At the Western Conference of Public Service Commissioners (WCPSC) held last month, Grace Relf, Chief of Policy and Research at the Hawaii Public Utilities Commission, suggested that Hawaii’s approach to energy regulation is so advanced that it’s like “sending a postcard from the future.” In truth, several states, in addition to Hawaii, recognize that the grid of the future is possible today. Technological and regulatory momentum, as well as market drivers associated with achieving customer and grid operator benefits, have helped states build the case to move grid modernization forward faster.
As Gene Rodrigues, Assistant Secretary of Energy at the Department of Energy, shaped for the WCPSC audience, the existing energy system was built on 19th-century engineering principles. As engineering and uses of the system have advanced, so too must the system itself as well as the regulatory frameworks that were created to support it.
Across the conference, there were three standout measures of evolution from an antiquated to a modern electric grid:
- Utilities must be encouraged to implement and use grid-edge technology;
- there must be a focus on outcomes in ratemaking; and
- planning for risks and resources on the electric grid is crucial.
The power of grid-edge technology
Grid-edge technology is foundational for grid modernization. By virtue of sitting at the edge, it can help to build a more holistic view of what is happening – whether inside of a customer’s home or at local levels of the distribution system (or both). The most cost-effective means of integrating grid-edge technology is through the electric meter. The latest generation of smart meters, sometimes referred to as AMI 2.0, have embedded software to sample high-resolution data at more than 1 MHz per second and can process and analyze the data from the meter all from the edge. This enables real-time presentment of insights to both consumers and utilities. National Grid is implementing the latest generation of smart meters in both its New York and Massachusetts electric territories, Rhode Island Energy and Southern California Edison each have presented plans to their respective regulators to upgrade to AMI 2.0, and Connecticut regulators are expected to issue a decision on statewide AMI as part of the Equitable Modern Grid Initiative.
Evolving the approach to ratemaking
The nation’s regulatory constructs developed as the energy system grew, but those rules no longer meet the moment. A different model is needed to incentivize utilities to make the right investments in grid modernization. Outcome-based regulation is one such concept. States like Hawaii, Connecticut, and Minnesota have adopted performance-based regulation (PBR), wherein performance incentives replace predetermined returns on investments and give utilities flexibility in achieving benefits for customers. Other states, like California and New York, use shareholder incentives to reward utilities for achieving set outcomes in specific areas like demand management portfolios, but have not fully adopted outcome-based regulation.
This evolution of the regulatory model not only aligns utility shareholder, customer, and regulator interests, but it also gives third parties quantifiable targets for both the solutions and outcomes they provide. This type of clear market signal is especially important as AMI and other grid-edge technologies leverage third party applications for achieving benefits for customers and the grid. Once new smart meters are deployed, states can encourage utilities to activate their grid-edge capabilities by aligning metrics to the achievement of customer and grid benefits relied on in the cost-benefit analysis of AMI 2.0 proposals.
Getting ahead of risk and planning for the right resources
The success of grid-edge technology and outcome-based metrics relies on a renewed approach to distribution system planning. Rewiring America’s Keishaa Austin was met with aggressive head-nodding as she shared this sentimenht with the WCPSC audience. Austin suggested that planning ensures a practical approach to electrification, where resources being added to the system are known and accounted for ahead of being integrated in an effort to maintain the integrity of grid operations.
Managing the distributed energy resources and electrification loads means getting better at finding where these resources are being plugged in and understanding their flexibilities – something that grid-edge technology can provide. Further, planning for increasingly-common extreme weather events – wildfires in the west, hurricanes in the south, and heavy snow events in the north and east – is also critical for a modern distribution system. Knowing which resources and geographies are most vulnerable and planning for outages and reinforcements of the system ahead of such events can become an outcome-based metric used by regulators to hold utilities accountable for reliability. Whether managing new resources or mitigating risks, planning is the core utility function that operationalizes the modern grid.
Implementing each of these measures requires vision and commitment. Not implementing the right metering technology today, for example, can put a state 15-20 years behind as it waits for another cycle of the meter’s useful life to pass. Having the right technology in place but not aligning ratemaking metrics to using it risks not achieving the benefits that customers are paying for. And not integrating these tools and outcomes into the planning process risks having the distribution system out of balance from one utility to the next. The transition to a decarbonized, modern grid is anything but a vacation – but for those states that are slow to embark on the journey, the postcard from the future simply reads: “wish you were here.”