3

Compensating Distributed Energy Resources: Markets, Equity, and Consumer Adoption Lenses

For the workshop’s second session, speakers and attendees turned to the question of how distributed energy resources (DERs) are or could be compensated to create appropriate incentives and sustainable financing for various stakeholders. Considering the role of consumers, grid operators, policy makers, markets, and regulation, participants discussed how different approaches to compensation may influence DER adoption and integration and the implications of different DER compensation models for energy equity, affordability, reliability, and resilience.

KEYNOTE ADDRESS

Susan Tierney, senior advisor, Analysis Group, discussed different viewpoints on DER economics, the factors influencing how different stakeholders determine the value of DERs, and approaches to compensating DERs. The many types of DERs have varying load generation rates that depend on multiple factors, such as cogeneration, demand-side factors, weather, and storage capabilities. DER compensation arrangements also depend on many factors, and these arrangements can have implications for equity and fairness, customer adoption, operational issues, and more.

Tierney noted that perceptions of the economics of DERs depend on one’s viewpoint—whether the host of the DER, the local utility, nonparticipating customers in the same service territory, vendors, and so forth. DERs can potentially provide a wide range of services, including providing electricity; avoiding certain attributes associated with

grid-supplied electricity, such as fees, investments, and local environmental impacts; and intangibles, such as avoiding emissions to help mitigate climate change even in the absence of a carbon price. These services have different implications and hold different values for various players. Among customers, those who host DERs may have different perceptions and reap different values from DERs than those who do not. Among utilities, those that are “wires-only” will have a different perspective than those that are vertically integrated. Regional transmission organizations (RTOs) and society at large also have different viewpoints and values. Thus, when considering investments in elements such as energy efficiency measures or residential rooftop solar installations, the perspective of a given stakeholder influences what DER services are of interest to them and the economic considerations related to those interests.

Tierney drew a distinction between three key concepts relevant to DER economics: value, benefit-cost, and compensation. “Value” refers to the worth or usefulness of a DER for one or more entities. “Benefit-cost” refers to whether the values extracted from a DER are worth the cost to achieve these values, from the perspective of a given entity. “Compensation” refers to the mechanisms and payments designed to reward a DER owner for services to the customer who hosts the system, to the grid for exports, and to others. Tierney noted that for most customers of grid-supplied power, electricity typically provides much greater value than its out-of-pocket cost (although there are some customers for whom electricity bills are high relative to their income and they need basic electricity service as a necessity of life). However, avoiding payments for grid-supplied power is only one of many factors that customers may consider when deciding whether to adopt DERs.

Compensation arrangements for consumers that host DERs directly impact energy equity, adoption, and grid operations. These arrangements vary widely depending on the jurisdiction involved and a utility’s and/or state’s approaches to net metering, net billing, and buy-all/sell-all arrangements; the size and characteristics of the DER technology and its eligibility for net metering or renewable portfolio credits; and the roles and responsibilities of the entity that is providing the compensation. Other important factors associated with compensation arrangements include the calculated value of solar energy; competitive procurements required to satisfy distribution system needs; the ability to participate in RTO markets; and the existence of other funding sources (e.g., tax incentives) outside of electric-service rates and payments.

Noting that long-standing, rate-making principles encourage setting prices based on marginal costs and discourage cost shifting, Tierney said that the value of DERs often depends on the underlying retail rate design and level, including the relationship to marginal and avoided

costs, whether there are fixed or demand-related charges, the extent to which fixed costs are recovered in variable rate elements, and the role of time of use pricing. She added that rate-making principles also encourage utilities to emphasize energy supplies with the lowest cost and comparable payments for comparable services, which can influence how a utility approaches different types of technologies, such as solar generation alone versus solar plus storage, utility-scale DERs, and resources that are contracted or those that are available on the wholesale market. How the costs are assigned to different players also matters. For example, it is important to consider whether costs related to interconnections, the underrecovery of utility fixed costs, or investments in incremental distribution system operations and controls are paid for by DER customers or the utility’s other customers.

