What needs to be accomplished between now and market go-live falls into two broad categories. On the one hand, regions do have line of sight to resolving the mechanisms needed to facilitate the participation of DER aggregations in compliance with FERC’s rule. These represent the tactical steps needed to get to go-live, and while there is still work to be done, there is a level of clarity on what next steps look like and what constitutes success. For example, each ISO/RTO has described elements such as the DER aggregation registration process, interactions with existing interconnection study procedures regarding the 60-day safety and reliability review, possible conflicts with respect to FERC Order 745 implementation, and operational coordination with distribution utilities.
However, there is a second set of issues that remain largely unanswered. Each of the three items described below could significantly shape the level of DER participation and their resolution could vary substantially across markets, states, and utilities:
- Dual participation mechanisms: Rules that clarify the simultaneous participation of DERs and aggregations in wholesale markets and distribution system services and/or customer applications will be critical. While participation in established wholesale markets is attractive, it is often not the primary use case that distributed resources serve. To the extent that DER are already participating as a distribution asset (such as a non-wires solution) or participating in a retail tariff or utility program, the rules to facilitate participation in wholesale markets often remain unclear. These have begun to be addressed in jurisdictions such as New York and California, but significant clarity is still needed in many regions to provide rules for DER to participate in wholesale markets while providing distribution services and meeting customer needs.
- The geographic span of aggregations: To participate in wholesale electric markets, DER aggregations must be sized at 100 kW or above. Aggregations can be spread across pricing nodes, or be restricted to a single pricing node, depending on the respective ISO/RTO’s initial proposals. Customer acquisition continues to be a significant challenge and the number of resources an aggregator can draw from to reach the 100-kW threshold for market participation will depend on whether an aggregation can be multi-nodal or not. This factor could in turn shape the business case and opportunity space for aggregators. Approaches to establish the geographic span of aggregations have varied across regions (for example, node mapping methods in New York vs. the use of Distribution Factors and Sub-Load Aggregation Points in California) and we are likely to see additional flavors emerge as other markets finalize their rules.
- Metering and market settlement and reconciliation: As regions prepare for DER participation, it will be essential to ensure that utility systems can use different billing determinants for supply and delivery on retail and wholesale tariffs so that they can be separately treated. For example, it will be key to ensure that wholesale supply from a customer remains distinct from retail service to that customer. This also means that utility back-office systems will need to be able to capture sub-metering data. Where customers do not already have parallel metering configurations, alternate arrangements will need to be identified and harmonized with existing practices (e.g., for storage metering under FERC Order 841) which could represent significant barriers to implementation.
The regions will need to address these issues as markets prepare for their respective go-live dates. The shape of their resolution could impact the ability of aggregators to acquire sufficient resources to meet resource size thresholds, the opportunity cost of market participation vis-a-vis customer or distribution services, and the infrastructure hurdles that must be addressed to ensure that resources are compensated appropriately.
The longer-term view for DER aggregations
While these represent some of the pressing near-term questions that will define the scale of resource participation prior to go-live, other critical issues will shape the long-term trajectories of future DER market participation:
- Evolving markets, evolving value: While many of the conversations to date have focused on participation in real-time energy and ancillary services products, it is still an open question as to whether this is where DER can provide the most value to the system, especially as operating reserve markets saturate and interest increases in developing market services for emerging attributes such as resilience and flexibility. In addition, while there has been interest in capturing DER contribution to planning reserves, calculating the resource adequacy (RA) contribution (e.g., effective load carrying capability) of heterogeneous aggregations remains a challenge, especially as new constructs for RA emerge. This means it will be necessary to not only navigate the impacts on market participation from rules such as must-offer requirements (see here and here), but to also anticipate the value that DER provide in these contexts as market designs continue to evolve. This will in turn define the scope and scale of the revenue opportunity that DER could capture as these markets develop.
- Capturing the full cost of entry: Although FERC Order 2222 seeks to remove the barriers to market participation of DER, the details of the costs for that participation are still yet to be determined and many of the key decisions will fall to the states. In New York and beyond, discussions have focused on near-term cost barriers such as telemetry requirements. While these costs will have a significant impact, this is only part of the picture. For example, since Order 2222 calls on regions “to apply any existing resource non-performance penalties to a distributed energy resource aggregation when the aggregation does not perform because a distribution utility overrides the RTO’s/ISO’s dispatch,” it could fall to state-jurisdictional interconnection rules to determine the system upgrades needed to ensure an injecting resource’s deliverability. DER interconnection studies typically focus on ensuring safe and reliable operation under system normal conditions. Changing the scope of these rules to enable DER deliverability under a broader range of system operating conditions could have considerable long-term implications for market participation. Alternatively, flexible interconnection frameworks could enable active network management to reduce system upgrade costs. However, this could require additional operational control and coordination to enable the distribution utility to evaluate DER dispatch schedules and identify constraints (see Figure 2, adapted from this report). This also introduces increasing curtailment risk for market participants as the frequency of constraints rises. Utilities will likely pursue a combination of these approaches, and their interactions will have a material impact on the full cost of DER market participation.
- Opportunity cost: The value proposition for participation will depend on not only the available revenue opportunities and the cost of participation, but also the value of other revenue streams foregone as a result of wholesale participation. There has been some discussion of retail tariff interactions such as the exclusion of net energy metered resources. However, the range and scope of these interaction effects could evolve over time as other sources of revenue emerge. For example, applications for local resilience (e.g., community microgrids), distribution services, and participation in customer programs or other evolving customer management approaches could preclude market participation either because of limitations in the dual participation rules mentioned above or limitations imposed by these other applications. The evolution of these services and their interactions with wholesale market designs will shape the willingness to take on the costs needed to participate in ISO/RTO markets and could have as much effect as the wholesale market rules themselves in shaping the future impact of FERC Order 2222.
The industry is on the precipice of what could be a dramatically impactful change in market rules governing participation of DER. The regions have made great progress, but important questions remain will determine whether FERC Order 2222 can provide an effective on-ramp for DER market participation. In the near term, there are practical matters around the rules that govern dual participation, the size of pricing nodes, the associated geographical span of aggregations, and market settlement and reconciliation. These factors will help establish the rules of the road, but the direction that road takes will be a function of how DER fit within the future evolution of markets, the costs and risks of participation, and the changing landscape of competing revenue opportunities. Even if FERC Order 2222 doesn’t lead to significant participation by DER in wholesale markets, addressing these items could be a helpful detour that identifies the pathways for DER to serve distribution grid services and customer needs. There are likely to be twists and turns along the way, but how these issues unfold will be useful guideposts as to where FERC Order 2222 ultimately takes us.