The Regulator's Dilemma, Part 3

Virtual power plants (VPPs) are poised to revolutionize the power sector by orchestrating distributed energy resources (DERs) — like smart thermostats, household appliances, solar panels, batteries, and electric vehicles — into real-time networks of dispatchable capacity. The opportunity is especially significant for advanced VPPs, which aggregate multiple device types, are fully automated and optimized by price signals, provide multiple reliable grid services, are compensated on a pay-for-performance basis, and serve as a true supply-side resource.

Advanced VPPs can offer grid operators significant value by reducing stress on generation, transmission and distribution infrastructure at lower cost than conventional solutions like large-scale batteries, peaker plants, or additional poles and wires.

VPPs are already here. They are built on established technologies, and they hold great potential for significant market growth in the future. According to the U.S. Department of Energy, VPPs (including traditional demand response) serve approximately thirty to sixty gigawatts of peak demand.

However, that is only a fraction of their economic potential. Best estimates suggest that the VPP market could triple by 2030, serving eighty to one hundred sixty gigawatts of peak demand (or ten to twenty percent of the peak), and potentially even more beyond 2030.

So, the question arises: if VPPs are such a good solution, why aren't we seeing much faster deployment across North America today?

The answer lies in the fact that VPPs are hampered by several persistent market and regulatory barriers. These barriers include insufficient regulatory planning, misaligned financial incentives for utilities, inadequate mechanisms to stack benefits, and insufficient technology, communication, and consumer standards.

With the right policy and market development framework in place, regulators have an opportunity to accelerate the deployment of VPPs, improve grid reliability, reduce rate pressure on consumers, and make progress on decarbonization. This article explores these topics, describing best practices for utilities and regulators to consider in order to accelerate growth of VPPs.

Regulatory Planning for VPPs

Incorporating VPPs in regulatory planning processes, given the traditionally cautious approach utilities take when evaluating new technologies, is essential given the quickly evolving distribution system landscape.

There are particularly good opportunities for VPPs to be deployed as non-wires alternatives, enhance grid operations by improving efficiency, reduce costs, and enhance customer experiences. The planning and modeling processes in which VPPs can be valued include Integrated Resource Planning (IRP), generation planning, transmission and distribution planning, demand-side management (DSM), and resilience and reliability planning.

Neil Veilleux: Advanced VPPs can offer grid operators significant value by reducing stress on generation, transmission and distribution infrastructure at lower cost than conventional solutions like large-scale batteries, peaker plants, or additional poles and wires.

In some applications, VPPs can be evaluated as alternatives to traditional power generation in IRP modeling, helping to meet energy demand while lowering costs and emissions. In many instances, VPPs can also improve grid flexibility and reduce congestion, and importantly, they can provide these benefits in relatively short timelines (such as, VPPs can be deployed in months as opposed to the years-long timeline for peaker plants).

In the case of DSM, VPPs can provide load flexibility, enabling utilities to shift energy consumption and integrate renewable energy more effectively. Additionally, resilience and reliability planning can benefit from VPPs by optimizing distributed resources.

To ensure VPPs are considered, regulators can require that utilities include the technology in planning studies and consider appropriate compensation for value. These studies should assess the technical, economic, and market potential of VPPs compared to traditional solutions.

By comparing the advantages and disadvantages of VPPs with conventional grid infrastructure, regulators can make informed decisions, ensuring that ratepayers benefit from the most cost-effective and innovative energy solutions available.

Gisela Glandt: By improving the utility planning process, aligning utilities’ financial incentives, enabling stakeholders to stack benefits, and supporting standardization of communication and customer standards, regulators can help unlock VPPs as a powerful force in this energy transformation.

In Ontario, for example, utilities must evaluate non-wire solutions, including VPPs, for any grid project over two million dollars. In Ameren Illinois' service area, residential customers are partnering directly with third-party aggregators, and earning financial incentives for their participation, to help mitigate capacity shortages and rising energy costs. Commonwealth Edison in Illinois and Xcel in Colorado are considering similar opportunities in response to regulatory encouragement.

Integrating VPPs into the planning process requires regulators and grid planners to carefully evaluate appropriate applications, a crucial first step in building confidence in the technology.

Utility program managers will, for example, commonly launch a small-scale VPP program, collaborating closely with grid operators to test its effectiveness. With successful results, the utility can scale up those efforts, supported by further investments in an advanced distribution management system (ADMS) and other grid-modernization technologies.

Regulators may ultimately create demand flexibility standards, which establish VPP capacity minimums (set as a percentage of peak load). In California, plans are being made to introduce flexible demand standards for various household appliances with the goal of aligning appliance usage with lower electricity rates, especially during periods of high renewable energy generation. Standards are also being developed for electric vehicle chargers and battery storage systems with the goal to achieve seven gigawatts of load flexibility by 2030.