DERs and their compensation arrangements may impact grid congestion in different ways in different places—for example, the grid capacity in a particular geographic area can influence the optimal amount of solar energy generation that can be accommodated without requiring grid upgrades. Given the wide variation in approaches, understanding of compensation arrangements and their implications can also be spotty. Tierney suggested a need to clarify different stakeholders’ responsibilities around DER compensation, timing, and delivery. She added that state and federal regulations—which are currently in a state of rapid change (see Figure 3-1)—also can be used to help to ensure energy equity and grid resilience, especially during outages.

PANEL PRESENTATIONS

Panelists described a variety of challenges and opportunities in achieving fair and effective compensation for DERs. Each panelist delivered opening remarks before engaging in a deeper discussion of key issues and possible solutions.

Valuing the Resilience and Reliability Benefits of Distributed Energy Resources

Anne Hoskins, senior vice president of policy and market development, Generac, a company that provides products to support residential energy generation and management and is actively acquiring DER companies to support energy generation, distribution, and storage more broadly. She posited that DERs have a critical role to play in enhancing grid resiliency, particularly in places that suffer from subpar grid performance or extreme weather events. For example, she highlighted the role of solar and batteries in restoring electricity to a fire station in Puerto

Rico after Hurricane Maria devastated the island’s central grid in 2017, leading to outages that lasted for many months. With outages continuing to challenge Puerto Rico, Generac has been selected by the Department of Energy to provide solar and battery systems for medically and geographically vulnerable residents in Puerto Rico.

Hoskins refuted the notion that DER compensation is bad for electrification, grid reliability, or grid resilience. Expressing her belief that consumer adoption of DERs will only continue to increase, she said that obstacles—both real and perceived—are increasingly being overcome as new technologies like solar-connected batteries and virtual power plants (VPPs) make it easier to store and share energy (Barbose et al. 2023). She suggested that fairly compensating DER-hosting customers and incentivizing them to share the power they generate can help make the grid not just more resilient and reliable, but also more equitable and effective.

Barriers to Realizing the Full Value of What Distributed Energy Resources Provide

Utopia Hill, chief executive officer, Reactivate, which develops renewable energy projects focused on enabling people in low-income or disadvantaged communities (LIDACs) and energy transition communities to access and benefit from the value that DERs can provide. She emphasized that DERs represent a plethora of opportunities for individuals, communities, utilities, and society more broadly. By providing a source of energy, they can not only offset energy demands on the whole but also do so in a way that is often closer to the point of use, potentially reducing the challenge of meeting energy demands in that location as well as the need for transmission system expansion. They can also lead to decreased emissions in some locations, as well as enhanced grid reliability and resilience.

Reactivate offers community solar farms, small utility-scale solar projects, onsite rooftop and carport solar projects, and other DER projects and has specific goals to increase renewable energy projects in LIDACs, deliver training and career development, and contract with minority or women-owned business enterprises. To meet these goals, Reactivate partners with local utilities to deploy distributed generation projects across the United States. Hill described some of the challenges the company has faced in establishing these partnerships. A key challenge is the sheer complexity of the more than 3,000 investor-owned utilities, cooperatives, and publicly owned utilities nationwide (with Hill noting the inability to find one map with all U.S. publicly owned utilities displayed). These entities create a complex, opaque, and sometimes illogical “black box” with regard to DER implementation and compensation, with varying pricing structures, requirements, DER valuations, and interconnection policies.

In one example, she said it was estimated that $80 million in upgrades would be required to support a 4-megawatt DER project. This clearly poses an economic barrier but also speaks to a larger issue in that the opaque nature of the system made it challenging to understand the factors that led to this estimation or how the project might be made more feasible. This lack of transparency in the policies related to DER deployment makes it extremely difficult to collaborate on integrated resource planning to ensure equitable access to renewable energy resources, Hill said.

