which the group mapped the current state utility ratemaking, agreed on guiding principles that should characterize any future electricity system, developed possible future scenarios, and then crafted recommendations to best position Minnesota in any of those futures; all while learning about a range of issues through presentations from e21 stakeholders and national experts.
This discovery process also included developing working papers summarizing the current utility regulatory framework and gave all stakeholders a baseline set of facts from which to work. It revealed that all e21 stakeholders were disenchanted with the existing utility business model and regulatory framework, albeit for quite different reasons, setting the table for change.
After roughly a year of monthly meetings (and small group work in between), the group published consensus recommendations for future regulation, including “[a] new performance-based, more forward-looking approach to ratemaking and incentives.” This agreement influenced several important outcomes, including the Minnesota PUC approving Xcel Energy’s proposed four-year multi-year rate plan for 2016-2020, a measure highly aligned with e21 recommendations. e21 was also able to move on to a “Phase Two”, through which the options for performance-based regulation and other subjects were fleshed out, building further sophistication and highlighting key areas of agreement.
In 2017, the MPUC issued a notice for parties to comment on potential performance metrics that align with goals articulated in e21’s report. GPI, CEE, and e21 participants used further collaborative dialogues to develop and submit comments to the MPUC describing general areas of agreement and disagreement among stakeholders. e21 will also continue with Phase Three, supporting implementation of innovative pilots and research on new utility models by fostering further stakeholder dialogue and informing PUC decisions.
Other states are educating stakeholders through PUC proceedings. Ohio’s PowerForward initiative hosted thought leaders from around the country for six days in March 2018 to build understanding on utility ratemaking evolution, creating a potential launching point for proceedings at PUCO to address utility business model challenges. The Illinois Commerce Commission is ramping up seven parallel stakeholder working groups that will focus on evolving the power system, including ratemaking, with the intent to inform future regulation or legislation. Oregon, spurred by legislation, is embarking on a formal process to re-examine utility incentives, starting by educating stakeholders on the existing business model, and partnering with Rocky Mountain Institute and Regulatory Assistance Project for policy advice and facilitation services.
Creating a record
In March 2017, prompted by request from Governor Gina Raimondo, Rhode Island’s Division of Public Utilities (DPU), the state Office of Energy Resources (OER), and the PUC jointly investigated the changes to the electricity sector and utility investment needed to affordably and reliably reduce greenhouse gas emissions by 80 percent below 2005 levels by 2050. The inter-agency team managed the Power Sector Transformation (PST) Initiative with four work-streams: 1) utility business models, 2) grid connectivity and functionality, 3) distribution system planning, and 4) beneficial electrification.
After two months of technical meetings and another four months of facilitated engagement with draft proposals including stakeholder comments, the DPU and the OER published their Power Sector Transformation Phase One Report, recommending significant changes to the existing utility model. The PUC was unable to join in the deliberation and decision-making for the final report, since it maintains the appropriate decision making neutrality for future rulemaking proceedings.
The PST report’s utility business models recommendations focused on strengthening the link between utility profits and performance. It recommended exploring metrics and incentives for demand-side management and distributed energy resource integration along with a multi-year rate plan. The report also tracks party comments and shares how they differ from the recommendations, giving all stakeholders a better sense of their counterparties’ views.
Shortly after the PST report was published, National Grid filed a rate case which proposed to add incentives that were materially different than those recommended in the PST report, though the proposal represents an incremental step toward the report’s vision. Now that stakeholders have undergone education and exploration under PST, they are armed with better understanding and common language and recommendations they can use to critique or support National Grid’s proposals. The PUC could ultimately consider the recommendations directly in the case, as the DPU will also be an intervenor.
Of course, there’s more than one way to build a record, and Rhode Island’s precise method reflects its unique situation of having significant experience with energy efficiency and renewable energy incentives, a prior commission-led Investigation into the Changing Electric Distribution System, executive branch support, and only one regulated utility.
New York took a slightly different approach. After engaging stakeholders in forums of varying formality, the Department of Public Service staff itself issued straw proposals for comment to build a record on utility business model reform in its Reforming the Energy Vision (REV) dockets. The “Track One” and “Track Two” proposals each took on a wide range of issues related to rate design, utility incentives, and the future utility business model. Stakeholders provided feedback on the straw proposals, which then built a robust record from which the Public Service Commission (PSC) could issue guidance for future rate cases under REV. Roughly two years later, several utilities have filed or settled rate cases with new performance incentives and pilots for distributed energy resource integration in accordance with the Commission’s Track One and Two recommendations.
Quantifying existing incentives and historical performance
Rhode Island’s PST Report was also particularly useful for understanding the utility’s existing incentives and historical performance, something necessary to set reasonable, ambitious performance targets and compensate utilities for creating value.
The report began by summarizing what the authors and many stakeholders agreed was the basic incentive created by cost-of-service ratemaking.
“In the traditional regulatory model, electric utilities earn a return on investments based largely on . . . prudent capital investments. This model may exert a ‘capital bias’ on the utility to deploy capital-intensive solutions . . . . discourag[ing] the utility from seeking more efficient solutions [such as demand-side management] that do not depend on large capital investments.”
The PST report compliments this summary by quantifying and comparing the incentives already in place that attempt to fix perceived flaws with the utility business model. The comparison is facilitated by translating each program into equivalents of impact on net earnings, basis point adjustments to the regulated return on invested capital, and program expenditure.
The PST report also begins to catalogue performance by pointing out areas where it has been either poor or deteriorating. In particular, the report points out the peak-to-average demand ratio has steadily increased to 1.98, meaning nearly half of the utility’s capital investment is unused most of the time. It further attributes direct costs to meeting demand in the top one percent of hours, and benchmarks National Grid’s inefficiencies against other New England utilities.
These metrics and existing incentives can now be used in the rate case by stakeholders to help inform what metrics and incentives are most needed and valuable. For example, National Grid proposed a peak reduction incentive in its rate case; since the PST report helps quantify the value of reducing peak demand, stakeholders now have a sense of what benefits might accrue to customers to complement National Grid’s own assessment.
Another way to gather this information is by requiring utilities to publish scorecards for performance in key areas. For example, Illinois investor-owned utilities are required to report their performance on reliability and customer service over time in annual performance reports. Hawaiian Electric Companies are required to report over 30 performance metrics on the company website. And the Ontario Energy Board requires all its utilities to produce performance scorecards, which quickly compare performance against metrics set by the regulator.
Stakeholder education, record building through a formal report, and quantifying existing incentives and performance are a few strategies to help lay the foundation for remaking utility regulation. As these matters continue to proliferate around the country, the regulators and stakeholders who have taken some of these preemptive steps will be better prepared for an implementation phase, which could come as soon as the next rate case.
Thanks to Rich Sedano, David Littell, Leia Guccione, Rachel Gold, and Rolf Nordstrom for their helpful feedback on this piece. The article and any errors therein are solely the responsibility of America’s Power Plan.