Financial Incentives for Utilities

Brien Sheahan: Incorporating VPPs in regulatory planning processes, given the traditionally cautious approach utilities take when evaluating new technologies, is essential given the quickly evolving distribution system landscape.

To accelerate growth of VPPs, regulators should consider aligning the value of consumer participation with the financial interests of utilities and overall system benefits. In today's regulatory environment there is a significant mismatch between the financial interests of utilities and benefits created by VPPs. Remedying this challenge will be necessary to enable widespread adoption of VPPs.

Financial alignment with utilities is necessary to scale all types of VPP business models. This includes, for example, utility-administered VPPs where the utility directly partners with an aggregator to co-brand, market, monetize DER assets, and unlock consumer benefit. It also includes third-party aggregators that offer direct-to-consumer products and independently bid aggregated capacity into the wholesale market.

In the former case, the utility is the key business partner responsible for designing the program, engaging customers through utility-branded marketing efforts, calling events, bidding capacity into wholesale markets, and compensating aggregators.

In the latter case, the aggregator is responsible for designing, managing, and orchestrating the program; however, the utility remains a critical partner providing access to meter data needed to facilitate settlement of wholesale VPP transactions. In all cases, utility partnership is essential if the aggregator seeks to monetize distribution-level value of the VPP.

Brian Kooiman: In today’s regulatory environment there is a significant mismatch between the financial interests of utilities and benefits created by VPPs. Remedying this challenge will be necessary to enable widespread adoption of VPPs.

To incentivize utilities, it is necessary for regulators to create a mechanism that aligns a utility's financial interests with the implementation of new technology and customer benefit. One way to achieve this alignment is through performance-based ratemaking, which allows the utility to earn by achieving certain performance targets. States such as California, Hawaii, Illinois, Minnesota, and New York incentivize electric utilities in this way.

Performance-based rates (PBR) can effectively incentivize utilities to invest in new technologies like VPPs while providing tangible benefits to ratepayers. Under PBR, utilities are rewarded based on achieving specific performance targets, such as improving grid efficiency, reducing costs, or enhancing service reliability.

By adopting VPPs, utilities can optimize energy distribution, integrate more renewable energy, and better manage peak demand, all of which contribute to achieving these performance goals. The efficiency gains from VPPs can lower operational costs, which, in turn, can lead to lower rates or slower rate increases for consumers. Moreover, VPPs can enhance grid resilience and flexibility, improving service quality and reliability for ratepayers, while driving the utility toward a more sustainable and cost-effective energy future.

Another approach could be to allow the capitalization of VPP software and associated implementation costs. Allowing the capitalization of intangible software assets for technologies like VPPs can benefit both utilities and ratepayers by accelerating the adoption of innovative grid management tools.

By capitalizing these software investments, utilities can spread the costs over time, making it more financially viable to deploy advanced technologies. This can lower operational costs for utilities, leading to reduced rates for consumers.

Additionally, a more efficient grid can reduce strain during peak demand and lower overall energy costs for ratepayers. Updates to accounting rules over the years have made capital investments in software more financially viable for utilities, and States like New York, Pennsylvania, and Arkansas allow the capitalization of certain software assets.

Aligning the financial incentives of utilities with the deployment of VPPs is crucial for accelerating their growth and realizing their full potential. By implementing mechanisms like performance-based rates and the capitalization of software, regulators can create the financial motivation utilities need to invest in these advanced technologies.

This approach not only benefits utilities by making investments in VPPs more financially feasible, but also brings significant advantages to ratepayers through enhanced grid efficiency, lower costs, and improved reliability. As more states enact these regulatory frameworks, the widespread adoption of VPPs will play a pivotal role in creating a more resilient, cost-effective, and sustainable energy future.

Mechanisms to Stack Benefits for VPPs

The power of VPPs is that their unique characteristics enable a host of benefits beyond those of a traditional power plant. The demand response capabilities alone of VPPs yield a spectrum of service types, described by Lawrence Berkeley National Lab (LBNL) as "Shape, Shed, Shift and Shimmy."

Practically, these service types indicate that demand response within VPPs support energy efficiency, permanent load shift, capacity and resource adequacy, and real-time energy including ancillary services. In its VPP Liftoff Report, the DOE further differentiates the non-energy benefits of VPPs, including deferring grid capex expenditures with T&D infrastructure relief, providing reliability and resilience, supporting decarbonization, and reducing local air pollution, and community empowerment alongside job creation.

However, there is also a tendency within the industry to try and make an apples-to-apples comparison between resource types. In doing so, modeling of VPP value often leaves the non-energy benefits out of the equation. This risks significantly undervaluing the VPP resource.