Barriers to DER access and deployment create missed opportunities in the nation’s quest to ensure adequate, reliable, and resilient energy systems. Hill noted that it is estimated that DERs could meet one-third of the country’s energy capacity needs in the near future (Gledhill 2023). To accomplish this, however, she said that there is a need for significant improvements in policy transparency; appropriate incentives and penalties; and investment in people, resources, infrastructure, and technology, especially in LIDACs. For example, she suggested that incentives could be developed to encourage shareholder-driven, investor-owned utilities to make hosting capacity maps available or make institutional processes more transparent (or to penalize them if they do not). Hill also noted that a loan forgiveness program for distribution engineers could be an incentive to make more of these workers available. In addition, she said that further research is needed to elucidate the causes of outages and the role of infrastructure age, needs for network upgrades, and other barriers to DER access specifically in LIDACs.

Principles for Virtual Power Plant Development

Lauren Shwisberg, principal for carbon-free electricity, RMI, discussed how VPPs can contribute to DER integration along with the policy principles that can be used to support effective VPP development. Noting that DERs are expected to grow rapidly at the same time that electricity demand is rising, Shwisberg posited that new DER loads can represent either a benefit or a burden to the grid, depending on their compensation structure and flexibility. “A lot of these assets are existing on the grid, and all we need to do is be able to better leverage them to provide critical services,” she said, adding that, “we’re going to make our lives a lot harder in the next 5 years if we don’t figure out how to make much of this coming load as flexible as possible.” By effectively managing the mixture of energy sources with the necessary flexibility, DERs can help shape and slow the expected load growth while maintaining affordability, reliability, and critical services (DOE 2023).

One potential strategy to leverage DERs is the creation of VPPs, which are aggregations of grid-integrated DERs that can balance electrical loads

and provide utility-scale, utility-grade grid services (see Figure 3-2). Shwisberg said that VPPs can play a pivotal role in transitioning to a DER compensation platform that enables multiple revenue sources, and outlined 17 policy principles to enable VPP development and deployment (VP3 Regulatory and Policy Strategy Working Group 2024). The policy principles span five main areas: increasing the DER asset base, thoughtful

VPP design, fair and equitable compensation, seamless customer experience, and clearly defined utility and system operator roles. The three principles most relevant to DER compensation and maintaining reliability are enabling value stacking of multiple services to maximize benefits, utilizing best practices in price and program design in a transparent way, and supporting comprehensive utility planning and investment decisions. Enabling value stacking helps to address issues with valuing or compensating DERs and can help improve the cost-effectiveness of demand-side programs. Leveraging best practices from established, successful, and jurisdictionally relevant programs can help utilities and third parties share lessons learned, avoid common pitfalls, and reduce implementation costs when outlining VPP specifications. Last, supporting a comprehensive approach to utility planning and investment decisions can help to capture programmatic impacts and appropriately value the contributions of VPPs in planning, Shwisberg said.

Capturing Whole-System Impacts of Distributed Energy Resources

Juan Pablo Carvallo, research scientist in energy markets and policy, Lawrence Berkeley National Laboratory, discussed approaches to capturing the impacts of DERs via markets and regulation, along with modeling approaches that can help inform future planning. DER integration requires careful planning because it impacts the entire power system. DERs offer many benefits to energy generation, transmission, and distribution systems, as well as imposing technical and economic constraints and costs. However, Carvallo said that neither the benefits nor the constraints and costs are fully captured in system analyses. For instance, some processes may capture avoided costs to one part of the system without capturing what benefits, costs, or constraints are imposed in other parts of the system. This leads to significant knowledge gaps and missed opportunities and undermines the capability to create informed and appropriate compensation systems.

Broadly speaking, the value of DERs can be captured and compensated through market forces or through regulation. Market forces are effective when the product is well defined and can be bought and sold in a competitive marketplace. If key market attributes are missing, then regulation can be instrumental in defining the structures through which products are sold. Significant challenges have been encountered in both areas with regard to DERs, and to overcome these challenges will require new tools and planning models. One critical issue is that power system planners have historically drawn a hard line between the bulk power system side (encompassing long-term resource planning for power generation and transmission planning) and the distribution side

(encompassing distribution planning and demand-side management planning) (see Figure 3-3). Integrating DERs and designing effective compensation approaches requires a comprehensive approach spanning all of these facets, but Carvallo said that planning processes in most cases remain highly fragmented, hindering progress.

Planners in both the bulk power system and the distribution side are increasingly recognizing the need for new tools and more integrated resource planning, Carvallo said, but they have different and sometimes competing perspectives on value, costs, priorities, and beneficiaries. The high level of uncertainty in projections of future energy demands and DER deployment presents a further complication. Scenario-based approaches can help to some extent, but he noted that there is often wide variation in projections under different scenario assumptions for DERs. Furthermore, modeling resource adequacy often requires data and integration that is currently unobtainable.

Carvallo described two modeling approaches that can help planners adopt a more integrative approach. Sequential integrated modeling (SIM), which is currently used more by practitioners, is a bottom-up sequential input-output approach that captures one-directional impacts using industry-standard tools whose outcomes can be implemented into existing institutions. Comprehensive integrated modeling (CIM) is also a

bottom-up approach, but it is currently used more in academic contexts and focuses on optimization. CIM captures whole-system design but requires new tools and new institutions for implementation.

PANEL DISCUSSION

Annaswamy moderated a discussion among panelists that explored strategies for approaching DER value and compensation along with related issues including equity, societal expectations around resource sharing, defining and enabling resilience, and the role of VPPs.

Approaches to Calculating Value and Compensation of Distributed Energy Resources

Panelists discussed different approaches to calculating DER value to inform compensation arrangements. Carvallo stated that performing multiple assessments can help create a rigorous understanding of DER capacity, reliability, and resiliency. The models he mentioned, SIM and CIM, overlap with the four pillars mentioned earlier by van Welie for operational and investment scales. In Carvallo’s view, time is an especially critical element because it is not currently possible to incorporate DERs on an hourly basis. He posited that models that calculate the value of specific DERs with highly granular timing data, localized regulations, and market policy instruments can help inform compensation structures. Such instruments are possible to build, but will require significantly more research, especially into value stacking, fixed costs, investment requirements, and revenue predictions that can help to create more certainty for potential investors.

Annaswamy asked Hoskins, a former Maryland Public Service Commissioner, to discuss conflicting state and federal regulations for DER compensation, addressed by FERC Order No. 2222. Hoskins replied that balancing multiple regulations is possible, as some programs in New England are demonstrating. For example, collaborations between wholesale market leaders and utility commissioners can make it easier for utility companies and RTOs to balance their needs and recover their costs. However, she added that Order No. 2222 has been slow to take effect, does not reflect the full potential of DERs, requires complex and resource-intensive discussions for utilities and their consultants to navigate, and is not sufficient to create the needed changes.

In response to a question from Annaswamy, Hill stated that energy cooperatives, which serve only about 13 percent of the U.S. population, are not necessarily better equipped than investor-owned utilities to tackle DER compensation challenges. She noted that cooperatives are

already resource-constrained and need additional support to match the pace of DER deployment, and Tierney added that some cooperatives also have generation or transmission agreements that limit DER adoption.

Equity and Sharing

Shwisberg stated that equity must be core to the compensation discussion, especially the critical issue of how to design compensation arrangements that account for both private investment and public good. Tierney agreed that energy equity is a thorny issue, because the grid is not merely providing a paid service but also supporting how our entire society operates, including many truly critical services, and some communities will need more help than others in adopting DERs.

Hoskins stated that supporting critical services is a public policy purpose that is fundamentally different from providing energy for homes or businesses, noting that energy and electricity are now “critical human needs.” She suggested that this could be reflected in compensation arrangements, for example, by creating compensation structures that encourage a “sharing economy” approach where DER hosts are compensated for sharing power with neighbors during blackouts or other emergencies.