In a recent Brattle report on "The Value of Virtual Power," Brattle demonstrates that stacking the VPP benefits of emissions, resilience, distribution, transmission, ancillary services, energy against capital, and operating costs leads to a twenty times improvement on net costs over a traditional gas peaker. Furthermore, VPPs can have an even greater value proposition when considering additional soft benefits afforded to ratepayers through incentives, faster time to capacity, and customer engagement.

To continue and grow the market for VPPs, the full value of VPPs needs to be realized by aggregators and their customers, in a way that also is aligned with the utility incentives as both an operator of the distribution system and a retailer.

First, regulators can develop cost tests that capture the stacked value of VPPs. Cost tests are not typically designed to consider the full suite of tertiary benefits such as distribution deferral, local air pollution, or community empowerment. While these may be harder to quantify, the associated benefits are real and thus need to be considered, especially if VPPs are being compared against traditional power plants that do not have these same benefits.

Second, regulators can help utilities and aggregators capture wholesale market value — for those in a wholesale market — by making it easier to participate through reasonable and simplified customer enrollment processes. There is a risk of over-regulation in setting high thresholds for customer participation. One particularly acute example is rules around dual participation in both wholesale programs and retail programs. Customers should be able to participate in the program of their choice as long as they are not getting compensated twice for the same load modification.

Third, regulators can build out more defined markets for distribution value. While we are likely years or decades away from a utility Distribution System Operator model, establishing first steps toward this kind of paradigm would create incremental, interim value for VPPs. As one example, the New York utilities run demand response programs for distribution support in tandem with New York ISO programs for capacity support. Aggregators are able to enroll their resources in both, capturing the broader suite of VPP value.

Technology, Communication and Consumer Standards

VPPs manage data across interconnected and complex systems (from the local scale to the community, regional and international scale) to create value for customers, grids, markets, and the environment. To operate efficiently, VPPs require a common set of data and communication protocols. Creating interoperable and seamless data flows between devices, aggregators, consumers, VPP platforms, utilities, and grid systems has the potential to substantially lower transaction costs for VPP deployments.

In fact, in 2021, the National Institute for Standards and Technology (NIST) issued its report "NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 4.0." NIST notes that as society continues to deploy DERs and modernize how we produce, manage, and consume electricity, strategies for system operations and economic structure will diversify.

This diversification will benefit from — and eventually rely upon — enhanced interoperability.

The benefits of interoperability are well-known. Interoperability serves as a hedge against technology obsolescence, maximizes the value of equipment investments by increasing usage for secondary purposes, and facilitates combinatorial innovation by allowing coordinated small actions across diverse stakeholders and devices to have grand impacts.

For example, DER users benefit from interoperability by increasing access to information that improves their energy decisions; increasing opportunities to value stack across the end-use, distribution, and transmission systems; and increasing customer choice.

However, interoperable data and communication protocols for DERs are only partially in effect today, resulting in unnecessary cost (and, in some cases, confusion) across stakeholders — including customers, aggregators, utilities, and market operators — that engage with VPPs.

To address these challenges, regulators could work with utilities and industry to accelerate the deployment of interoperability standards in their states. There are a range of issues that regulators could focus on in the near-term.

First, consistent customer enrollment and registration standards are needed. This includes automatic enrollment of DERs into VPPs with opt-out and interoperability of DER software.

Next, data access standards should be standardized, especially utility meter data access protocols. It is in many cases unnecessarily challenging for industry leaders to access the meter data needed to facilitate market transactions.

Third, open-access device communication standards are critical for scalability. Here, regulators and utilities could encourage development of open standards for APIs to increase interoperability, promote customer choice, and ensure the smoothest customer experience. IEEE 2030.5 and OpenADR 3.0, for example, are two key standards in the U.S. and internationally that are rapidly growing in adoption due to California legislation and well positioned for enabling this goal.

Finally, performance, forecasting, measurement and verification could be standardized across utilities and regions. Specifically, these standards ought to build upon operational standards of distribution systems, guiding development of VPP standards in areas like system reliability, DER interconnection, energy data sharing, product certification, and cybersecurity.

Conclusion

If deployed at scale, VPPs can help facilitate a transformative shift in the power sector, offering consumers and utilities more affordable, reliable, and sustainable solutions for managing energy demand and supply.

Regulators in particular have an important role in facilitating the creation of regulatory frameworks that address persistent barriers to VPP growth. By improving the utility planning process, aligning utilities' financial incentives, enabling stakeholders to stack benefits, and supporting standardization of communication and customer standards, regulators can help unlock VPPs as a powerful force in this energy transformation.