Hoskins added that the current rate system for recovering distribution upgrades is not equitable for low-volume power users or many low-income communities, who are often not first in line for grid upgrades. Some customers also receive upgrades sooner than others, making it easier for them to weather power crises.

Building on these points, Hill emphasized the need for a holistic approach to DER compensation that benefits the entire grid. For example, DER hosts who may not feel obligated to share the energy they generate could be incentivized to do so through fair compensation arrangements similar to Uber, Airbnb, and other sharing-economy platforms. Shwisberg stated that compensation arrangements could also be structured to penalize DER hosts who cannot provide a previously committed amount of energy when needed. Tierney added that it is important for any sharing obligations to be clearly enumerated in compensation contracts, which is not currently the case.

Carvallo added that appropriately compensating DERs creates reliability and resilience. He noted that there are multiple streams that can be tapped to create compensation arrangements that promote reliability and resilience, perhaps modeled on capacity markets that are practiced in incentivizing contributions.

Defining and Enabling Resilience

Annaswamy asked panelists to comment on how resilience should be defined in the context of this workshop. Carvallo responded that resilience cuts across four different levels—customer, community, utility, and societal—and is both more complex and more granular than the concept of system-wide reliability, which is an average that fails to fully reflect the poor service some customers receive. He suggested that a taxpayer-funded entity may be needed to bolster resilience across all four levels. Hoskins noted that DERs support resilience at the customer level through their ability to adapt to fast-changing conditions and provide flexible solutions. She said that it is important to research strategies to enhance system-wide resilience, but more granular, local resilience also deserves attention, as Carvallo noted. Shwisberg added that some utilities are trying to integrate resilience into their planning processes, and suggested that best practices will emerge for programs and prices that address resilience, customer value, and DER integration; capture more value stream; and are backed by robust planning.

Tierney defined resilience as the process of minimizing outages, responding to issues in real time, and recovering operations as quickly as possible, and learning from outages to improve responses to future events. She posited that while systems can be resilient (and/or reliable), individual technologies rarely are. Hoskins shared that Generac has developed a grid resilience program utilizing a smart thermostat that utilities can remotely signal for support as warranted during an emergency, instead of pleading with the public to conserve energy. While program participation will be optional, planners believe that enough individuals and businesses will participate to make a substantial difference in grid reliability. Shwisberg added that such resilience efforts could benefit from behavioral science insights to better understand and plan for the ways in which customers respond to events.

Hill emphasized that incorporating DER value and resilience across the grid cannot be overly reliant on adoption by wealthy households; community DER projects, which benefit more people, are also important. She urged a stronger emphasis on “carrots and sticks” to encourage customers to use their resources to benefit not only themselves but society more broadly. Hoskins agreed, adding that some states, such as New York and Connecticut, are experimenting with various models as they undergo grid modernization. She also noted that DER adoption is not always as concentrated in wealthy households as one might think. In California, for example, the middle-class Central Valley has seen the largest adoption rates for solar batteries, a trend that she suggested will only increase as technology costs go down and federal incentives continue to

be offered. These factors also apply to small businesses and multifamily households, which is important to emphasize when considering compensation arrangements.

The Role of Virtual Power Plants

Shwisberg elaborated on how VPPs can positively impact grid reliability. They are far more rapidly deployable than traditional power plants, demonstrating an ability to enroll thousands of households and more than 100 megawatts of capacity in mere months. They also support resiliency and reliability based on their ability to aggregate multiple assets and create backup energy sources, and they can lower energy bills and better position the grid to handle the coming load growth. However, she noted that unanticipated risks, such as cyber incidents or extreme weather events, could have unanticipated impacts. To inform planning, she said that it would be helpful to build out holistic risk assessments of the value and risk associated with various resources in certain scenarios.

Hill added that, as decentralized energy systems that can be deployed more rapidly than traditional power plants, VPPs will become even more impactful as electrification trends become more embedded in multiple aspects of our lives. A network of microgrids, for example, can be much more reliable and resilient than relying on a few large, centralized stations whose outages can cause disarray, as happened in Puerto Rico following Hurricane Maria.